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August 15, 2024

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PJM CEO, Panelists Address Reliability During Annual Meeting

CAMBRIDGE, Md. — Opening PJM’s Annual Meeting on May 1, CEO Manu Asthana said organized markets and planning have continued to stand the test of time, but challenges lie ahead as stakeholders wrestle with a possible overhaul to the capacity market to address future resource adequacy concerns, in part sparked by the impact of the December 2022 winter storm.

“Just within PJM we estimate our markets … bring in $4 billion in value each year to customers and producers. I know there’s a lot of rhetoric lately about RTOs and organized markets, and I just want to say RTOs and organized markets are” efficient and transparent, Asthana told the Members Committee at the meeting.

Though this is not the first time PJM has experienced a major energy transition, pointing to the shift from coal to natural gas for generation, Asthana said the clean energy transition presents a new, global challenge that will require the RTO to continue to evolve.

The need to interconnect more renewable energy could be exacerbated by a significant number of generation retirements that are expected through 2030, Asthana said, referencing PJM’s February Resource Retirements, Replacements & Risks (4R) report, as reserve margins are expected to shrink because of electrification and data center load growth.

The winter storm, also known as “Elliott,” underlined many of those concerns, leading PJM’s Board of Managers to initiate a Critical Issue Fast Path (CIFP) process in February to gather stakeholder proposals for the board to consider later this year. That process is currently in the second of four phases. (See PJM Stakeholders Refine CIFP Capacity Market Proposals.)

Though the storm was within the studied conditions that could be expected within PJM, Asthana said it was concerning that emergency procedures were required to meet load during the storm, and it’s necessary to now think about what can be done differently to not get as close to the edge next time.

“The question is, did our Capacity Performance [CP] rules work as intended? … I think it’s important that we look at that and think about that,” he said.

Last year’s FERC approval of a new system for handling interconnection requests — allowing PJM to work through its queue backlog quicker — will go a long way toward navigating the transition, Asthana said. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

“That complicated piece of work is a big deal for us. It is a big deal from a reliability perspective. It is a big deal from an energy transition perspective. It is a big deal from the perspective of helping our states and our members reach their energy transition goals,” he said.

PJM’s State Agreement Approach (SAA) has also proven itself to be a valuable tool for states to work with the RTO to meet their clean energy goals, he said. New Jersey received FERC approval for the cost allocation portion of its first SAA process to construct the transmission necessary to interconnect 7,500 MW of offshore wind. The state announced a second SAA process with the goal of developing 11 GW of offshore wind capacity by 2040. (See NJ BPU Backs Plan for 2nd Grid Upgrade Process with PJM.)

MC Chair David “Scarp” Scarpignato said Elliott was both an accomplishment for PJM and a struggle: The RTO kept the lights on while managing to provide aid to surrounding regions, but it laid bare unforeseen reliability issues. While a sudden emergency hasn’t occurred recently, it remains a real risk, and stakeholders must consider changes to price signals, a “circuit breaker” system for limiting extended periods of high pricing and the market seller offer cap, he said.

“Last year, the defining accomplishment or struggle for PJM at large was Elliott and how well our market reliability procedures and rules worked,” he said. “We, collectively, did keep the lights on.”

Panel Discusses Future Reliability Landscape

Independent Market Monitor Joe Bowring and PJM administrators shared how they’re working to maintain reliability through the clean energy transition through state, market, operations and planning initiatives.

Asim Haque, PJM vice president of state policy and member services, outlined the series of “Energy Transition in PJM” reports the RTO is publishing, detailing the challenges presented by the transition and possible solutions. The first iteration, “Reliability in PJM: Today and Tomorrow,” was released in March 2021, while the 4R study earlier this year was the most recent. He categorized the identified reliability concerns as immediate, largely pertaining to Elliott; near term, relating to resource adequacy in the latter portion of this decade; and upcoming, which includes essential reliability services.

“We do believe we are relatively well positioned today, but we are concerned this position may not hold for the not too distant future … so we feel some sense of urgency to act to maintain reliability,” Haque said.

In visiting state legislatures, he found that each have their own priorities but are all bound together by a desire for reliability. He recounted telling states that regardless of their individual goals, it is a reality that PJM’s interconnection queue is primarily composed of renewable resources, and planning the future of the grid will have to reflect that.

“The finding that most directly impacts reliability as we transition to greater renewable penetration is the conclusion that we will continue to need our thermal resources and the essential reliability services they provide in order to preserve reliability until a replacement technology for these resources is deployable at scale,” he said.

Senior Vice President of Operations Mike Bryson said there have been multiple retirements announced since the 4R study that weren’t anticipated during the document’s drafting, and some scenarios for this summer are showing operating reserve shortages this summer for the first time he can remember. The reliability-must-run (RMR) system is one potential area for improvement, as he believes there may be a more significant need for those contracts in the future.

Bowring said increasing reliance on RMR agreements could create an incentive to retire, and they should be used with caution. Bryson said they offer a benefit in allowing some flexibility in addressing policy retirements that could impact reliability, an area that cannot be met through market changes.

Ensuring the right types of reserve products and all necessary characteristics are being captured in offers and procured is critical to provide dispatchers assurance that when they call on resources, they will receive what has been committed, said Vice President of Market Design and Economics Adam Keech. The transition provides an opportunity to use markets to shape the grid of the future, focusing on flexibility and providing incentives as a proactive solution.

“Now is the time to use the markets proactively to send the right signal, so we attract the right resources we need,” he said.

Bowring said Elliott showed the flaws of having energy market incentives manifest in the capacity market and that extreme prices and penalties can have a destructive effect. He cautioned against creating new cost-of-service constructs as a reaction to the storm, saying that wouldn’t promote reliability; market solutions should be sought instead.

Vice President of Planning Ken Seiler said PJM is potentially on track to complete interconnection studies on projects with a nameplate capacity equal to resources expected to retire in the coming years, but much of that new generation is intermittent, which will push the RTO to change how it acts under various system conditions.

The first-come-first-serve interconnection model approved by FERC last year allows PJM to transfer the capacity interconnection rights of generators that complete the study process and receive an interconnection service agreement (ISA) but do not complete construction within a year. Seiler said PJM has seen a large number of projects that receive ISAs but haven’t entered construction.

Stakeholders Approve New Terms for 3 Board Members

The MC voted to reseat three board members whose terms expired: Jeanine Johnson, Margaret Loebl and Charles Robinson.

The committee also elected Vickie VanZandt to continue filling the remaining year left on the term previously held by Sarah Rogers, who retired in September 2022.

Johnson brings a background in cybersecurity and product design to the PJM board, to which she was elected in 2021, according to PJM’s biographies of the candidates. She was shortlisted as Entrepreneur of the Year by the Women in IT Awards for co-founding a company commercializing a product to create drinking water.

Loebl has held officer positions in finance at several companies, most recently serving as executive vice president and CFO at AgroFresh Solutions, and has worked with the board of companies on acquisitions, strategy, controls infrastructure and risk management, according to her biography. She was elected to the board in 2020.

First elected in 2011, Robinson serves as general counsel for the Regents of the University of California and was previously general counsel for CAISO. He has also served as a senior attorney for several companies, including Packard Bell and Raychem Corp.

President of VanZandt Electric Transmission Consulting, VanZandt was appointed to the board in 2022. She previously served as the senior vice president and chief engineer of transmission services for the Bonneville Power Administration and served on the ISO-NE Board of Directors.

States Argue Board Didn’t Consult Membership on Auction Delay

The MC voted to approve the minutes of its special meeting held April 4, but five states objected to them because they stated that PJM provided an update on the Base Residual Auction schedule and consulted with membership on delaying upcoming auctions.

The board is required to consult with stakeholders prior to making any Federal Powers Act Section 205 filing under the RTO’s tariff. PJM made a Section 205 filing to delay future auctions following the meeting on April 11 (ER23-1609).

“The board members weren’t present to have that discussion, so it was kind of a misrepresentation of what that meeting would entail,” said Gregory Poulos, of the Consumer Advocates of the PJM States. He added that the objecting states didn’t believe that it constituted an adequate consultation.

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PJM MRC Endorses Proposal to Reduce Performance Penalties

The Markets and Reliability Committee on Thursday endorsed a proposal to reduce penalties for generators that don’t meet their capacity obligations during performance assessment intervals (PAIs).

The package, made by American Municipal Power, redefines the penalty rate and the stop loss limit — the maximum a generator can be penalized in a year — to both be based on the Base Residual Auction (BRA) clearing price. It would also reduce the circumstances under which PJM can declare a PAI.

Both the penalty rate ($3,177/MWh) and stop loss ($142,952/MW-year) are currently based on the net cost of new entry (CONE). AMP’s proposal would reduce them to $394/MWh and $17,744/MW-year, respectively. The change would be effective through the 2024/25 delivery year. (See “Capacity Performance Penalties,” PJM MRC Briefs: April 26, 2023.)

The AMP proposal was one of three before the MRC during a May 4 special meeting, with LS Power and the Independent Market Monitor also making presentations. The subject was brought before the MRC by LS Power through the quick fix process, allowing the issue charge and problem statement to be considered simultaneously with the proposed rule changes. The Members Committee is set to consider endorsement of the AMP solution on May 11.

The LS Power proposal retained the $3,177/MWh status quo PAI charge rate but set the stop loss limit to twice the BRA clearing price, or $23,659/MW-year. All three proposals included the same PAI trigger.

Monitor Joe Bowring said LS Power’s proposal would result in the annual limit being reached very quickly, defeating the purpose of the penalties. The IMM’s proposal used the same penalty rate as AMP and the same stop-loss formula as LS Power. It did not receive a vote because AMP’s plan was approved.

According to the sector-weighted vote report, the Electric Distribution sector unanimously opposed the LS Power proposal, which was voted on first, but gave full support to the AMP solution. The Transmission Owner and End Use Customers sectors also gave majority opposition to the LS Power package and supported AMP.

During a May 1 special MRC meeting, LS Power’s Marji Philips said her company’s proposal was a compromise between PJM’s desire to have a higher penalty rate and the goal of many stakeholders of limiting when PAIs can be called and lowering the annual penalty cap. Philips said she would support any of the three options over the status quo, arguing that generators wouldn’t invest in PJM if they were subject to a penalty rate that could wipe out years of capacity market revenues.

PJM General Counsel Chris O’Hara said the RTO strongly preferred the LS Power proposal, largely because it has the highest penalty rate of the three.

“We feel that from an economic perspective and from a legal challenge perspective that if we are going to do something for these two years, we are much more comfortable leaving the penalty rate where it is,” he said during the May 4 meeting.

Reviewing penalty claims from the December 2022 winter storm, he said the capacity performance construct appears to have properly incentivized many generators to make investments to support their capacity obligations. In many cases, circumstances out of generators’ control impacted their ability to perform, he added, saying it makes a case for reducing the stop loss limit.

American Electric Power’s Brock Ondayko said a filing at FERC seeking to modify the stop loss limit would likely run into challenges that it constitutes retroactive ratemaking. He said generators expected to overperform their capacity obligation may have made offers based on the assumption that they were likely to receive a certain amount in bonuses in a year.

Vitol’s Jason Barker said reducing the penalty rate or stop loss limit effectively shifts the performance risk from a financial risk faced by generators to a reliability risk across PJM. Rather than a separate process addressing penalties for upcoming delivery years, he encouraged stakeholders to vote against all three and instead seek a solution through the ongoing critical issues fast path (CIFP) process. If an interim solution were to go forward, he said one limited to just modifying the PAI trigger would be preferable. (See PJM Stakeholders Refine CIFP Capacity Market Proposals.)

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California Faces Challenges Connecting 156 GW to Grid

Participants in a California Energy Commission workshop last week wrestled with the question of how the state can interconnect huge quantities of new storage and generation resources to its transmission grid in the next two decades to meet its climate goals.

State statutes require load-serving entities in California to serve retail customers with 90% carbon-free electricity by 2035 and 100% by 2045, while reducing greenhouse gas emissions to 40% below 1990 levels by 2030 and 85% below 1990 levels by 2045.  

“The punchline, of course, is that we need 86,000 MW added to our grid in 12 years,” said Sharon Eddy, executive director of the Large-scale Solar Association. “We need another 70,000 MW in the 10 years after that” to meet the 100% clean energy goal established by Senate Bill 100 in 2018. “This is unprecedented.”

The state’s transmission system needs major upgrades and additions in a relatively short timeframe to handle so much new capacity, panelists said in the workshop.  

“Our current transmission grid can’t accommodate an additional 86,000 MW without new lines, new poles, new substations, and we need it quickly,” Eddy said.

“Everyone is running into the fact that we just didn’t plan early enough to build out the transmission system,” she said. “The challenge isn’t that we have too many projects vying for too little grid space, it’s that our entire system and our planning processes weren’t set up to handle this kind of accelerated growth.”

541 Interconnection Requests

CAISO adopted what it called a “more strategic and proactive approach” to interconnections in its 2022/23 transmission plan, which identified 46 transmission projects costing $9.3 billion that California needs by 2032 to incorporate more than 40 GW of renewable resources. (See CAISO Retools Transmission Plan for Reliability, Renewables.)

Future transmission plans will have to address portfolios from the California Public Utilities Commission (CPUC) that call for adding 70 GW of new resources by 2033 and 86 GW by 2035, CAISO said.

The 2022/23 transmission plan broke with tradition by analyzing projected resource additions within 14 transmission interconnection zones. CAISO said the “zonal” approach will allow it to deal more efficiently with interconnection requests, which it previously evaluated in annual cluster studies.

Interconnection requests to CAISO have soared in the last three years, from 155 in 2020, to 373 in 2021, to 541 this year, in clusters 13, 14 and 15, respectively. This year’s requests totaled 354 GW on top of the 180 GW already in its queue, including 18 GW of requests for a single substation, CAISO said.

Performing cluster studies on “such a huge volume is inefficient and provides less meaningful study results,” said Neil Millar, CAISO vice president of infrastructure and operations planning. “This clearly calls on us to take action and move forward with more substantive, transformative changes, better prioritizing where we’re putting our energies.”

The ISO’s new zonal approach targets “energy rich zones” with current or anticipated transmission connections where CAISO wants utilities and resource developers to focus their efforts, Millar said.   

“We’re talking about volumes being required in next year’s transmission plan of over 7,000 MW of installed capacity to be added to the grid each year for the foreseeable future,” Millar said. “The challenge would be to maintain that pace year over year, which our current processes were not designed around.”

Transmission-owning utilities such as Pacific Gas and Electric also have been inundated with interconnection requests.

“For many years up to cluster 13, the number of applications never exceeded more than 70 and [involved] less than 20,000 MW,” said Marco Rios, PG&E’s manager of transmission planning. “That wasn’t the case in cluster 14, where we received 185 applications and over 46,000 megawatts of generation just in the PG&E system. That makes the study process very, very difficult.”

PG&E used to have a high withdraw rate, but fewer developers are withdrawing their projects from the queue, compounding the problem, he said.

‘Promising if Arcane’

The afternoon sessions of the all-day workshop dealt with possible solutions.  

Representatives of wind, solar and storage trade organizations urged CAISO to revise its generation deliverability study methodology.

Nancy Rader, executive director of the California Wind Energy Association, called it a “very promising if arcane topic.”

“Reforming that methodology could really accelerate generator interconnections and make more efficient use of our existing grid and every additional transmission project that we build,” Rader said.

The ISO launched a stakeholder initiative in December to review its deliverability methodology, she said.  

“CAISO uses this methodology to determine what reliability upgrades are needed for an interconnection customer to obtain deliverability capacity … which is what generators need to qualify under the CPUC’s resource adequacy program,” Rader said. “The point of the methodology is to ensure that a project will be able to deliver its generation to load when it’s needed.

“The prospect of reforming this methodology is exciting because it could immediately address the current lack of available [deliverability] capacity” on transmission lines, she said. “Without it, projects can’t qualify for RA and generally won’t be commercially viable. And so, in our view, the available capacity appears to be insufficient to meet the state’s mid-decade and certainly our longer term SB 100 goals. And that will remain the case until new transmission is planned and built and that’s about 10 years off…”

CAISO currently uses a more restrictive methodology for assessing deliverability capacity than other RTOs, Rader said. Adopting less stringent criteria such as that used by PJM and MISO could “free up more than 10 GW of capacity immediately across the CAISO grid in areas … where the grid is strong,” she said.

“Capacity is a function of the assumptions used in the CAISO’s deliverability study methodology, and in our view those assumptions are unnecessarily conservative,” she said. “Reforming those assumptions consistent with those used by PJM and MISO could dramatically expand [deliverability] capacity. And that capacity would immediately become available at no cost.

“So, we really might have a big free lunch here,” she said.

Rader said she and others were looking forward to discussing the issues in CAISO’s upcoming stakeholder process.

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Constellation CEO: Nuclear PTC Could Extend Reactors’ Life to 80 Years

The Inflation Reduction Act’s production tax credits for nuclear could boost Constellation Energy Group’s (NASDAQ:CEG) profits by $100 million annually beginning in 2024 and help extend the life of its reactors to 80 years, CEO Joseph Dominguez said during the company’s 2023 first quarter earnings call on Thursday.

Nuclear represents about 86% of the terawatt-hours of power Exelon’s spin-off independent power producer generates for its customers, according to the company website. The PTC, which could provide up to $15/MWh for plants not already receiving state support, “provides downside commodity risk protection … while ensuring that our plants remain economic and reliable,” Dominguez said.

“Other provisions in the IRA create unique growth opportunities, like increasing the output from our nuclear plants through upgrades and hydrogen [production],” he said. “And finally, it gives us the opportunity to extend  the time horizon of our fleet to 80 years. … No other clean energy assets can run this long without being replaced.”

The company began producing zero-carbon hydrogen at its Nine Mile Point nuclear plant in Oswego, N.Y., in March. The 1-MW hydrogen production facility was a joint demonstration project of Constellation and the Department of Energy. (See Megawatt-scale Demonstration Project Yields First Pink Hydrogen.)

“The clean hydrogen generation system operating at Nine Mile Point uses 1.25 MW of zero-carbon energy per hour to produce 560 kg of clean hydrogen per day, more than enough to meet the plant’s operational hydrogen use” to cool the facility, according to a company press release on the project.

Constellation also said it will invest $900 million through 2025 to develop and scale commercial clean hydrogen production using nuclear power.

Marking just over a year since its separation from Exelon, Constellation reported first-quarter GAAP net income of $96 million versus $106 million in the first quarter of 2022. Adjusted (non-GAAP) EBITDA was $658 million, down from $866 million.

The lower 2023 figures were partially caused by higher energy prices in 2022 and increased refueling outages and labor costs as Constellation has been increasing staff, said Daniel L. Eggers, executive vice president and chief financial officer.

Dominguez was nonetheless upbeat about the quarter’s results, saying the company expects “we will end the year comfortably in the top half of our guidance range” of $2.9 billion to $3.3 billion.

It declared a dividend of 28.2 cents/share in the first quarter, about twice the payout in the first quarter of 2022.

The Nuclear Edge

While Constellation is now separate from Exelon, which reported its first-quarter results one day earlier, both companies are positioning themselves as key players in the U.S. energy transition, providing carbon-free power to a broad range of residential and commercial customers. (See Exelon CEO: Energy Transition ‘Requires Investments,’ Rate Increases.)

With its large nuclear fleet — 12 plants with 21 reactors — and smaller amounts of solar and wind, Constellation boasts that it is currently producing 90% of its power from carbon-free sources. All of the generation it owns will be 100% carbon-free by 2040, it says.

Dominguez said the company provided 11% of the country’s clean power in 2022, serves 25% of the competitive commercial and industrial market and numbers 75% of the Fortune 100 among its commercial customers.

He also stressed nuclear’s reliability in the face of the increasing number and severity of extreme weather events.

With electric generation shifting toward more intermittent renewables, anyone participating in retail or wholesale markets has “to ask yourself really three basic questions,” Dominguez said. “Do I have physical generation? Is it the kind of physical generation that is going to show up in extreme events? And do I have the financial balance sheet to deal with negative outcomes?”

How the PTC Will Work

The nuclear PTC does not kick in until 2024, when Constellation anticipates four of its 12 plants will be eligible for the credit: Calvert Cliffs in Maryland, LaSalle in Illinois, and Limerick and Peach Bottom in Pennsylvania.

Payoff Dynamics (Constellation Energy) Content.jpgThe IRA’s production tax credit for nuclear will help Constellation top up its revenues from nuclear plants not already receiving state subsidies. For example, if the company is getting $35/MWh at a plant, the PTC will add $7/MWh to ensure a total of $42/MWh. | Constellation Energy

The credit is designed to ensure nuclear owners are getting around $40/MWh for their power, with the amount of the credit a specific plant gets hinging  on market prices. The credit phases in at $25/MWh and phases out at $43.75/MWh, Constellation said.

In a hypothetical example, the company assumes prices at $35/MWh, with the PTC then kicking in $7/MWh, to ensure a total of $42/MWh.

In such a situation, Eggers said, “The PTC is functioning as it should, stepping in to provide downside protection.”

Dominguez was confident that IRA tax credits would not be lost in any deal over the debt ceiling now being debated between the White House and congressional Republicans.

“We just see that as — it’s hard to use the word ‘normal’ — the political back-and-forth that’s occurring,” he said. “I don’t think there’s any prospect that President Biden is going to cut or gut the IRA to deal with this issue.”

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Coalition Promotes US-Canadian Offshore Transmission Link

An industry coalition is promoting the concept of underwater transmission linking New England and Nova Scotia with each other via wind farms off their respective coasts.

The shared infrastructure, they say, would help both regions meet their climate-protection goals in the coming decades.

The New England-Maritimes Offshore Energy Corridor last week released a report on the concept prepared by risk-management company DNV and electric consulting firm Power Advisory.

It is not a business case for building such a power line; it was intended to show its potential benefits, rather than quantify them.

But the benefits would be spread among multiple parties, the report’s authors write, so for a proposal to attract investment, they must be quantified and recognized in the cost-allocation process.

The long, windy coast of New England is expected to play a critical part in that region’s clean energy drive, with Massachusetts alone targeting 5,600 MW by 2027 and other states hoping developers will install thousands more megawatts.

Nova Scotia’s provincial government wants to offer leases for 5 GW of OSW between 2025 and 2030 to support its budding green hydrogen industry.

Transmission between the two sets of offshore wind arrays could both enhance grid reliability and provide economic benefits, the authors said. Nova Scotia turbines could export to ISO-NE during high-priced hours, and wind turbines in the Gulf of Maine could export to Nova Scotia to reduce curtailment.

Weighing against this are multiple challenges: the multijurisdictional permitting of such a line, its non-traditional value proposition and its significant cost: High-level price estimates range from $6.4 billion to $8.3 billion (USD).

Government financial support would be needed. Meanwhile, the floating turbine technology that would be required in the deep water of the Gulf of Maine is still being developed, and the supply chain to manufacture its components is facing yearslong delays.

NEMOEC comprises:

      • Atlantic Canada Offshore Development, a joint venture of Copenhagen Investment Partners and Shell Canada to explore the potential for OSW in Canada’s Maritime provinces;
      • hydrogen and ammonia developer Bear Head Energy, a subsidiary of BAES Infrastructure;
      • Ireland-based renewable energy developer and operator DP Energy;
      • floating wind developer Hexicon;
      • transmission line developer Grid United;
      • Canadian power producer Northland Power; and
      • floating offshore wind developer TotalEnergies SBE US, a partnership between TotalEnergies and the Simply Blue Group.
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Climate Advocates Ask FERC to Reject ISO-NE Capacity Results

Environmental activists asked FERC on Friday to reject the results of ISO-NE’s Forward Capacity Auction 17, saying continued payments to fossil fuel generators is a risk to ratepayers and the climate.

The March 6 auction for the 2026/27 procurement period saw a slight increase in non-emitting generation obligations but still resulted in over three-quarters of the total obligations going to fossil fuel generation. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.)

ISO-NE filed the results on March 21, asking the commission to find them just and reasonable and in accordance with the RTO’s tariff (ER23-1435).

More than 160 individuals and organizations wrote comments opposing the auction’s results. No Coal No Gas, a New Hampshire-based campaign to end fossil fuels that recently elected an activist slate of candidates to the Consumer Liaison Group’s (CLG) Coordinating Committee, coordinated the effort to reject the results. (See Climate Activists Take Over Small Piece of ISO-NE.)

“Based on blatantly inaccurate assumptions about the capacity, reliability and sustainability of fossil fuel-powered generators, the FCA 17 results not only violate ISO-NE’s mandate, but also call into question the legitimacy of the [Forward Capacity Market] as a whole,” the group wrote in its comments. “Thus, the arguments made in No Coal No Gas’s protests and comments are directly relevant to whether the ISO-NE followed its tariff when it conducted FCA 17.”

The group noted that the Merrimack Station did not win a capacity supply obligation, saying it was “grateful that our utility bills will not be used to subsidize coal as of June 2026.”

But it lamented that the auction “awards hundreds of millions of ratepayer dollars to keep the oldest, dirtiest, least economical fossil fuel-powered generators online for use as peaker plants. By propping up these failing fossil fuel-powered generators as standby peaker plants and sending bonus payments to base load generators, ISO-NE is preventing a just transition on our dime, and we call on FERC to intervene.”

The organization highlighted a 2019 white paper commissioned by the Sustainable FERC Project that found that capacity markets like those run by ISO-NE “have built-in biases against renewable energy.”

Commenters also criticized the structure of ISO-NE, arguing that the Forward Capacity Auction is part of a broader bias within the RTO favoring existing fossil fuel generators and providers.

“The current status quo financial subsidies and broken rules of ISO’s transmission grid has created a state of high ratepayer financial and physical vulnerability,” wrote Nathan Phillips, a Boston University ecology professor and one of the recently elected members of the CLG coordinating committee. “ISO-NE’s corporate arm, NEPOOL, is set up so that ratepayers are only one-sixth of the stakeholder groups involved in the grid.”

The Berkshire Environmental Action Team also filed comments in opposition, saying ISO-NE should “also aggressively prioritize demand response and other efficiency programs, and engage ratepayers in programs designed to reduce demand during peak events on the grid.”  

Several companies with a financial stake in the auction — including Eversource, National Grid, Calpine, Dominion and Constellation — filed motions to intervene in the proceedings, though none filed comments.

ISO-NE has requested FERC rule on the auction results with an effective date of July 19.

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Wash. Allocates Millions from Cap-and-Trade Fund

A new pumped storage site, an undetermined number of solar farms and agrivoltaic ventures are among the projects for which Washington is allocating $300 million.

Washington’s first cap-and-trade carbon allowances auction in February raised $300 million for the state’s coffers. (See Washington Confirms $300M Take for 1st Cap-and-Trade Auction.)

Near the end of the legislative session last month, Washington lawmakers divided the $300 million into 188 individual appropriations. Highlights include:

  • $10.7 million to develop agrivoltaic projects, the mingling of solar farms with growing crops and grazing livestock. Washington currently has a small agrivoltaic project operating on the Colville Indian Reservation near the Grand Coulee Dam. In May 2022, the Yakima County government approved BayWa r.e.’s 94-MW Black Rock agrivoltaic solar farm, expected to be completed next year.  
  • $39 million will go to developing solar farms.
  • $40.9 million to help local government add climate planning to their urban growth planning. The Legislature recently passed House Bill 1181, which adds climate considerations to city and county land-use planning.
  • $600,000 to help site new pumped storage projects. The Legislature recently passed HB 1216, which directs the Washington State University Energy Program to develop a pumped storage siting process. Washington has one pumped storage project in the works, which is controversial because part of it would be on land that the Yakama Indian Nation considers culturally sacred.
  • $20 million to help the state’s fledgling hydrogen industry. Washington, Oregon, Idaho and Montana have combined forces to seek at least $1 billion in federal money to create a regional hydrogen hub. Another $3 million will be allocated to build hydrogen vehicle refueling infrastructure. 
  • $50 million for climate change projects for the state’s tribes.
  • $15 million to capture methane rising at the state’s landfills.
  • $50 million to install solar panels on public buildings. 
  • $1.4 million to deal with childhood asthma problems related to jet fumes from SeaTac International Airport between Seattle and Tacoma. 
  • $36 million to build charging infrastructure for electric vehicles.
  • $30 million to build a hybrid electric ferry. Another $180 million is allocated to overhaul ferry docks and terminals to handle electric ferries.

The next quarterly auction is set for May 30.

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Eversource CEO Gives Update on Offshore Wind Sale

Eversource expects to reach a deal this quarter to sell off its offshore wind interests.

CEO Joe Nolan last week said negotiations are far along with two potential buyers.

But the sale will not end its involvement in the offshore sector, he said. Eversource expects to concentrate on the transmission of power generated by fleets of offshore turbines, rather than the turbines themselves.

Nolan’s remarks came Wednesday during a call with industry analysts to discuss the company’s first-quarter earnings.

The question-and-answer portion of the call returned repeatedly to Eversource’s plans to offload its assets in the offshore wind sector, which has experienced rising costs as the first of thousands of megawatts of planned capacity is developed off the Northeast coast.

In Massachusetts, Commonwealth Wind and SouthCoast Wind have both said their projects are now untenable under their existing power purchase agreements, though only Commonwealth has formally attempted to back out.

Eversource teamed up with Denmark’s Ørsted, the largest offshore wind developer in the world, in a 50/50 joint venture to develop South Fork Wind, Revolution Wind and Sunrise Wind. Construction has begun on South Fork and is expected to start later this year on Revolution.

The two have also proposed Sunrise Wind 2 and Revolution Wind 2.

Eversource said over a year ago that it was considering sale. Nolan said Wednesday that negotiations on its leases and contracts are now in late stages.

“Our transaction will involve two parties. It is very far along in the process; that’s why we can tell you with a very high degree of confidence that you will have an announcement in the second quarter,” he said.

Nolan said they will bring a good price.

“These are very mature projects; these are not just concepts on paper … so for that I think we’ll recognize good value for those projects. … I think that at the end of the day it will be a very good outcome for Eversource and for Eversource’s shareholders.”

An analyst asked if the company might retain a smaller ownership share than 50%.

“We see a path for a clean exit from this, so that is definitely not the case,” Nolan said.

Another analyst asked whether Eversource is planning to move into transmission of power from offshore generators.

Nolan replied that the company sees great opportunity to work with Ørsted and other developers to import clean energy to the ISO-NE and NYISO grids.

“That was one of the points that had us make the pivot because we think there’s so much opportunity in both the land aspect of it and the investment around not only the projects that we were involved in, but the projects that everybody else is involved in,” he said. “We are very well positioned in this region at load centers, and people want to get to them. … We see a tremendous opportunity for investment in offshore wind as it relates to our regulated business and that’s really what our focus is — de-risking and focusing on our regulated assets.”

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Inslee Signs Raft of Washington Climate, Energy Bills

A good chunk of Washington’s 2023 climate change legislation was signed into law Wednesday, including a plan to make the state a center for producing sustainable aviation fuel.

“The world is looking at Washington state to lead a clean energy revolution,” Gov. Jay Inslee said Wednesday at a signing ceremony for seven clean energy bills at Energy Northwest’s Horn Rapids Solar Farm in Richland, Wash., a project that in 2020 received financial assistance from the state’s Clean Energy Fund. “What you see behind me is good paychecks for good jobs.”

Inslee noted that Washington’s solar capacity has increased 460% during the past five years.

One passed bill that was noticeably absent from Wednesday’s signing ceremony was House Bill 1173, sponsored by Tri-Cities Rep. April Connors (R), which would limit the blinking red lights on wind turbines to times when low-flying aircraft were near rather than leaving them on through the night. This legislation was the result of many residents objecting to a plan to build a large wind farm in the scenic Horse Heaven Hills area south of the Tri-Cities. There are rumors that wind power interests have been lobbying Inslee behind the scenes to veto the bill.

“I think it is a grand idea, assuming it will work,” Inslee said. “We are just making sure that it does. But we really appreciate everyone looking for a way to minimize the visual disturbance. We think this will be a tremendous benefit.”

Successful Climate Bills

Here is a rundown of climate-related bills passed in the 2023 session, which ended in late April:

Senate Bill 5447, which is intended to make Washington more attractive to the sustainable jet fuel industry.

The new law sets a business-and-occupation tax rate of 0.275% for any plant that would produce at least 20 million gallons a year of low-carbon jet fuel. The rates for most Washington B&O taxes — a levy on a business’ gross receipts — range from 0.47% to 0.9%.

SB 5447’s purpose is to set up a second West Coast alternative jet fuel plant in Washington. A few years ago, the predicted cost of building such a plant was at least $1 billion.

“Air travel is one of the hardest areas to address (in trimming greenhouse gas emissions),” said Senate Majority Leader Andy Billig (D) at the bill signing. “The production is what brings the economic benefits of the jobs. … That’s the promise of the green economy.”

House Bill 1181, which would add climate considerations to city and county land-use planning.

This law changes Washington’s Growth Management Act, which regulates long-range, land-use planning for city and county governments. It requires local governments to review and, if needed, revise their comprehensive plans and development regulations every eight years.

The law requires climate change to be considered in land-use and shoreline planning for the 10 largest of Washington’s 39 counties and in cities of 6,000 residents or larger. The 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland.

Senate Bill 5165, which requires utilities to begin transmission line planning 20 years in advance, along with some technical changes to transmission planning.

A major driver behind this law is that Washington will transition from being a net exporter of power at present to a net importer by 2050 if it is to reach the goal of weaning itself from fossil fuels, according to calculations by the state’s Department of Commerce. As a result, the state needs to dramatically increase its transmission capacity while simultaneously developing more alternative power sources.

House Bill 1216, which creates an interagency council to improve the siting and permitting of clean energy projects.

It also directs the Washington State University Energy Program to develop a pumped storage siting process. Washington has one pumped storage project in the works, which is controversial because part of it would be on land that the Yakama Nation of Indians considers culturally sacred. (See Wash. Bill Seeks to Accelerate Renewable Buildout.)

Rye Development of Boston is hoping to build Washington’s first pumped storage project for $2 billion in southern Klickitat County near the John Day Dam and have it in operation between 2028 and 2030.

That project would include two lined, 600-acre water reservoirs that are 60 feet deep and separated by 2,100 feet in elevation. One reservoir would be on the river shore and the other at the top of a cliff. An underground pipe would connect the two reservoirs with a subterranean electricity generating station along the channel.

House Bill 1176, which creates the Washington Climate Corps Network to develop climate-related service opportunities for young adults and veterans.

House Bill 1416, which requires “market” — or nonresidential — customers of consumer-owned utilities to comply with the greenhouse gas-neutral standard and the 100% clean electricity standard under the Clean Energy Transformation Act.

House Bill 1236, which authorizes all public transit agencies to produce, distribute, use, or sell green electrolytic hydrogen and renewable hydrogen. “Every transit agency has signed on to this bill,” said Rep. David Hackney (D).

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FERC Rejects Protest of SPP PRM Increase

FERC last week rejected a complaint by SPP members seeking to overturn the RTO’s decision last year to increase its planning reserve margin (PRM) from 12% to 15%.

In a 3-1 vote Wednesday, the commission ruled that American Electric Power (AEP), Oklahoma Gas and Electric (OG&E) and Xcel Energy failed to show SPP’s PRM process was unjust, unreasonable, or unduly discriminatory (EL23-40).

Commissioner James Danly dissented from the order, saying FERC had failed to grapple with the complainants’ core point: What must SPP be required to include in its tariff and what can the commission allow to be consigned to business practices or external processes?

The three utilities filed their complaint in February under Section 206 of the Federal Power Act. They argued that the new PRM’s implementation gave them only six months to procure additional capacity necessary to comply with the increased resource adequacy obligations ahead of the 2023 summer season. The utilities said the PRM’s value and calculation is not in SPP’s tariff and asked the commission to require the grid operator to include the methodology in the tariff and file it for the commission’s review.

SPP’s board approved the change last July over opposition from stakeholders, who advocated for phasing in the PRM over a three-year period. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

In rejecting the protest, FERC ruled that the utilities failed to meet their Section 206 burden to show that exclusion of the PRM left SPP’s tariff as unjust. It disagreed with their argument that SPP’s PRM decision constituted an “impermissible collateral attack” on a 2018 resource adequacy order and assessed the complaint on the record before the commission.

“Complainants’ core argument is that the rule of reason, filed rate doctrine and due process require SPP to include its planning reserve margin value in its tariff,” FERC wrote. “Granting this relief would go beyond merely adding new details about SPP’s existing process, which is a common remedy to a rule of reason claim.”

The commission said Attachment AA to SPP’s tariff, which it accepted in 2018, describes the process through which the RTO reviews and revises the PRM.

“We find that this level of detail is sufficient to satisfy the rule of reason,” the three approving commissioners wrote. “Our determination here is consistent with relevant commission precedent, including specific precedent regarding the establishment of planning reserve margins in resource adequacy programs.”

FERC also denied the utilities’ alternative request that it direct SPP to remove the deficiency payment mechanism from its tariff, saying it continues to exercise jurisdiction over the deficiency payment mechanism and the grid operator’s PRM process.

Danly said in his dissent that while the PRM value doesn’t necessarily need to be in the tariff, “it nevertheless represents a rather important part of SPP’s rate.”

“Perhaps the lesson to be drawn from this proceeding is not to focus on whether the existing tariff provisions accord with the rule of reason but whether responsible administration and regulation of RTOs is even possible,” he wrote. “As the complexity and uncertainty of our markets increases, it becomes ever more difficult to implement rational policies and to assure ourselves, even in the face of a particular complaint, that a tariff remain just and reasonable.”