NEW ORLEANS — The likelihood of a sloped demand curve in MISO’s capacity market earned seals of approval from panelists at Gulf Coast Power Association’s 9th Annual MISO/SPP Regional Conference March 8-9.
MISO Independent Market Monitor David Patton said he recommended the grid operator adopt a sloped demand curve for about 20 years, to remedy its “broken” capacity construct.
Patton said he assumes that stakeholders opposed to a sloped curve are acting in their self-interest. He said members sooner or later must accept that they may have to purchase capacity “that keeps the lights on” in a market structured to reflect capacity’s marginal reliability.
MISO is intent on designing and implementing a downward-sloping demand curve by its 2024/25 capacity auctions. It will replace a demand curve that abruptly cuts off excess capacity’s value when reserve margin requirements are satisfied. (See MISO Charts Course on Capacity Auction’s Sloped Demand Curve.)
The grid operator is proposing four sloped demand curves for each of its seasonal auctions based on separate seasonal reliability targets. Its analyses have shown an incremental value for capacity procured beyond the summer reliability target.
“Historically, as an industry, resource adequacy was binary. Either you had it or you didn’t,” said Todd Ramey, MISO’s senior vice president of markets and digital strategy.
Ramey said that the paradigm led to the RTO’s longstanding vertical design.
“When we started, we had a pretty healthy reserve margin for the footprint,” Ramey said. “Here we are 10 years later, and we’ve been wildly successful at bumping down our reserve margin.”
He said the static demand curve has produced capacity pricing that is “inefficiently low” to spur new generation development.
Patton said that had MISO used a sloped curve in previous auctions, it would have produced prices in the $100-$150/MW-day range.
“It’s going to hit everybody,” Patton said of reliability issues, especially during winter storms.
“We can’t maintain reliability without a capacity market that functions,” he said. “We need to realize that keeping the lights on is way more important than spending a little more on capacity.”
Patton also said stakeholders must get comfortable with MISO placing a marginal value by resource type on capacity.
“You get to a point that you have enough wind that building more wind isn’t going to have reliability value,” he said.
Brett Kruse, Calpine’s vice president of market design said he was surprised that MISO is willing to bend its demand curve after years of opposition. He said he considered it inevitable.
Kruse said a demand curve sending “investment signals” is meant to keep existing baseload generation online. He said new merchant thermal generation is unlikely to be built without developers first securing 20- to 30-year power contracts.
Peregrine Consultants President Charles Griffey said MISO doesn’t need a three-year forward market if it can develop incentives within its one-year spot market.
“The problem is do we really have that incentive in these areas?” he asked rhetorically.
Griffey said demand curved shapes will likely be a “political decision” involving a subjective reliability target, while factoring in carbon-reduction goals.
Patton agreed that forward capacity markets are a “terrible, terrible” idea, saying they interfere with investment, fuel procurement and generator-retirement decisions.
Lisa Duffey, Cleco’s director of strategic market and fuel operation, said she wasn’t sure MISO and SPP were doing enough to make sure that capacity is deliverable to load. She said MISO’s planning doesn’t ever seem to help localized transmission constraints.
“Are we fixing the real problem?” she asked.
Patton said MISO should design its local resource zones to reflect actual load pockets. He said Zone 9, which combines East Texas and Louisiana, is the worst offender for not recognizing natural electrical boundaries.
ERCOT quietly dropped a spring resource adequacy assessment last week that indicated it expects nearly 100 GW of seasonally rated capacity to be available to meet demand.
The Texas grid operator projects demand will peak at 59.5 GW in April and 69.9 GW in May, according to its latest seasonal assessment of resource adequacy (SARA). That assumes the footprint will experience “typical” spring grid conditions, based on average weather conditions during the 2007-2021 spring peaks.
ERCOT announces its spring resource adequacy report. | ERCOT via Twitter
The total capacity includes 63.4 GW of thermal generation, 15.8 GW of wind resources and 10.7 GW of solar resources. It also assumes 844 MW of battery storage capability will be available for dispatch before the highest spring net load hours. Staff calculate net load as total load minus wind and solar generation to represent the demand that must be met with other available resources.
The report includes typical thermal outages of 19.5 GW during the March-April maintenance window and 16 GW during May’s forecasted spring peak. ERCOT based the outage assumptions on historical data for the previous three spring seasons; staff excluded 2021, when February winter storm outages extended into the spring.
The load forecast incorporates expected increases during the peak demand hour from interconnected cryptomining facilities and other large loads. Staff evaluated two risk scenarios: based and moderate, and extreme risk.
ERCOT’s only public notification of the SARA was a tweet Wednesday. It previously issued the report in press releases; follow-up conference calls were discontinued after the deadly 2021 winter storm.
ISO-NE procured 31,370 MW in this year’s capacity auction, the grid operator said Friday in a press release.
Forward Capacity Auction 17, which was procuring capacity for the region for 2026 and 2027, took place on March 6. The preliminary clearing price was $2.59/kW-month in all of ISO-NE’s zones and import interfaces except for the New Brunswick interface, which cleared at $2.551.
That’s largely in line with the prices cleared in last year’s auction, which ranged from $2.531 to $2.639, but ISO-NE noted that this year’s price “was among the lowest in the auction’s history.” The lowest price in the history of the auction was FCA 14 in 2020, at $2.001.
About 750 MW of new renewables, storage and demand response secured capacity obligations this year, 519 MW of which were solar and/or storage and 130 MW were DR.
More than 5,000 MW of renewables, storage and demand cleared in total, accounting for about 16% of total capacity, ISO-NE said.
“This year’s auction secured the lineup of resources — including clean electricity generation, energy storage and resources that reduce demand — needed to meet the region’s power system reliability requirements, at a low price,” Peter Brandien, ISO-NE’s vice president of System Operations and Market Administration, said in a statement. “The results represent clear benefits to New England’s residents and businesses in the form of cost-effective resource adequacy and support for the clean energy transition.”
The auction awarded capacity obligations to 567 MW of imports from New York, Quebec and New Brunswick.
ISO-NE said finalized auction results, including details on specific resources, will be filed with FERC and announced publicly soon.
NEW ORLEANS — Panelists at the Gulf Coast Power Association’s 9th Annual MISO/SPP Regional Conference March 8-9, which attracted a sellout crowd of 230 attendees, made links between long interconnection queue wait times, major transmission expansion, reliability worries, and the inexorable integration of renewable energy.
Terry Chambers, director of the Energy Efficiency and Sustainable Energy Center at the University of Louisiana at Lafayette, said there isn’t a route to achieving the state’s climate goals unless grid operators can bring generation projects online in a timely fashion.
He said MISO and SPP should share more information sooner and publicly so developers can make an informed decision on whether to enter their projects into the queue. He said MISO might recruit more staff to assist with processing and studying the queue.
Kelly Pearce, AEP’s managing director of integrated resource planning, agreed that “four- to five-year delays and the uncertainty” they breed for developers is frustrating.
Recurrent Energy’s managing director Robert Moore said he realized he and a colleague had spoken about the same issue in 2019. He said the dinner discussion then was largely the same as now, other than the fact they dined on grilled oysters instead of barbecue.
Moore said when he tells farmers and county officials they’ll have to wait five years to have certainty on revenue through solar projects “[they] look at me like I’m a moron.”
“I’ve been married long enough [to know] that you want to manage expectations,” Moore joked.
Advanced Power Alliance’s senior vice president of markets and infrastructure, Steve Gaw, said developers need new transmission capacity quickly. He said MISO’s long-range transmission planning (LRTP) is a “huge, huge advance” in incorporating more renewable energy.
“Certainty is the issue that most developers face. We need to get this transmission built earlier, and we need more certainty,” Gaw said. He added that developers enter queues without a firm estimate of their interconnection costs or how many restudies their projects will be subjected to.
Gaw said MISO’s and SPP’s efforts to reduce wait times has largely raised the developers’ financial risk by requiring more capital upfront.
“It just becomes a question of how long can you afford it and how long can your company afford it to know that your project is viable,” he said.
LRTP to Aid Transition
Increasing renewable energy is the thrust behind MISO’s ongoing LRTP effort.
“On July 25, 2022, we shook up the world,” MISO Vice President of System Planning Aubrey Johnson said, referencing the MISO Board of Directors’ approval of the first LRTP portfolio, valued at $10 billion. MISO has now embarked on a second portfolio again aimed at its midwest region. (See MISO Says 2nd LRTP Portfolio Still in Flux.)
Johnson said parties might have doubted the RTO’s ability to bring forward another comprehensive, forward-looking transmission portfolio after its 2011 slate of multi-value projects.
He said MISO envisions requiring about 330 GW of renewable energy over the next 20 years to meet goals set by states and members. That will require dramatic transmission expansion, he said.
“And I have a lot of people sitting on their hands. They take long breaks and take a lot of vacations,” Johnson joked of his overtaxed planning team.
Johnson said MISO needs to keep focus on “regulatory support” needs for long-range transmission expansion. He said MISO is counting on its incumbent developers to convey to state regulators how crucial LRTP projects are.
David Kelley, SPP’s vice president of engineering, said SPP is seeking to “innovate and completely transform” its transmission planning by using a consolidated process. He said SPP must devise “a fair and equitable manner” to divide the costs of an optimized grid. He added that SPP is being “very deliberate” about planning for more common extreme weather.
“We have to continue to learn from each other,” Kelley said.
Jim Dauphinais, an energy consultant representing multiple MISO end-use customers, said his clients are disappointed that MISO has already devised and is now coming up with a new cost allocation for LRTP projects. (See MISO to Test Long-range Tx Allocation Benefits.)
He said MISO had a durable and comprehensive cost-sharing method in its existing market efficiency project allocation and relies on adjusted production cost savings, avoided reliability projects, and savings when a project can reduce dependency on the transmission constraint between its Midwest and South regions.
“Somehow, that got tossed aside … That’s highly problematic,” he said. “There are tens of billions of dollars being talked about in transmission investment.”
Dauphinais called for a refocus on LRTP cost allocation and “a lot of care” in selecting which projects are needed now. He said cost-allocation challenges are behind MISO’s delay to plan LRTP projects in the south until it completes two planning rounds for MISO Midwest.
“Quite frankly, I believe, the cost-allocation issue is a sensitive issue for the MISO South commissions,” he said.
The Regulatory View
In a panel focusing on the regulators’ perspective of recent events, Kansas Corporation Commissioner Andrew French said the industry is realizing that one grid operator’s reliability risk affects another grid operator’s reliability status.
Michigan Public Service Commission Chairman Dan Scripps said MISO’s 2022/23 capacity auction, which resulted in a Midwestern shortfall, was “a wake-up call for MISO and the country.” He said the RTO’s LRTP portfolio represents “a best-in-class” transmission planning exercise to facilitate the generation fleet’s evolution.
But Scripps said it’s currently taking too long to bring generation online through MISO’s queue process. He questioned whether the first LRTP planned projects are sufficient to meet the fleet evolution, “the ground literally moving under our feet.”
Scripps said he thought the second LRTP portfolio’s preliminary possibilities is a good start. He said the first two portfolios that focus on MISO Midwest should be relatively uneventful compared to the third and fourth packages in which planners will analyze MISO South’s transmission needs.
“I think it’s really interesting in terms of tranches three and four,” he said, saying the fourth portfolio is where MISO will get to the “holy land” of better connecting its Midwest and South regions. Scripps said MISO’s current postage-stamp allocation applying to Midwestern LRTP projects probably won’t pass muster in MISO South.
“That approach is one that, let’s say, hasn’t been fully embraced by people in [MISO] South,” he said.
But Scripps said a “free flow of electrons and benefits” between subregions is necessary for a unified MISO system.
“The current bifurcation of the MISO footprint does no favors, I think, on either side,” he said.
Louisiana Public Service Commissioner Davante Lewis, noting he was only 69 days into the job after upsetting incumbent Lambert Boissiere III in a December runoff, said his priorities include helping renewables gain quicker access to the grid, customer affordability and grid hardening. (See Lewis Upsets Boissiere for Seat on La. PSC.)
“I know we talk about how the contractors and developers can’t wait. People can’t wait,” Lewis said of more affordable energy.
Lewis warned that there’s an inflection point at which customer disconnections due to nonpayment will begin to accumulate.
MISO Counsel Calls for Collaboration
MISO Senior Vice President and General Counsel Andre Porter said the GCPA audience has “no other choice [but] to be a high-performing team” in managing the evolving grid. He said the alternative is to be territorial, insular companies, “dysfunctional” and “engaging in disputes [and] spending too much time solving to the last decimal place.”
Porter advised his listeners to collaborate, communicate openly and “check in with each other.”
“There are millions of people, companies outside this room relying on us,” Porter said. He said MISO has long believed there are “unsafe consequences of an uncoordinated transition.”
Porter said he is concerned over accredited capacity exiting the footprint and being replaced by even more gigawatts “coming online, but not providing that same level of high confidence.”
He said MISO’s staff vacancy rate is receding to normal levels, and he said the RTO is hiring the next generation that stands ready to tackle reliability challenges.
“There is a tremendous change and a revolution going on,” Gaw said, also stressing the need for parties to work together.
ACES Power Senior Vice President Jason Painter said that for the first time in his career, he’s witnessing reliability concerns take precedence over price considerations.
WASHINGTON — While they recognize that changes to permitting laws are needed to fully realize the benefits of the Inflation Reduction Act, Democratic officials told the American Council on Renewable Energy on Thursday that a package emerging from House Republicans is a poor start.
Successful bipartisan permitting legislation is more likely to come out of the Senate, said John Podesta, a senior adviser to President Biden on clean energy innovation and implementation.
The House of Representatives is “going to produce some legislation, and they’ll pass it,” Podesta said at the ACORE Policy Forum. “My guess is they won’t consult with Democrats very much. They’ll sort of put together what’s their wish list of assets.”
The White House could work with House Republicans if they come up with sensible proposals that “respect science” and do not “undermine core environmental laws,” Podesta said. But several senators are interested in working on serious permitting legislation, including Sen. Joe Manchin (D-W.Va.), who tried to get a bill through last Congress, and his fellow West Virginian across the aisle, Sen. Shelley Moore Capito, Podesta said.
The attention that permitting is getting from senior officials will help move things along in a process that is performed in the agencies with little attention from the heights of government, Podesta said.
“There’s nothing like accountability: having people at the top know that they’re responsible for working through and breaking through unacceptable delays,” he added.
Biden has also directed his cabinet to make sure that they are using their existing powers, which include some backstop siting authorities for the Department of Energy and FERC from the Energy Policy Act of 2005, Podesta said.
Both Podesta and Sen. Martin Heinrich (D-N.M.) have worked for years to try to get Pattern Energy’s SunZia transmission project built, which would bring up to 4,500 MW of wind power from New Mexico to markets in Arizona and Southern California. Podesta recalled working on it in the Obama administration in 2015 and thinking the line would move forward, only to find out that Pattern had not started construction when he started working for Biden.
The line recently received a final environmental impact statement from the Bureau of Land Management, and a final decision on its route over federal lands is expected this spring, said Heinrich.
“As we build out more transmission lines like this one and overhaul our existing transmission infrastructure, we can bring many, many more large-scale clean energy and storage projects onto the grid,” Heinrich said, “but only if we move much more quickly than we have in the past. It has taken more than a decade and a half for a series of developers to navigate the complex siting and permitting processes for just this transmission line.”
Eliminating carbon emissions from the power sector will require doubling, or even tripling, the capacity of the grid, and while Congress passed legislation last session that includes significant funding for transmission, more change is needed, Heinrich said.
“We all know we have to go a lot further,” Heinrich said. “And that means addressing the underlying problem: that financing timelines and the time it takes to get these major infrastructure projects through complex permitting processes simply don’t match up.”
Heinrich plans on introducing bills intended to improve the transmission planning process and would require that the multiple benefits of transmission be considered in cost allocation. He also plans to introduce a tax credit for transmission, which ACORE has found would spur $15 billion in private investments.
On changes to permitting, Heinrich said he was preparing legislation that would give FERC and DOE conditional authorities to expedite siting processes for high-voltage transmission through a collaborative process that involves states, tribes and other federal agencies.
Besides federal changes, Heinrich urged any firms interested in developing major transmission lines to meet early and often with the impacted communities so they can develop alternatives and avoid conflict as much as possible.
“I would encourage developers to look at issues like environmental mitigation and working with tribes as opportunities for positive engagement rather than just confrontational obstacles,” Heinrich said.
Changing permitting laws has a path to get through Congress this session, with Heinrich saying it is one of the few areas where the two parties have some overlapping goals. But he would rather see something like what Manchin proposed last Congress than what House Republicans have floated so far.
“There’s definitely a potential path,” Heinrich said. “And I think the question is, can the House become a bit more pragmatic? It is driven by its right flank right now; it is making a lot of statements; [but] at the end of the day … [you] come to Congress hopefully to get things done, not just make statements. And that’s the pivot that we need.”
Texas lawmakers Thursday laid out a legislative package that threatens the state’s renewable industry and provides generous incentives to dispatchable generation.
Sen. Charles Schwertner (R), chair of the Business and Commerce Committee, listed seven bills and three more by Vice Chair Phil King (R) that he said would address the operational flexibility and resource adequacy “needed to power Texas into the future.” That parroted language used by ERCOT CEO Pablo Vegas during the grid operator’s most recent board meeting. (See related story, ERCOT’s Vegas Makes His Case for PCM.)
The bills would create a reserve market of 10 GW of gas-fired generation; require that, effective next year, 50% of capacity installed in the state be dispatchable; institute a firming requirement for all resources and load-serving entities; and mandate that generation be built closer to load to reduce transmission costs.
Asked whether the legislation can be interpreted as saying that lawmakers want to focus more on dispatchable energy rather than renewable energy, Schwertner, flanked by signs that read “Powering Texas Forward,” said, “That’s absolutely correct.
“I think it is important that we state the facts,” Schwertner said. “Certainly, renewable penetration is significant, and when it gets too high, because of the variability and lack of performance at critical times … we need that dispatchable generation to balance out and assure that we have a grid that’s performing in times of critical need.
“We’ve got companies that are wanting to invest here. We have to have generation that performs when it’s critically necessary, and that’s dispatchable generation that can be counted on when the wind is not blowing and the sun is not shining. It’s absolutely critical that we level the playing field and balance out that market,” he added.
Advanced Power Alliance CEO Jeff Clark said many of the bills would “dramatically” raise consumer costs, distort the free market and “stifle” advancements in innovative technologies that would provide “a more affordable, reliable and resilient electric grid.”
“Serious policy proposals have been put forth by stakeholders since Winter Storm Uri, and this suite of anti-renewable bills spits in the face of the many productive conversations that have taken place regarding how best to solve the issues we face in Texas,” Clark said. “Grid reliability events are caused by a variety of factors, and the Texas Legislature should be laser-focused on addressing those issues, not searching for ways to tax cheap energy and increase profits of existing generators. The Texas Senate is playing a high-stakes game of politics, with no attention paid to who will lose in the end: Texas consumers.”
The legislation is a response to the deadly February 2021 winter storm, also known as “Uri,” that almost brought the Texas grid to its knees, killed hundreds of residents and inflicted billions in economic damage. A joint FERC–NERC inquiry into the storm found natural gas facilities accounted for more than 50% of unplanned outages, de-rates and failures to start during the storm. (See FERC, NERC Release Final Texas Storm Report.)
The gas fleets in ERCOT and other RTOs and ISOs suffered similar problems during the winter storm in December last year.
Texas Lt. Gov. Dan Patrick (center), standing with state senators, explains the need for more thermal generation in the ERCOT market. | The Texas Senate
Lt. Gov. Dan Patrick, who leads the Senate, called the proposals a “bold agenda” that will “fix the Texas power grid once and for all.”
“I have been abundantly clear that we need to bring new dispatchable (primarily new natural gas plants) generation online as soon as possible to make sure that Texans have reliable power under any circumstance,” Patrick said in a statement.
He has included two of the bills, SB6 and SB7, as two of his top 10 priorities for the current legislative session that ends May 29. Schwertner drafted both bills.
SB6 would establish an “energy insurance program” by offering state-backed loans as low as 1% to build 10 GW of natural gas generation, similar to a program that the state uses for water projects. The units in the program would operate under a last-on, first-off construct. The program’s transmission and distribution costs would be allocated to retail customers in ERCOT.
“This is not building a capacity market; it is an insurance product,” Schwertner said. “The energy-only market has been very successful here in Texas at keeping costs down. But it is again important to have a backup system so that Texans can be reassured that we have the power necessary in times of crisis.”
SB7 would create a new day-ahead ancillary service product, a dispatchable reliability reserve service with two-hour ramps and four-hour runtimes, targeted at dispatchable resources. The bill would also address “market distortions” caused by federal tax credits for “less reliable generation,” Schwertner said.
“Reliability comes at a cost, and for too long that cost has not been shared equally between intermittent and firm generation,” he said.
The bill would also institute a firming or reliability requirement “in a nondiscriminatory manner” on a cost-causation basis. Procurement costs for ancillary and reliability services would be allocated to both dispatchable and non-dispatchable resources and LSEs “in proportion to their contribution to net load variability over the highest 100 hours of net load in the preceding year.”
SB2015, authored by King, would require the Public Utility Commission to monitor each generation company, municipal utility or cooperative operating in the state and to ensure they meet the legislature’s intent that 50% of capacity installed in Texas after 2023 is dispatchable.
The bill would also direct the PUC to establish a dispatchable generation (e.g., natural gas) energy credits trading program. Power providers that are short of the 50% requirement would be required to purchase enough credits to satisfy the requirement.
A second King bill, SB1287, would set a cap on the cost Texans pay when new generation is interconnected to the grid, the idea being to site them closer to existing transmission.
“Everything above, that is going to be paid for by the company that’s building that power facility,” King said. “That will be a tremendous incentive to better site those instead of going out and looking for the cheapest land, which often ends up in a very remote area.”
Other bills include:
SB2010, which would require ERCOT’s Independent Market Monitor to immediately report any potential market manipulation or rule violations to the PUC;
SB2011, which would update voluntary mitigation plan requirements to protect ERCOT’s wholesale market against market power abuse;
SB2012, which would add guardrails to the PUC’s proposed performance credit mechanism to ensure any rate increases are “manageable and go directly toward improving reliability through dispatchable generation”;
SB2013, intended to protect the grid against sabotage and hostile foreign powers; and
SB2014, which would eliminate a state subsidy paid by state consumers to renewable generation.
The bills were filed by Friday’s deadline. Any legislation will have to be coordinated with the House State Affairs Committee, chaired by Rep. Todd Hunter (R), who has positioned himself as a protector of consumer costs since the 2021 storm.
PJM’s real-time load-weighted average LMP for 2022 was a record-high $80.14/MWh, more than double that of 2021, the RTO’s Independent Market Monitor reported Thursday.
The 101.4% increase was itself a record, beating 2021’s 82.8% increase from 2020, during which prices were at their lowest amid the COVID-19 pandemic. (See PJM Monitor: Prices, Coal Power Bounced Back in 2021.)
The previous high was in 2008, which saw an average LMP of $71.13/MWh. Monitoring Analytics’ annual State of the Market report attributed nearly two-thirds of the increase to rising fuel costs, particularly for coal and natural gas, the prices for which doubled in the eastern part of the RTO’s footprint.
Real-time hourly average load only increased by 1.5%. While there was an increase in data center load, this was offset by increased use of behind-the-meter solar, according to the report.
The rise in fuel prices was from an increase in global demand for both coal and gas, Monitor Joe Bowring said during a press conference Thursday.
“The cost of coal was up very dramatically,” he said, citing the closures of coal mines in the U.S. Meanwhile, the U.S. exported more LNG last year, he said.
Nevertheless, the Monitor found the results were indicative of a competitive market.
“Market performance was evaluated as competitive because market results in the energy market reflect the outcome of a competitive market, as PJM prices are set, on average, by marginal units operating at, or close to, their marginal costs in both day-ahead and real-time energy markets, although high markups for some marginal units did affect prices,” the Monitor said.
But as he has in the past, Bowring noted that “during extreme weather” — such as the December winter storm, also known as “Elliott” — “there is market power being exercised on the gas side. And that’s outside our direct bailiwick, but nonetheless, we believe that’s something [FERC] needs to pay attention to.”
Bowring also criticized components of how PJM forms LMPs. “Largely because of Elliott … we see emergency demand response contributed 4.3% [of the increase over 2021]. … We don’t think that’s the way it should work.” The transmission constraint penalty factor’s contribution of 3.2% is “a result of PJM de-rating transmission lines in a way that it shouldn’t do.” And 12% was market power-related, which “obviously we don’t think that should occur,” Bowring said.
Capacity Performance a ‘Failed Experiment’
The Monitor found the performance of PJM’s capacity market to be overall competitive in 2022, but Bowring noted that the analysis did not include the latest Base Residual Auction, the results for which were released in February after a delay. (See PJM Capacity Prices Jump in 5 Regions.)
Still, Bowring said that generators’ performance during Elliott indicated that the Capacity Performance construct — a response to an extreme cold weather event in 2013/14 — has not worked as intended. PJM has said that generators may face penalties totaling between $1 billion and $2 billion for as much as 46,000 MW in capacity being offline during the late December storm, including more than one-third of gas resources.
“The CP design is a failed experiment,” the report says. “The fundamental mistake of the CP design was to attempt to recreate energy market incentives in the capacity market. The CP model was an explicit attempt to bring energy market shortage pricing into the capacity market design.”
“Given that the market seller offer cap has already been removed by FERC,” Bowring said, “the remainder of the fundamental element of the [CP] design should be removed. The whole notion of PAIs [performance assessment intervals] and having these extreme penalties … putting resources at risk, creating this huge administrative nightmare for PJM, including subjective elements of when PAIs occur … it’s simply not a rational way to run a market.”
The Monitor also highlighted its concern with the amount of capacity at risk of retirement by 2030: about 51.8 GW. For comparison, it noted that about 47.5 GW retired between 2011 and 2022.
Of the amount the IMM says is at risk, about 23.5 GW is for regulatory reasons. The plants are primarily coal, Bowring said, and the regulations are primarily from EPA.
PJM and the agency have been working together to “try and ensure that all the resources don’t shut down instantly; that resources are given the opportunity to fix their problems, particularly with wastewater treatment, and some have done that,” he said. “Some are not going to do it. So the EPA and PJM have been trying to make sure that any ultimate retirements are spread over time so that they don’t affect reliability.”
Bowring also said that the Monitor is “very concerned about the increase in” reliability-must-run agreements. Some generators “have interpreted the RMR rule as allowing them to recover costs which have already been sunk. …
“So we’re extremely concerned that this high level of retirements could lead to more RMRs, and we think that the PJM RMR tariff needs substantial revision to ensure that units that are required for reliability are paid and paid appropriately — that is, paid every penny of the costs they incur to provide that service, plus an incentive payment — but not paid more than that; not paid two to three times that, which are the kinds of requests we have seen over the last 10 years.”
The EPA is proposing tighter standards on wastewater discharge from coal-fired power plants.
The revised Effluent Limitations Guidelines and Standards would restore and build on standards set under President Obama in 2015 but weakened under President Trump in 2020. The EPA estimates the changes would block the release of 584 million pounds of toxic pollutants per year via three separate waste streams.
Use of coal as a fuel for steam electric generating stations has been steadily decreasing in the U.S., and the proposed changes appear to encourage additional decommissioning, with an exit option for plant operators planning or considering a shutdown or a conversion to a different fuel.
Operators will be eligible for less-stringent wastewater pollution limits if they agree to permanently stop burning coal by 2028. And those that have already complied or are in the process of complying with the 2015 or 2020 requirements will get a pass on some of the new regulations if they plan to stop burning coal by 2032.
The original deadline for the 2028 opt-in has already passed, but the EPA said in a fact sheet that it is aware that additional plant operators would opt in if the deadline were extended as it proposes and said the extension might give some operators the flexibility to cease burning coal earlier than they might otherwise.
Announcing the proposal Wednesday, EPA Administrator Michael S. Regan called it an ambitious step to protect communities from harmful pollution.
Coal-fired plants discharge large amounts of wastewater laced with mercury, other toxic pollutants, nutrient pollution and dissolved solids, the EPA said.
The proposal would address three waste streams from combustion — flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate — and pave the way for potentially stricter discharge standards on surface impoundments such as ash ponds.
The EPA offers four sets of options in its proposal. It estimates the total social costs of its preferred option at $200 million and total monetized benefit at $1.56 billion, plus unquantifiable benefits such as habitat improvement for aquatic life.
In its impact analysis, the EPA projects a 0.1% nationwide reduction in generating capacity and 0.1% increase in production costs by 2030 as a result of plant slowdowns or shutdown under its preferred option. Depending on the region, that could mean a residential bill increase anywhere from 9 cents to $1.31 per household per year, the EPA estimates.
The rule was originally issued in October 1974. It was amended four times through 1982, then not again until 2015. After two legal challenges, EPA in August 2020 revised it again, changing limits on the flue gas desulfurization and bottom ash transport wastewater discharge.
Five months later, on his first day in office, President Biden issued Executive Order 13990, ordering the EPA to review all regulation and policy actions taken under President Trump and to revoke or revise any that did not protect public health and the environment.
The EPA’s move to reaffirm Mercury and Air Toxics Standards for power plants was one result of that order. (See EPA Reaffirms Power Plant Mercury Regulations.) The new wastewater regulations proposal announced Wednesday is another.
The EPA will soon post details on virtual public hearings planned April 20 and 25.
A federal jury in Cincinnati on Thursday found former Ohio House Speaker Larry Householder (R) guilty of racketeering conspiracy in connection with nearly $61 million FirstEnergy paid a dark money group controlled by him to win passage of legislation authorizing a $1.1 billion public subsidy for the utility’s two uncompetitive nuclear power plants in northern Ohio.
Also found guilty as a co-conspirator was former Ohio Republican Party Chairman Matt Borges for his role in lobbying lawmakers to approve H.B 6 in 2019 and to help defeat a referendum petition overturning the legislation in 2020.
Two other co-conspirators pled guilty to lesser charges and testified against Householder and Borges. A fifth defendant and top Ohio lobbyist died by suicide in 2021.
The jury deliberated about nine hours following the seven-week trial that included hundreds of documents.
FirstEnergy in July 2021 agreed to pay a $230 million fine in a deferred prosecution agreement that included its willingness to assist federal prosecutors. (See DOJ Orders $230 Million Fine for FirstEnergy.) The company fired its CEO and up to half-dozen others following internal investigations in the last two years.
In March 2021, Ohio lawmakers reversed the nuclear bailout subsidy with passage of a bill that continued a public bailout of two aging coal-fired power plants owned by the Ohio Valley Electric Corp. (See Ohio Lawmakers Repeal Nuclear Subsidy for Energy Harbor.)
After the FBI arrested Householder and his four associates in July 2020 pre-dawn raids, the office of the U.S. Attorney for the Southern District of Ohio called the months-long investigation the largest public corruption case in the state’s history.
Following the verdict Thursday, U.S. Attorney Kenneth Parker said in a prepared statement Householder “illegally sold the state house, and thus he ultimately betrayed the great people of Ohio he was elected to serve. Matt Borges was a willing co-conspirator, who paid bribe money for insider information to assist Householder.”
The Justice Department said that, beginning in March 2017, Householder began receiving quarterly $250,000 payments into the bank account of Generation Now, a 501(c)(4) he controlled, from FirstEnergy and its subsidiary FirstEnergy Solutions, operator of the power plants at the time.
Both defendants plan to appeal the conviction and remain free on bond. A sentencing hearing has not been set.
The West Virginia Public Service Commission has filed a complaint with FERC alleging that PJM is violating its tariff by not granting the PSC access to the RTO’s Member Liaison Committee (EL23-45).
“PJM’s refusal to allow the PSC access to discussions with the PJM Board that can be observed by electricity producers, transmission companies and other market participants is wrong,” PSC Chair Charlotte Lane said in a press release announcing the complaint.
“This compromises the PSC’s ability to understand the full range of underlying factors and special interests driving PJM decisions so that it can be fully armed to protect the West Virginia electric customers in grid decisions, as well as in decisions we make in regulating West Virginia electric utilities,” Lane said.
Along with other state regulators, the commission had been permitted to attend LC meetings from 2011 through 2018. But in September 2018 the Members Committee voted to enforce the LC’s charter to restrict attendance to members of the RTO and PJM’s Board of Managers, locking out state commissions, FERC staff, the Independent Market Monitor and the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Table WVa PSC Attendance at Liaison Committee.)
“We are disappointed that PJM has required the PSC to take this extraordinary step in filing a complaint to access information needed to protect West Virginia electric customers,” Lane said in the release.
The PSC complains that PJM’s tariff and past FERC transparency rulings require that ex officio, nonvoting members must be allowed to observe the LC meetings and that prohibiting their attendance violates the non-discrimination provisions of the Federal Power Act sections 205 and 206. It notes that PJM continues to allow other ex officio members, namely state consumer advocates, to attend the LC given their status as voting members of PJM’s standing committees and makes the case that there is no reason to not allow state regulators as well, as the LC is not a voting committee.
After being told that it was not allowed to register for LC meetings in August 2018, the PSC attended two MC meetings in September and November 2021 to make the case for its right to attend. While a motion was made during the Nov. 17 meeting, stakeholders narrowly voted to indefinitely postpone voting on the matter.
“Indeed, the Liaison Committee Charter makes clear that the Liaison Committee does not ‘vote’ on matters, but rather exists to improve transparency between the Board and the members. There is thus no reason to distinguish between voting and non-voting ex officio members of PJM regarding their rights to attend and observe the Liaison Committee meetings,” the complaint states.
PJM spokesman Jeff Shields responded that the RTO “is fully compliant with its governing documents on this issue. Participation on the Liaison Committee is determined by members, who did not support participation by the West Virginia Public Service Commission when it was brought before the Members Committee in November 2021.”
The PSC argued that knowledge of the meeting’s proceedings is necessary to allow it to fulfill its mandate to protect consumers’ interests, since FERC-regulated utilities operating in West Virginia may participate in the meetings and have an opportunity to advocate before the PJM board for market rules that are not in the state’s interests.
“The statements made by those utilities to the PJM Board and the positions they take before the Board are matters of unique and critical interest to the PSC WV given the state regulatory commission’s obligation to oversee the actions of those West Virginia-jurisdictional utilities and the positions they take in discussions with an entity charged with overseeing the markets and transmission operations for their utility operations in West Virginia,” the PSC wrote. “Absent the right of the PSC WV to attend those meetings, it would be unable to discern what the West Virginia jurisdictional utilities were telling the PJM Board of Managers regarding issues of critical importance to regulation of utility operations in West Virginia.”
The PSC said attending the LC meetings “is critical to its ability to ensure service reliability and affordability in West Virginia, especially during the market’s transition to renewable energy resources.”
MISO Senior VP Todd Ramey | © RTO Insider LLC
