The Maryland Climate Change Commission’s Mitigation Working Group began a steep climb April 19 when it met for the first time following the enactment of the state’s Climate Solutions Now Act (SB 0528).
Maryland Gov. Larry Hogan (R) allowed the bill to become law April 8 without his signature, along with HB 0740, which requires Maryland’s State Retirement and Pension System to incorporate climate risk into its investment evaluations. (See Md. Climate Bills Become Law Without Hogan’s Signature.)
The Climate Solutions Now Act resets the state’s emissions-reduction goals to 60% below 2006 levels by 2031 and net zero by 2045. That’s half again as large as the goal set in the 2016 Maryland Greenhouse Gas Reduction Act (GGRA), which mandated a 40% reduction in emissions from 2006 levels by 2030.
The commission is charged with advising the Maryland Department of the Environment (MDE), the governor and the General Assembly on the dramatic greenhouse gas reductions the new law requires. The bill “requires MDE to publish a draft 2031 plan in approximately 14 months from now,” said Mark Stewart, climate change program manager at MDE. “That means that we will have to draft a plan that’s ready to circulate with state agencies and the governor’s office next spring, soon after a new administration is in place.”
The Mitigation Working Group Steering Committee will “map out a work plan” for creating the draft by September, Stewart said.
Closing the gap between the GGRA plan and the tougher 2031 target “within the next eight years will not be easy,” he said.
A Need for More Nuclear Power?
Commission member Sandy Hertz, director of the Office of Climate Change Resilience and Adaptation in the Maryland Department of Transportation, said that while she isn’t in favor of nuclear power, it could be hard to reach the 2031 target “if we don’t have something like that, that has a much larger output than what we have right now in terms of clean and renewable or low-carbon energy sources.”
“We don’t have hydroelectric,” she said. “We don’t have geothermal everywhere in Maryland. So I’m just wondering … how do [we] get 70% of the [power] to be that [low-carbon] source if it’s not necessarily available?”
Maryland’s only nuclear power plant, the Calvert Cliffs power station, accounted for 41% of the state’s net electricity generation in 2020, according to the Energy Information Administration. About 11% of the state’s electricity generation came from renewables in the same year, EIA says. About three-quarters of the renewable energy consumed in Maryland is imported, according to state officials.
Curbing Building Emissions
Getting buildings to net zero carbon emissions is another of the enormous challenges set by the Climate Solutions Now Act. During the amendment process, provisions that would have required emissions-reduction targets for large commercial buildings and multifamily dwellings were cut, from 50% to 20% in 2030, and a net-zero target for 2035 was eliminated. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)
Mel Litter, CEO of Elemental Impact Solutions, noted the law’s requirement that buildings 35,000 square feet and larger have zero direct emissions by 2040 would cover a planned 80,000-square-foot innovation incubator. She wanted to know if there is a list of architects who could design the building to meet those requirements. Stewart said there is not, but the U.S. Green Building Council has a directory of architects and other professionals with LEED (Leadership in Energy and Environmental Design) credentials. [Editor’s note: An earlier version of this article incorrectly described Litter as a member of the climate change commission.]
The new law also includes an assumption that federal funding will be available to help electric utilities transition to carbon-neutral energy production and pushes them to apply for such monies. But federal funding might not be available in the future, said Kim Coble of the Maryland League of Conservation Voters, commission co-chair. If federal money dries up, “this is going to get a lot more difficult to do,” she said.
New Working Groups Created
SB 0528 also requires MDE to provide staffing for four newly created Climate Change Commission working groups, which were tasked with providing reports to the commission and legislature by the end of 2023:
The Just Transition Employment and Retraining Working Group is charged with providing a report on the number of jobs created to counter climate impacts; the projected inventory of jobs needed and skills and training required; workforce disruption due to community changes caused by the transition to a low-carbon economy; and strategies to target workforce development and job creation in communities historically impacted by carbon polluters.
The Energy Industry Revitalization Working Group will conduct a study of the impacts of transitioning to renewable energy, including the number of small businesses impacted by the transition; the costs and economic impact of the transition; and an analysis on the impact of generating facilities that may close because of the transition.
The Energy Resilience and Efficiency Working Group will report on methods to increase grid security and encourage electricity storage technology research; potential electric grid distribution transformation projects; the potential to develop clean energy resources on previously developed project sites; and the lifespan and viability of energy facilities in the state that do not emit GHGs.
The Solar Photovoltaic Systems Recovery, Reuse and Recycling Working Group will focus on the recycling, disposal and decommissioning of solar PV systems and must recommend financing mechanisms to support a circular economy approach.
Market Participants Frustrated with ERCOT’s Market Redesign
HOUSTON — The Gulf Coast Power Association drew more than 400 attendees to its first in-person Spring Conference, and 35th overall, since 2019 and “that thing,” as GCPA President Mark Dreyfus referred to the COVID-19 pandemic.
A pair of panels discussing regulatory and market changes since the February 2021 winter storm brought the ERCOT grid within minutes of a total collapse kicked things off. Panelists expressed frustration with the pace of change and the uncertainties of future market designs.
Michele Richmond, executive director of lobbying group Texas Competitive Power Advocates (TCPA), said her members want to be compensated for the weatherization requirements and other obligations that have been placed on them.
“We focused on reliability, which was good early on for many years, but what we’ve seen is a shift to command and control,” she said. “There’s an unwillingness to let the market commit resources. We’ve seen a lot of mandates placed on generators, which we understand in terms of winterization and resiliency, but that is largely uncompensated so far.”
Richmond called for a reliability standard, saying ERCOT’s conservative approach to operations and heavy use of reliability unit commitments “have not done anything to incentivize new investment in ERCOT’s dispatchable fleet.”
“That hasn’t done anything to incentivize existing resources, many of which are marginal,” she said. “When the wind’s not blowing and the sun not’s shining, you definitely want my members to turn on. The economics for gas plants don’t work. No one wants to lend you money to do that. Until we have a market that allows full recovery on dispatchable generation costs, we’ll continue to see problems.”
Bryan Sams, Calpine’s executive vice president of governmental regulations, said the Texas Public Utility Commission’s lowering of the operating reserve demand curve’s system cap from $9,000/kWh to $5,000/kWh has been among several changes that have sent a dampening signal to the market and is taking money out of it.
WattBridge’s Tina Lee agreed, saying, “We haven’t seen the price impacts ripple through the market. For generators, we think the market signals have been muted, not only by ERCOT’s conservative operations approach, but the other revenue channels’ dispatchable generation needs. You want to incent new generation, not keep older generation around.”
“Historically, in an energy-only market, all revenue comes from the market itself and a small portion from ancillary services,” AB Power Advisors’ Matthew Berend said. “Now, we’ve gone to an approach where there’s more value in a smaller part of the market. That doesn’t necessarily translate into more thermal generation being built.”
Last December, the PUC suggested several market designs to be evaluated for the ERCOT market’s second phase of restructuring. Commission Chair Peter Lake asked staff to focus on a backstop reliability service proposal first and then a load-side reliability mechanism that some have likened to a capacity market — a four-letter word in Texas. (See PUC Forges Ahead with ERCOT Market Redesign.)
“All of them have their challenges, and there’s no silver bullet,” Berend said.
“If you’re going to use the ‘c’ word [‘capacity’], you may as well belly up to the bar and say we need a capacity market,” ENGIE’s Bob Helton said.
Jones: Will Stay as Interim CEO
Interim ERCOT CEO Brad Jones declined to use prepared remarks in addressing attendees, opening himself up to questions, but with a catch: only two-word questions.
“Retirement plans?” he was asked.
“Soon. Soon. Very soon,” Jones said. “I have committed to the state, to the PUC, to politicians and others that I will be here as long as they need me, but only as interim CEO. I want to ensure they get that right person into this role.”
Since Jones was chosen to lead ERCOT last April, his retirement plans have slipped from the fall to April, and now to June. According to industry insiders, the grid operator’s Board of Directors has been looking at five to 18 candidates but is having trouble finding someone to fill what has become a political position. (See ERCOT Board Chooses Jones as Interim CEO.)
Responding to the one single-word question he received (“Cryptos?”), Jones said cryptocurrency and Bitcoin miners present a “fantastic” resource to the grid operator. He said the large, energy-intensive data farms used to solve the complex calculations that yield Bitcoin are “very price-responsive” and have the ability to quickly shut down operations, making them effective in balancing supply and demand.
Jones said one crypto load near ERCOT’s control center in Taylor has about 700 MW of load, about half of Austin’s average load. He said when he asked one legislator to imagine half of Austin — one of the deep-blue urban areas in an otherwise red state — disappearing from the grid, the lawmaker cracked, “Wow! That would be pretty cool.”
“We need to work with these folks to bring them in,” said Jones, who is expecting ERCOT’s current crypto load of 1.5 GW to reach 5 GW in two years. “I see that as a positive, but we’ve got to think about some policy issues.”
Jones was unable to provide an answer to “2032 peak?” But he offered a 2022 number: 80 GW. That would shatter ERCOT’s record peak demand of 74.7 GW, set in 2019.
“I believe we have the resources to meet that kind of load. I’m excited about that,” Jones said. He cited the “extraordinary growth” in renewables — 15 to 18 GW in a year — in pushing ERCOT’s renewable capacity to 44 GW.
“As we speak, we expect to have about 28 GW of production from our wind generation,” he said. “California bragged about 18 GW of wind the other day. … Let’s show them our numbers.”
MPs Ask for Continued Stakeholder Involvement
Several panelists brought up their concerns with ERCOT’s stakeholder process, in which the Technical Advisory Committee endorses system changes and market rules before they go to the board.
The new board, completely changed since last year’s storm, has created a Reliability and Markets Committee that some market participants worry will take them out of the governance process.
“The stakeholder process forces collaboration and improves outcomes,” TCPA’s Richmond said. “Our members are experts in running power plants, but not transmission and distribution utilities. Something is missed if you don’t have expertise from other [market] segments. It’s sometimes a messy process, and sometimes we argue … but the outcomes tend to be better. It’s more thought out when you conduct it that way.”
Pedernales Electric Cooperative CEO Julie Parsley, noting she served on the board for all of five months before it was essentially disbanded after the winter storm — “A little coincidental, isn’t it?” she remarked — said market participants need to be involved at the board level.
“There’s a non-electric industry view that market participants being a part of the market process is the fox guarding the henhouse,” she said. “Nothing could be farther from the truth. It’s checks and balances. No one’s going to let anybody rob the henhouse, because we’ll see that. I hope we can maintain that stakeholder interest. When you’re working in the market, you see the functionality of the market.”
“The stakeholder process has always been key. It’s made this market,” ENGIE’s Helton said. “You’re not going to invest if you don’t have a voice and your access. I hope we keep going down a path of strong stakeholder involvement.”
“That puts us all in a tough environment. I can’t tell you where the board will be, but there’s a strong belief in the value of the stakeholder process,” Jones said. “That’s my prediction. It’s just a matter of getting that board into a place of comfort.”
Jones also addressed outage scheduling, “the hot issue of today.” He said the outage windows have become shorter, and with the increase of renewables in the market, the spring and fall shoulder months are also having trouble. On April 18, TAC unanimously rejected an ERCOT-drafted rule that would have complied with 2021 legislation to give the grid operator total control over approving or denying maintenance outages. (See ERCOT Technical Advisory Committee Briefs: April 13, 2022.)
“The discussion in the last several weeks, months in fact, is how many outages can we accept. How many megawatts can we take offline,” he said. “The legislature gave us the ability to approve or deny all generation outages, which leaves all generators in a concerning spot.
“That discussion leaves us at odds on some issues,” Jones said. “ERCOT wants to hold as much control as possible over that, while generators want to control as much as possible, but I believe we’ll get there.”
Brouillette Stresses Energy Balance
Former U.S. Energy Secretary Dan Brouillette, now president of Sempra Infrastructure, said the world is seeing a rebalancing of the energy equation, not just in Europe with Russia’s invasion of Ukraine, but across the globe.
He said he spent much of his time in Europe during the Trump administration warning Germany and other countries that they were too dependent on Russian gas.
“We could see what the ultimate goal was on the part of Russia. We recognize now that those admonitions of three to four years ago were correct,” Brouillette said. “Environmental security is very important, but also important is economic security and financial security. You have to balance all three, or else you’ll be in the position Germany is today.”
Asked why the U.S. and its allies haven’t been able to replace the gas coming from Russia, Brouillette said, “We can’t simply snap our fingers and create the enormous facilities to produce natural gas. … We’re going to be somewhat dependent on Russian gas. I just don’t see how we replace that amount of gas in such a short time.”
He said energy transition’s historical arc has always been from less energy to more energy; from less dense energy like wood and biomass, to more dense sources like nuclear power.
“As it gets more dense, it gets cheaper and meets more needs. To grow economies, you need more energy,” Brouillette said. “Whale oil is the only source we’ve taken out of the energy stack over the last 1,000 years. Everything else has been additive. [I’ve] always promoted an all-of-the-above strategy. You need to produce all these sources to keep the economies rolling.”
Nuclear energy should remain a part of that mix, Brouillette said. One of the projects he is proudest of as energy secretary was enriching nuclear fuels.
“This specialized fuel allows the creation of these smaller reactors they’re talking about,” Brouillette said. “It allows for walk-away safe nuclear reactors. If the cooling system goes away, nothing happens. There’s no [radiation] release. The reactor just shuts down.”
Analytics Important to Glotfelty
Saying he never wanted to be a regulator, Jimmy Glotfelty, the newest member of the first four-person PUC, has embraced his role as overseer of the ERCOT market.
“We used to be brother and sister, and now the legislature has given us full regulatory oversight over ERCOT,” Glotfelty said, referring to legislation passed in the wake of the February 2021 winter storm. “We can’t let them be the entire analytical process for the commission. We have to have our own view. We have to be able to build out our own processes and our own thoughts.”
Analytics are important to Glotfelty, who had a previous career as a wind developer. He hit the ground running when confirmed to the PUC, meeting with lawmakers after he had already been sworn in and participating in an ERCOT market redesign workshop.
“The cornerstone of [the market redesign’s second phase] is analytical. We have to have the analytics,” Glotfelty said. “I believe the market had some challenges in February [2021], but I don’t believe the market failed. Components of the market failed. Components of winterization failed. Components of the gas system failed. If analytics prove that we don’t know, we’re going to have to understand a little more of it.
“I’m eager to get into these analytics,” he said. “I’ve been saying this since I got to the commission; it needs to be the cornerstone of how we analyze policies at the PUC.”
Storage Key to ERCOT ‘Pummeling’ the Future
During an afternoon workshop on energy storage and its integration into the market, ERCOT staffer Kenneth Ragsdale remembered the first battery that connected to the system 10 years ago.
“It was 36 MW with about 15 minutes of discharge,” he said. “We registered it as controllable load and generation storage. Unfortunately, we’re still using that workaround, but we are trying to get to a single-model aspect.”
Fast forward a decade and the grid operator has about 1.5 GW of storage capacity either installed or synchronized to the grid. Ragsdale thinks the number could approach 5 GW by year-end.
“We’re pummeling the future here with the rapid integration of wind and solar energy. When you walk into an office and tell people you’re in the storage business, they lean forward,” said Pat Wood, former FERC and PUC chair and now CEO of Hunt Energy Network. “This particular piece of energy storage will absolutely be critical to that. The lack of storage requires us to do a much more complex market design.”
Industry Vet Oswalt Wins Star Award
Vicki Oswalt, a 33-year veteran of the Texas electric industry, was honored by the GCPA’s board as its 2022 recipient of the Pat Wood Power Star Award, given annually for the honoree’s significant contributions toward advancing Texas’ competitive energy markets.
“This award is as much about all the people I’ve worked with than it is about me,” Oswalt said. “I don’t want to name names, or we would be here all day. I really feel I share this award with all of you.”
The award is named for Wood, who presented the award to Oswalt and recalled meeting her when he joined the PUC in 1995. The commission wasted no time in installing Oswalt as the first chief of the newly formed Office of Policy Development.
Oswalt joined the PUC in 1989 as a regulatory analyst. After joining Reliant Energy in 1997, she helped implement Senate Bill 7, which opened ERCOT’s competitive retail market. Oswalt also spent time at Energy Future Holdings and its TXU Energy and Luminant subsidiaries before retiring earlier this year as senior vice president of regulatory affairs for Sharyland Utilities.
The GCPA board also took advantage of the opportunity to present ExxonMobil’s Alexandra Williams with its 2021 emPOWERing Young Professionals Award. The award is presented annually to an individual under the age of 40 who has achieved excellence in the electric power industry. Williams actually won the award last year, but she had laryngitis during GCPA’s 2021 virtual Fall Conference, so she could not verbally accept the award. (See “Industry Leaders Honored,” Overheard at the 2021 GCPA Fall Conference.)
A NERC-certified reliability coordinator, Williams has contracted more than 800 MW of renewable power purchases, and managed the two largest demand response portfolios and more than 15 GW of power generation.
NextEra Energy lost almost 10% of its market value last week after telling the financial community that a federal government decision on solar panels and cells supplied from Asia could delay some of its projects.
The Department of Commerce said in March that U.S. trade officials will investigate whether imports of solar energy equipment from four Southeast Asian nations are circumventing tariffs on goods made in China. (See related story, Solar Sector Braces for Tariff Probe Impact.)
During the company’s first-quarter earnings call with analysts Thursday, NextEra management said that 2.1 to 2.8 GW of the company’s planned solar and storage projects may be delayed until 2023 because suppliers are not shipping solar panels to the U.S. while they wait on a final decision.
NextEra Energy Partners CEO John Ketchum said being unable to purchase solar panels from Southeast Asia will force renewables companies like his to instead source their materials from China. NextEra bills itself as the world’s largest producer of solar and wind energy.
“China is the only country in the world that would have panels available to sell because … the U.S. panel manufacturing industry, which is incredibly small even at full capacity, only has the ability to satisfy 10 to 20% of the entire U.S. demand,” he said. “The U.S. industry is sold out until 2025. It forces you back to China … which is an absolutely perverse outcome, an outrageous outcome, quite frankly, and one we intend to make sure that the Commerce Department clearly understands because that’s an unintended consequence that I don’t think anybody wants.”
NextEra announced a first-quarter net loss of $451 million (-$0.23/share), as compared to $1.67 billion ($0.84/share) for 2021’s first quarter. The Florida-based company said it expects to grow shareholder dividends at a 10% annual rate through 2024.
The company’s share price closed the week at $73.95, down $7.54 from its close the day before the earnings announcement and a 9.3% drop over two days.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
D. Members will be asked to endorse Operating Agreement revisions intended to appropriately document the underfrequency load shedding (UFLS) relay requirements applicable to East Kentucky Power Cooperative. A recent review of revisions showed “potential confusion” in EKPC’s appropriate UFLS requirement that needed to be corrected. (See “EKPC UFLS Requirements Endorsed,” PJM Operating Committee Briefs: April 14, 2022.)
E. Stakeholders will be asked to approve revisions to the Energy Price Formation Senior Task Force charter. The proposed charter edits relate to the delay in reserve price formation implementation, from May 1 to Oct. 1.
Endorsements (9:20-10:40)
1. Deactivation Process Timing (9:20-9:45)
The committee will be asked to endorse a proposal to update the process timing for generation deactivations. The proposed deactivation process would establish quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. (See “Deactivation Process Timing Update Endorsed,” PJM PC/TEAC Briefs: March 8, 2022.)
Stakeholders will be asked to endorse a proposed issue charge for the Resource Adequacy Senior Task Force addressing the procurement of clean resource attributes. The issue charge includes discussing the potential benefits and drawbacks of a forward procurement of clean resource attributes and the social cost of carbon in wholesale markets. (See “Procurement of Clean Resource Attributes,” PJM MRC/MC Briefs: March 23, 2022.)
Members Committee
Consent Agenda (1:25-1:30)
C. The committee will be asked to approve proposed revisions to Manual 34: Stakeholder Process to update the paper ballot process. PJM wants to revise Manual 34 before the Annual Meeting on May 17, which includes the Board of Managers election and General Session, to allow for remote voting. (See “Remote Voting for Annual Meeting,” PJM MRC/MC Briefs: March 23, 2022.)
Endorsements (1:30-1:50)
1. Interconnection Process Reform (1:30-1:50)
Stakeholders will be asked to endorse a proposal as endorsed by the MRC (see agenda item No. 2 above). PJM is seeking a same day vote on the issue at the MRC and the MC.
The Arizona legislature passed a bill this week that would close the door to electric retail competition, but lawmakers indicated the conversation on deregulation is not over.
The state Senate on Tuesday passed House Bill 2101 on a 17-11 vote, with two senators not voting. The bill was transmitted Wednesday to Gov. Doug Ducey, who has five days to take action.
The same day as the Senate vote, House Speaker Rusty Bowers and Senate President Karen Fann announced the formation of a joint Ad Hoc Study Committee on Energy. The nine-member committee will meet after the close of the current legislative session, with a report due by Dec. 31.
“The interim work of the committee will enable future discussion of the state’s energy policies and the benefits and risks of energy ‘deregulation’ by providing a robust base of knowledge for policymakers and regulators,” Bowers and Fann said in a joint statement.
The committee will discuss the reliability and affordability of diverse power generation, transmission and distribution resources. Arizona’s governance over electric generation and transmission will be another topic.
Customer Choice
HB 2021 would repeal a 1998 law that was intended to give customers a choice of electricity service providers in the service territories of both investor-owned utilities and consumer-owned “public power entities” (PPE).
But rules that the Arizona Corporation Commission (ACC) adopted to allow competition were shot down by a 2004 appellate court ruling. And proponents of HB 2101 say competition should be rejected to maintain reliable electric service.
The bill, sponsored by Rep. Gail Griffin (R), comes as an application from Green Mountain Energy is pending before the ACC. Green Mountain, a renewable energy company, applied in August to provide competitive electric generation services within the territories of the state’s largest investor-owned electric utilities, Arizona Public Service and Tucson Electric Power.
HB 2101 had its ups and downs in the legislature, as proponents scrambled to gather enough votes.
The House passed the bill in February on a 37-21 vote — after rejecting the bill earlier that month but passing a motion to allow reconsideration. (See Retail Anti-competition Bill Hits Snag in Ariz.)
Similarly, the Senate shot down HB 2101 in March, but passed a motion to allow reconsideration.
During Tuesday’s floor session, several senators commented on why they switched their vote or stuck with their previous decision.
Sen. J.D. Mesnard (R) said HB 2101 would remove a statute that was not working, and his vote in favor of the bill had not changed. Mesnard said he generally supports free-market policies and would have preferred to have a replacement for the deleted statute. He said he’s hopeful that the interim committee will make progress in that regard.
“I’m going to be … very interested in a replacement and be an advocate for creating more competition, more choices for our ratepayers and our consumers,” Mesnard said.
But Sen. Lisa Otondo (D) questioned the timing of the interim committee. She remained opposed to HB 2101.
“Since when do we do an ad hoc committee and stakeholder meetings after the bill has passed?” Otondo said. “What a slap in the face. I vote ‘no.’”
Sen. Tyler Pace (R), who voted against the bill last month but in favor of it on Tuesday, said he had spent dozens of hours studying the issue. Electric retail competition is different from competition in other retail markets, he said.
“This idea that somebody in the middle can just buy energy from whoever they want and then sell it to whoever they want without ever producing and without ever actually laying the wire is not, in my personal or business opinion, a reliable market,” Pace said. “Because when something does go bad, there are some issues with that business model.”
Transparency Concerns
Pace and Otondo both noted a lack of transparency around the bill.
“It was sold as a simple fix to remove defunct statutes from the books, so that the [Arizona] Corporation Commission couldn’t deregulate the energy market and cause a catastrophe, like what we saw in Texas last winter,” Otondo said.
Otondo said she later learned that the utility pushing the bill was involved in antitrust litigation. The utility had been sued by customers with rooftop solar, who were being charged up to 65% more than customers without it, she said.
Otondo didn’t name the utility in the case but seemed to be referring to Ellis v. Salt River Project. HB 2101 would repeal a section of statute that says the Uniform State Antitrust Act applies to a PPE’s competitive electric generation service and other services.
Outside of the legislature, the business group Advanced Energy Economy called “phony” claims that HB 2101 was needed to increase energy system reliability. The group opposes the bill.
The bill does “next to nothing to strengthen the power grid,” AEE Principal Shelby Stults said. “It’s just a way for utilities to reinforce their control over Arizonans’ energy choices.”
If Arizona wants to improve reliability, it should look into joining a Western RTO, Stults told RTO Insider. That would allow more renewable energy to be incorporated in a reliable manner, she added.
Mark Parsons, Green Mountain’s vice president and general manager, said Arizona residents have indicated they want a choice of energy providers. The state has avoided aggressive governmental mandates for clean energy, he said.
Parsons urged Gov. Ducey to reject the bill.
“We are disappointed that HB 2101 repeals the statutory basis for us to receive a license to operate in the state,” Parsons said in a statement following this week’s Senate vote. “That is a legal prerequisite for us to be able to do business.”
FERC on Thursday ordered CAISO, ISO-NE, MISO, NYISO, PJM and SPP to report on how their system needs are changing with their shifting resource mixes and how they intend to meet them (AD21-10).
The commission said the reports would build on the record developed during four technical conferences last year and provide a foundation for potential market changes.
“At this time, we do not propose a generic solution to address changing system needs across the RTOs/ISOs because of the diversity of those needs and the lack of a compelling record to support any one-size-fits-all solution for meeting those needs,” the commission said. “Instead, we believe that it is appropriate to gather additional information from the RTOs/ISOs … to enhance our understanding of the changing system needs in each RTO/ISO and potential mechanisms for addressing those needs as they change over time. We will review the reports and comments to determine whether further action is appropriate.”
The grid operators must report on:
current system needs under changing resource mixes and load profiles;
how each expects its system needs to change over the next five and 10 years;
whether and how each plans to change its energy and ancillary services (E&AS) markets to meet expected system needs over the next five and 10 years; and
information about changes to resource adequacy programs or other market changes, including to capacity markets, that would help each meet changes in system needs.
The commission gave the grid operators 180 days to file reports in response to the order, with public comments due 60 days later.
Democrat Richard Glick called for the proceeding after taking over the commission chairmanship last year.
The commission said the record developed in the docket indicated that “RTOs/ISOs currently face changing system needs that vary significantly by RTO/ISO. The time horizon (minutes, hours, days, seasons) of system needs, particularly with respect to net load variability and uncertainty, also appears to vary significantly across RTOs/ISOs.”
While the issues have been most acute in regions with the highest penetration of variable resources, such as CAISO and SPP, “other RTOs/ISOs also expect their system needs to change in the future, and the commission and stakeholders would benefit from additional information from all RTOs/ISOs on the subject.”
Concurring Statements
Although the commission unanimously supported the order, the panel’s two Republicans offered some additional comments in concurring statements.
Commissioner James Danly called for “a sincere effort to take the lessons learned in our markets and reevaluate whether and how those markets work.
“A single, basic set of questions must be at the heart of our examination: Are price signals providing the proper incentives for the orderly entry and exit of the correct type and quantity of generation to ensure resource adequacy and reliability?” he said. “What we should not do is try to engineer a record by which we might later justify commission action in pursuit of narrow, preordained policy goals.”
Commissioner Mark Christie said that although the primary focus of the reports ordered by the commission related to the E&AS markets, MISO’s latest capacity auction results “are only the latest evidence that the future of all RTO/ISO market constructs should be considered” in the docket. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
“Specifically, I propose fundamental questions regarding pricing and compensation in the energy, ancillary services and capacity markets that merit discussion due to their potential impact on reliability and fairness to consumers. For example, I think it is time to put the all-important question of the continued use of locational marginal pricing in these market constructs on the table for serious scrutiny and discussion,” he said.
Technical Conferences
In March 2021, FERC held its first technical conference in the docket, which focused on capacity markets in PJM, ISO-NE and NYISO and featured broad criticism of the minimum offer price rule. (See PJM MOPR in the Crosshairs at FERC Tech Conference.)
That led to PJM’s proposal to apply MOPR only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. The new rule took effect Sept. 29 “by operation of law” after the commission deadlocked 2-2. The rule change is the subject of a challenge by merchant generators before the 3rd U.S. Circuit Court of Appeals. (See FERC Declines Rehearing of PJM MOPR; Ball now in 3rd Circuit Court.)
A second conference on May 25 focused on ISO-NE’s markets. ISO-NE CEO Gordon van Welie told the commission markets are “never going to work very well” with inadequate infrastructure supporting them and cited a “misalignment” between the RTO markets and state policies. (See Regulators, ISO-NE Discuss Market Changes at FERC Tech Conference.)
A Forward Clean Energy Market, which is under consideration, could relieve some of the tensions, van Welie said. But he said problems will persist “until the region figures out how it wants to socialize some of these costs for reliability that are outside of the market.”
On Sept. 14, the commission held the first of two conferences on E&AS markets, with a focus on the need for flexible ramping products to compensate for shortfalls in forecasted wind and solar output. (See Flexible Ramping Grows as Ancillary Service.) FERC staff had teed up some of the issues in a Sept. 7 white paper.
The discussions continued at a conference Oct. 12, where speakers agreed that market participation rules should be revised to ease the entry of new and emerging resource types. (See Stakeholders Ask FERC to Support E&AS Market Changes.)
“One of the recurring themes we’ve heard from a number of participants is that increasing reliance on intermittent generation resources and changes in load profiles associated with the growth of behind-the-meter generation requires additional system flexibility,” Glick said at Thursday’s open meeting. He said the commission seeks feedback from market participants as well as grid operators. “That will help enable the commission to assess whether modifications of the markets we oversee are necessary and to address the changing needs of the system.”
Rising natural gas prices and extreme weather pushed wholesale electricity prices higher in 2021, FERC said Thursday in its State of the Markets report.
Commission staff said changes in fossil fuel markets “drove price increases” across the board, including for natural gas, oil, propane and electricity, reversing trends of flat to declining prices for several years.
Henry Hub spot gas prices averaged $3.82/MMBtu in 2021, compared with $1.99/MMBtu in 2020. And gas prices have continued to increase in 2022, averaging $4.54/MMBtu through March 14.
Average day-ahead peak prices increased last year at pricing hubs in each RTO and ISO, FERC said, up more than 45% on average and more than 100% in ISO-NE and NYISO. Commission staff said “stressed market conditions” during the February 2021 winter storm in ERCOT, MISO and SPP led to high prices that raised the average for the year.
Despite rising prices, FERC said, instances of negative prices in real-time markets continued to increase across various regions. In 2021, negative average hourly real-time LMPs occurred in about 3.5% of all hours across all RTO/ISO pricing points, compared with 3.1% in 2020.
SPP’s negative prices averaged -$15/MWh over the year, and the RTO accounted for 41% of negative LMPs across all markets, the result of high wind output and low demand, as wind’s share of total output jumped to 34% from 27% a year earlier. ERCOT accounted for 29% of negative prices at an average of -$12/MWh, while CAISO’s share was 21% at an average of $-15/MWh.
Generation Sources
Commission staff said higher natural gas prices also “increased the relative competitiveness” of coal-fired generation, with coal output rising 20% despite continued unit retirements.
Across the RTOs/ISOs, the share of coal-fired output increased from 21% to 24%, while gas-fired generation decreased from 38% to 35%.
Generating capacity continued recent trends, as aggregate nameplate generating capacity grew from 768 GW in 2020 to 789 GW across all RTOs/ISOs. As of December, natural gas represented 46% of the capacity mix, followed by coal at 18%, wind at 14%, and nuclear at 8%.
FERC said some RTOs/ISOs experienced “relatively large changes” in capacity mixes, including an increase in battery storage capacity in CAISO from 0.7% to 3.2% of its capacity mix, an increase in wind capacity in SPP from 26.8% to 29.5% and solar capacity in ERCOT rising from 4.1% to 7%.
The largest portion of capacity retirements came from coal, the commission said, although the 6.5 GW of retirements in 2021 was the lowest number since 2014. FERC said the decline was partly driven by increased electricity demand and the higher natural gas prices.
Electric Transmission
About $15 billion of transmission projects came online in 2021, FERC said, with more than 1,000 line-related transmission projects entering service in the Eastern and Western interconnections. The commission said about one-fifth of the projects included new lines, and about a quarter of those projects were at or above 230 kV.
FERC highlighted the Western Spirit project, a 155-mile 345 kV line in New Mexico, costing $360 million and connecting more than 1,000 MW of generation in the state to the electricity grid operated by Public Service Company of New Mexico. The line was the largest new high-voltage transmission project and the only merchant transmission line to enter service in 2021.
The commission said Order 1000 transmission planning in each region “worked towards or completed a regional transmission plan” in 2021. CAISO’s 2020-21 transmission plan identified three reliability-driven transmission projects estimated at less than $5 million, and two other transmission projects that could be replaced with battery storage. SPP identified 28 new projects with a total of 397 miles of new lines and 48 miles of rebuilt lines, costing $1 billion.
MISO identified 335 new transmission projects totaling 1,188 miles of new lines and 3,137 miles of upgraded lines, costing $3 billion.
PJM added to its Regional Transmission Expansion Plan with 118 new baseline transmission projects at an estimated cost of $920 million and 34 new network transmission projects at an estimated $48 million. Of the new baseline transmission projects, 52% were driven by transmission violations, 23% by generator deactivations and 25% by other NERC and PJM reliability criteria.
Electric Interconnection Queues
The commission said a changing resource mix with increasing renewables has made delays in generation interconnection queues a “persistent, growing feature” of the markets.
“There has been an unprecedented volume of requests to interconnect new generating facilities, which, in turn, has led to backlogs and delays in interconnection queues nationwide,” FERC said in its report.
The RTOs/ISOs had 716,783 MW in interconnection queues at the end of 2021. Solar accounted for the largest portion (282,978 MW), followed by batteries (216,426 MW), wind (114,634 MW), hybrid resources (41,873 MW), DC transmission (19,620 MW), natural gas (9,972 MW), thermal (6,034 MW), combined cycle (4,804 MW), hydro (2,958 MW) and steam turbines (1,119 MW).
Of all the regions, CAISO had the largest amount of capacity by megawatts in its interconnection queue, with solar and batteries as the most common resource types. PJM had the second largest queue by capacity volume, with solar and batteries also comprising the largest shares.
FERC on Thursday proposed changing transmission planning and cost allocation processes in the first in what may be a series of initiatives to help build out the grid in response to electrification and the shift to renewable generation (RM21-17).
FERC met in person for its monthly open meeting for the first time in more than two years, though the meeting was not open to the press or public, only commissioners and staff. | FERC
Meeting in person for the first time after more than two years of telework during the COVID-19 pandemic, the commission voted 4-1 to issue the Notice of Proposed Rulemaking, which would direct transmission providers to revise their planning processes to, among many other things, identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs.
The majority of the commission said the proposal would help planning entities, including RTOs and ISOs, prepare for the growth of renewables, new sources of demand such as electric vehicles and extreme weather events, expected to increase as climate change worsens. In a separate order Thursday, the commission ordered the five jurisdictional RTOs and ISOs to report on how those forces were changing their system needs and what new market rules were required to satisfy them. (See related story, FERC Asks RTOs for Plans on Changing Market Needs.)
“If today’s proposed rule is finalized, it will facilitate much needed transmission investment, improving the resilience of the grid, enhancing reliability and reducing power costs,” Chair Richard Glick said. “It’s also going to address our nation’s changing resource mix and the changing role of electricity in our society.”
The NOPR follows an Advance Notice of Proposed Rulemaking issued in July 2021, which covered a wider range of topics. The results of the ANOPR, which drew hundreds of stakeholder comments, has been highly anticipated by not just transmission developers, but the renewable energy industries as well. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)
The NOPR would not change planning and cost allocation rules for reliability or market efficiency projects, Commissioner Mark Christie noted. “We don’t want to mess with them, and we’re not,” he said. But it would require planners become more proactive in planning for what Order 1000 called “public policy” projects.
The proposed rule would:
require transmission providers to conduct regional transmission planning on a long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand;
require transmission providers to identify transmission needs through multiple scenarios that incorporate factors such as federal, state and local laws and regulations that affect the future resource mix and demand; trends in technology and fuel costs; resource retirements; generator interconnection requests and withdrawals; and extreme weather events;
broaden the benefits that could be considered for project selection and cost allocation;
require transmission providers to seek the agreement of relevant state entities regarding cost allocation; and
require an ex-ante cost allocation method or a state agreement process in which states can voluntarily agree to fund a project, or a combination of the two.
“The clean energy industry is developing thousands of megawatts of clean energy resources — but many projects are stymied by a lack of transmission capacity,” the American Clean Power Association said in a statement. “FERC’s proposed rule has the potential to accelerate backbone transmission development planning, ensure fair and consistent cost allocation, and provide a substantial role for states in planning transmission for the future.”
Many other stakeholder groups issued statements applauding the proposal, though some were more lukewarm. Many called it a “first step,” while Sarah Ladin, senior attorney at the Institute for Policy Integrity, said the proposal was “a modest but important step toward more efficient planning that can facilitate decarbonization.”
Glick assured stakeholders during the meeting that the commission had not forgotten about the ANOPR’s other issues, such as the backlogged generation interconnection queues, interregional transmission planning and incentives. Speaking to reporters after the meeting, Glick advised against taking “the fact that we did a NOPR today on transmission planning and cost allocation to suggest that there wasn’t enough support for any of those other issues. Just the contrary. …
“After all the comments came in on the ANOPR, we realized that there’s a lot here; there’s a lot of meat on the bone, so to speak. And we thought if we tried to handle to every single issue … in one big rulemaking, it would take forever. So, we thought we would streamline it into several different rulemakings. …
“My great hope is that in the very near future, we’ll able to issue a NOPR on interconnection reform, which is very important. … [But] we didn’t think it was wise to do it all in one big rulemaking.”
While perhaps not a complete overhaul, the proposal would result in significant changes to transmission planning. RTOs, for example, would be required to create scenarios, with a minimum time horizon of 20 years, that forecast changes in resource mixes and the probability of extreme weather events. Planners would then evaluate project proposals based on FERC-approved criteria that recognize the benefits over the time period for the purposes of cost allocation
Right of First Refusal
Among the most significant changes would be an exception to Order 1000’s elimination of the federal right of first refusal (ROFR).
FERC said regional transmission facilities subject to competitive procurements represent only a small portion of transmission investment in recent years and that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission.
Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, the commission said.
It proposed allowing an incumbent to exercise a federal ROFR for a regional project on the condition that it partner with an unaffiliated company with a “meaningful level of participation and investment” in the project.
While that change would be a win for incumbent transmission owners, the commission also proposed new procedures to ensure they don’t replace aging transmission infrastructure without evaluating whether they could be “right sized” to provide more cost-effective solutions to regional transmission needs.
Construction Work in Progress
Developers would also not be permitted to take advantage of the commission’s construction-work-in-progress (CWIP) incentive for their selected projects. Planners would also be required to seek state approval of their proposed cost allocation methods.
Those requirements were key to Christie’s support for the proposal. He said that CWIP puts consumers at risk by allowing developers to be paid “before a single ounce of steel is put into the ground, much less the project is in service.” Instead, pre-construction costs would be “booked” as allowance for funds used during construction (AFUDC).
“With AFUDC, the developer gets to book the costs but cannot collect from the consumers until the project is in service,” he said.
The former Virginia State Corporation Commission chairman was also exuberant about the provisions to include state input and approval. In this he disagreed with Commissioner James Danly, who dissented because, he said, “I don’t like the purpose of this NOPR.
“It is designed to encourage buildout of transmission specifically for the purpose of encouraging the development of certain types of resources. That is something that I think is not appropriately a concern of the commission. And it does so by socializing costs through putting public policy choices — that is, state and, if you can believe it, even local public policy choices — front and center in the transmission planning process.”
“It is also not a policy action to advance renewable energy interests. To so frame the proposed long-term transmission planning reforms, or to portray transmission planning as a zero-sum game, misses the point,” she said. “Rather, the proposal contains a sensible suite of reforms to shore up cost protections and reliability of the U.S. electricity system based on clear market signals about generation development and demand, the risks of extreme weather and the increasing threat of cyber and physical attack.”
Christie said the addition of a state role in cost allocation was “probably the single biggest reason” he voted for the proposal.
“For the first time, it puts states formally at the heart of the planning for these types of projects,” he said. “States are going to be at the heart of the planning. States are going to get the opportunity to agree to the criteria, and they’re going to get the opportunity to agree to the cost allocation. This has never been a formal requirement in FERC’s transmission regulation.”
Comments on the NOPR will be due in 75 days from publication in the Federal Register.
The Maryland Public Service Commission (PSC) on Wednesday unanimously approved changes to the state’s Electric Vehicle Charging Pilot Program, increasing incentives aimed at boosting the number of EV chargers installed at locations often underserved by commercial charging companies — multi-unit dwellings, small businesses and nonprofits (Case 9478).
For Baltimore Gas and Electric (BGE), the PSC approved a new rebate program that will cover 50% of the cost of fleet and workplace chargers for 25 Maryland small businesses, with rebates capped at $30,000 for the installation of two DC fast chargers (DCFCs). A $30,000 cap also was approved for DCFCs installed at multi-unit dwellings, an increase of the current cap of $25,000.
Pepco and Delmarva Power were also approved for the $30,000 cap for a new workplace and fleet rebate program for small businesses and nonprofits, again targeting 25 installations. But both utilities will scale back the number of rebates they offer for multifamily dwellings — from 200 to 100 for Pepco and from 50 to 25 for Delmarva — but cover 100% of installation costs, instead of the 50% previously offered.
All three utilities, which are owned by Exelon (NASDAQ:EXC), also were approved to offer $50 e-gift cards as an annual incentive for residential customers to stay enrolled in EV charging programs that allow the companies to track their charging data through “smart charging” software.
Pepco and Delmarva also won approval to expand their residential programs for newer EVs with advanced technology that allows them to communicate charging data to a utility without needing a “smart” charger or extra meter to track usage. EVs with this technology will be eligible for an off-bill credit, $0.03/kWh, for off-peak charging, paid quarterly in the form of a cash card.
With Commissioner Anthony O’Donnell absent, approval of the changes marked the end of several months of negotiations over mid-course adjustments to the pilot program that was launched in 2019 and is scheduled to run through the end of 2023. Key goals include the installation of 1,000 utility-owned chargers in public locations — that is owned or leased by state or local governments — and filling specific gaps in EV charging infrastructure, such as for multi-unit housing and small businesses.
In its decision establishing the pilot program (Order No. 88997), the PSC laid out the number of public chargers each utility is supposed to install by the 2023 deadline: 500 for BGE, 250 for Pepco and 100 for Delmarva. According to information shared with the commission on Wednesday, BGE has installed 206 public chargers to date, while the combined total for Delmarva and Pepco stands at 149.
Two other utilities, Potomac Edison and the Southern Maryland Electric Cooperative (SMECO), are also part of the pilot program, but were not at Wednesday’s hearing.
The Multi-Unit Challenge
The changes approved, and those denied, reflect the complicated economics and changing technology in the EV market.
While the incentives are seemingly generous, the three utilities have not had a good response to the charger rebates for multi-unit dwellings, especially in low-income areas. According to Jamie Caswell, a spokesperson for Pepco and Delmarva, to date Pepco has installed 12 EV chargers at multi-unit dwellings in Maryland, with five more such projects in the pipeline. Delmarva has three multi-unit projects in the pipeline, but has yet to install any, Caswell said in an email to NetZero Insider.
As an alternative, BGE had proposed that low- and moderate-income (LMI) customers should be eligible for a $1,000 rebate to install EV chargers. The PSC turned down the request, siding with consumer advocates who pointed out that such incentives would not address the more significant obstacle of the higher upfront costs of EVs and were therefore “premature.” BGE should work with local organizations to better understand the needs of LMI customers and communities, the commission said.
The commission also rejected BGE’s request to expand its residential charger program to add rebates of $300 each for the installation of 2,500 smart chargers, which would allow the utility to track customers’ charging patterns. The PSC had originally approved the utility for rebates for 1,000 residential smart chargers, but BGE reported, the program was oversubscribed.
The commission said that for many, more well-off EV buyers, the $300 charger rebate was not an essential decision point. In addition, the PSC said, the extra expense of smart chargers is no longer justified since most EVs now have the technology to directly communicate their charging data to a utility. The utility is no longer offering rebates for residential chargers, according to an email from the company.
An Exercise in Balance
Both Maryland and the PSC are bullish on EVs. According to the state’s most recent greenhouse gas inventory, transportation accounts for more than a third of Maryland’s emissions, and the state is pushing to get 300,000 EVs on the road by 2025.
However, “the state may be hamstrung to some extent” in reaching that goal, due to U.S. dependence on foreign sources for lithium and other minerals critical to EV battery production, said Commission Chair Jason Stanek, in opening remarks at Wednesday’s meeting.
Based on different industry sources, the state has about 40,000 EVs on the road at present (three of which belong to Stanek, Commissioner Odogwu Obi Linton and Commissioner Michael Richard). The state Department of Transportation reports 1,100 public chargers, with close to 3,000 ports in total.
Across the country, utilities are seeing the growing EV market as a major accelerator for demand growth but are also concerned about the impact of EV charging on local distribution systems, hence the interest in having access to charging data and designing special rates that encourage off-peak charging.
The Maryland EV Charging Pilot was intended to help remove obstacles to EV adoption. But, for the PSC, it has been an exercise in balancing the interests of the state’s investor-owned utilities in investing millions of rate-based or otherwise recoverable dollars in charging stations, and the impact of such initiatives on customer utility bills and the state’s competitive EV charging market.
For example, BGE’s original program proposal included plans for installing more than 18,455 residential, commercial and public chargers at a cost of $48.1 million. Pepco and Delmarva’s plans were more modest: $11.3 million for Delmarva to install 774 chargers, and $30.6 million for Pepco to install 2,264 chargers.
In its 2019 decision, establishing the program, the PSC knocked down those figures, stating the utilities had not “met their burden to justify the recovery of [millions] in cumulative program costs exclusively from ratepayers.” The decision gave approval for a scaled-down initiative including the residential rebates and time-of-use rates to encourage off-peak charging, the public charging targets and the multi-unit dwelling incentives.
Wednesday’s approvals were the latest iteration of this program dynamic. BGE, Pepco and Delmarva submitted a joint request to launch first a Fleet Calculator software platform that would “help educate fleet customers on the types of EVs that are available for purchase, what charging equipment to buy, and available EV rates.” The PSC approved the $300,000 price tag for launching the platform but balked at the $2.5 million the utilities requested to hire contractors to provide customers with more in-depth advisory services on fleet electrification.
Few utilities are offering this kind of service, the PSC said, and any efficiencies gained by a holistic approach to fleet electrification would be overshadowed by the cost to ratepayers, especially if a business decided not to electrify its fleet following an assessment.
MISO officials this week answered questions about the more confusing aspects of the Midwestern shortfall and expensive prices in last week’s capacity auction while stakeholders asked for more supply data from before the auction.
The RTO’s 2022/23 Planning Resource Auction (PRA) resulted in the Midwestern zones, 1 to 7, being deficient by 1.2 GW of their collective planning reserve margin requirements and clearing at the $236.66/MW-day cost of new entry (CONE). (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) However, on the zonal level, only zones 4 to 7 — which include parts of Illinois, Lower Michigan, Indiana, Missouri and western Kentucky — couldn’t meet their local clearing requirements, and they couldn’t find extra supply from the other Midwestern zones.
MISO’s transfer limits between its subregions also kept the Midwest from accessing additional supply from the South that could have counteracted the regional capacity shortage.
Eric Thoms, MISO senior manager of resource adequacy operations, said the RTO’s auction clearing engine uses subregional resource zones and includes the marginal cost of a binding subregional flow limit in prices. In the case of this year’s auction, the South-to-North transmission limit bound. MISO used a 1,900-MW South-to-North limit and a 3,000-MW North-to-South transfer limit in the auction. The RTO begins with the usual 3,000-MW southbound and 2,500-MW northbound limits and subtracts firm service contracts to arrive at the transfer limits used in the auction.
MISO also used Zone 3’s $236.66/MW-day CONE to price the entire Midwest because it is the cheapest of the CONE prices, and the auction is designed to apply the lowest CONE when an entire region is short. The CONE values differ by zone because the cost of building new generation varies regionally.
“The objective of the multi-zone optimization methodology is to minimize the overall costs of capacity,” Thoms explained to stakeholders in a Resource Adequacy Subcommittee teleconference Wednesday.
Stakeholders asked MISO to telegraph a better feel of supply in the weeks and months leading into the auction. They said there was a large delta between confirmed unforced capacity and what was ultimately converted into zonal resource credits. Ahead of the 2022/23 planning year, MISO anticipated a 121-GW coincident systemwide peak, with 157 GW in total installed capacity and just short of 128 GW in total unforced capacity to cover it.
Stakeholders asked if MISO could have disclosed a level of accelerated suspended or retired megawatts ahead of the auction so market participants could have reacted and made more supply available.
Apex Clean Energy’s Richard Seide said the auction results were “astonishing.”
“I know things were getting tight, but if you read the data going into this year’s auction, you didn’t think it was going to go this way by a few hundred megawatts. You thought we were going to slide by again,” Constellation Energy’s John Orr said.
MISO Director of Resource Adequacy Coordination Zakaria Joundi said that while the RTO can’t reveal unit-specific data, it is reviewing the usefulness of the preliminary PRA data it posts.
“I think the process should be more transparent, so that choices to bring more capacity to the market can be viable,” Power System Engineering’s Tom Butz said.
Taylor Martin of the Independent Market Monitor, Potomac Economics, said the IMM tries ahead of time to project what will be unavailable but is bound by multiple confidentiality rules. But he said the Monitor found no evidence of economic or physical withholding.
Thoms also said no market participants this year elected to pay a capacity deficiency charge to MISO. According to MISO rules, load-serving entities can opt to pay out all or a portion of their planning reserve margin requirement.
The auction results are emblematic of the tricky situation MISO faces in navigating its members’ portfolio transition.
The 2022/23 capacity results brought longstanding criticisms of MISO bubbling back to the fore, including its lack of sturdier transmission connections between its South and Midwest regions, a bevy of thermal generation retirements and MISO’s use of a vertical demand curve over a sloped demand curve in the auction.
MISO said members in recent years have been replacing retiring thermal generation with even more megawatts from new intermittent resources.
The auction results come as Consumers Energy — Michigan’s largest electric utility — and stakeholders this week announced that they reached an agreement to close all coal plants by 2025, which could make it one of the first large utilities in the nation to eliminate coal use. The proposal still needs the blessing of the Michigan Public Service Commission. (See Consumers to End Coal by 2025 in IRP Deal with Mich. AG.)
Michelle Bloodworth, CEO of coal lobbying group America’s Power, said EPA’s recent crackdown on coal ash could also idle a little more than 2 GW of coal-fired generation in MISO Midwest as early as the fall. She said MISO should also factor that development into its supply picture.
Stakeholders said it seemed that a lot of the new capacity that MISO and the Organization of MISO States were expecting per their annual resource adequacy did not manifest. Some wondered if the RTO needs to recalibrate its expectations of generation that will complete the interconnection process.
Monitor: Sloped Demand Curve, Please
Monitor David Patton said the auction shortage reinforces the need for a sloped demand curve in the auction, a call he’s been making for 12 years now.
During the Market Subcommittee’s meeting Thursday, Patton said MISO undervalues capacity, sending “bad signals” to market participants. He said MISO’s long history of “near-zero” clearing prices spur too-early unit retirements.
Zonal clearing prices in the 2022/23 MISO capacity auction | MISO
“Since 2019, MISO lost almost 5 GW of capacity in the Midwest that would have been economic if the PRA had set efficient clearing prices,” he said. “Most of these retirements were by unregulated merchant suppliers that rely on the market signals to make investment and retirement decisions.”
2nd Regional Resource Assessment in the Works
MISO will pull together another long-term resource assessment by the end of this year, this time with assistance from its members.
Last year, MISO relied only on public data it independently searched. The regional resource assessment this year will include data sourced directly from members to get a better picture of protracted resource trends. The RTO said it has collected generation information from 75% of its load for the 2022 assessment.
MISO said preliminary results show a lower level of nuclear retirements 20 years out; net neutral natural gas retirements and additions over two decades; and the same 35 GW of coal plant retirements by 2040 that it originally expected last year. It also foresees a 65% reduction in emissions from 2022 levels by 2040.
