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November 14, 2024

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Constellation Increases Costs of Proposed Everett Agreements

Constellation Energy is requesting an increase in the cost-of-operation charges in their proposed agreements with Massachusetts gas utilities to keep the Everett LNG import terminal operating through the winter of 2029/30. 

In comments to the Massachusetts Department of Public Utilities, Constellation — the owner and operator of Everett — wrote that it has not entered agreements for enough LNG supply to support the continued operation of the facility (DPU 24-25, 24-26, 24-27 and 24-28). 

Constellation wrote that each of the four utility contracts contains a provision, or “conditions precedent,” that allows the company “to terminate the agreements in the absence of contractual arrangements for supplying a certain total volume of LNG.” 

Based on the contracts entered to date, there is a difference “between the total contracted volumes and the threshold total volume identified in the conditions precedent,” Constellation said. 

To cover this gap, Constellation is asking for an increase in the “fixed non-commodity demand charge,” a provision included in each of the contracts with the Massachusetts gas utilities intended to cover Everett’s costs of operation. 

National Grid and Eversource Energy, the state’s two largest gas utilities, wrote that the rate changes would result in minimal increases to ratepayer bills and urged the DPU to approve the proposed increases. 

Eversource estimated that the increase would add $2.85 to next year’s bill for an average customer, with the overall agreement costing customers about $100 for the year. National Grid estimated that the increase would amount to 72 cents for its average customer in the coming year. 

“Given the important reliability benefits provided by the agreement,” National Grid wrote, “the company continues to respectively request that the department approve” the request by May 1. “The agreement is still needed by the company to reliably serve customers, and there are no viable alternatives that offer the services that could be provided to the company by the agreement.” 

Constellation has said the May 1 deadline is necessary to provide enough time to procure the LNG needed to fulfill the contracts. If they do not receive final approval by then, Constellation has the right to void the agreements. (See Everett LNG Contracts Face Skepticism in DPU Proceedings.) 

However, the proceedings are on track to extend past May 1; the DPU has set a May 2 deadline for comments on the rate changes and a May 7 deadline for reply comments. 

Throughout the DPU proceedings, environmental organizations have expressed concerns about the cost and climate consequences of the agreements. 

In an April 16 filing, the Conservation Law Foundation called on the DPU to reject the contacts, writing that the gas utilities “have failed to adequately consider alternatives to these agreements and have accordingly not shown that they are in the public interest.” 

Environmental groups have also argued that the cost-of-operation charges would result in gas customers ultimately subsidizing Everett’s operations for the benefit of industrial or power sector gas customers that decline to enter long-term contracts but could still purchase LNG from the facility. 

“The other buyers don’t want to execute fixed contracts,” said Joe LaRusso, senior advocate at the Acadia Center. “They want to buy in the spot market. … There’s financial risk associated with executing a fixed contract.” 

LaRusso added that the “non-commodity charge, paid by the utilities customers, is de-risking the other transactions that Constellation is going to enter into in the spot market with everybody else.” 

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Overheard at the Energy Bar Association’s 2024 Annual Meeting

WASHINGTON — The ongoing turnover of the generation fleet to cleaner resources, the recent return of demand growth and the need to stitch all that together with transmission expansion all came up at the Energy Bar Association’s Annual Meeting. 

“We’re at a major inflection point in the development and maturation of the electric utility industry,” MISO Assistant General Counsel Michael Kessler said. “And there are many factors that we are experiencing that are impacting almost all aspects of the industry.” 

Studies by MISO and others have found the grid can be operated reliably even with higher levels of intermittent resources, but until new technologies are available, those renewables will need to be balanced with more traditional, dispatchable resources, he added.

“There’s a lot of uncertainty going forward in kind of managing this transition,” said Analysis Group Principal Todd Schatzki. “And in many cases, the speed at which things are happening is very uncertain. Some things [that] we think are going to happen very quickly are taking longer. And some things we don’t anticipate are suddenly coming in very quickly. The whole data center issue, AI and how that’s changing things, is a classic example of that.” 

While the system is changing and regulators and the industry are working to address that, there is still substantial uncertainty about the pace of change, Alliant Energy Executive Vice President Raja Sundararajan said. Electric vehicle demand was supposed to grow at a steady clip, but now it varies by region and is slowing down in some, he said. 

“There’s a natural skepticism: Are we going to overbuild?” Sundararajan said. “And if you’re going to overbuild, then you have the affordability issue that comes into play, where the regulators are saying, ‘Why should … customers pay a portion of the cost for [a] new set of customers? And how do I transfer the risk between existing customers and the new customer?’” 

Basic regulatory processes need to speed up, he added, citing transmission and developing integrated resource plans. 

FERC has a major rule coming May 13 aimed at improving transmission planning and cost allocation. Commissioner Mark Christie is a key vote there, but he declined to wade into the debate when asked after his speech at the conference. He did make clear he continues to favor a strong role for the states and wants to make sure the changes do not impose unneeded costs on customers. 

While states have to site transmission lines, they do not get to decide what consumers will pay for them because that falls under FERC’s regulatory territory, he said. 

“I’m very adamant that in any transmission planning that FERC is going to mandate, if you’re going to put policy-oriented projects in there, the states have to have the ability to consent to it,” Christie said. “So, we can restore the balance, which we have not had really for 20 years, where state regulators have the role that they should have in determining the transmission costs and how they get passed on to consumers.” 

Risks are inherent in long-term planning, but it still is work that needs to be done, said Grid Strategies President Rob Gramlich. 

“A lot of people sort of end the conversation and say, ‘Well, we might be wrong,’” Gramlich said. “Well, of course. Look at this great industry that is still a marvel of modern society that has been developed and that we all inherited, where we can flip the switch and get the lights on. That was all planned. Guess what? Planners in the ’50s, ’60s and ’70s didn’t know what to expect.” 

A lot of transmission was built just 10 years ago in 2013, when different efforts such as MISO’s first Multi-Value Projects and the Competitive Renewable Energy Zone lines in Texas came to fruition. But since then, it has “slowed to a trickle,” Gramlich said. “If you care a lot about the pace of climate action and greenhouse gas reductions — well, 80% of the most historic climate legislation ever will not be achieved without doubling the pace of transmission.” 

FERC’s transmission rule is the culmination of years of work, which includes the Joint Task Force with states, said Karin Herzfeld, senior transmission counsel to Chair Willie Phillips. 

“The NOPR was silent as to what happens when states cannot come to an agreement on the cost allocation for any particular project,” Herzfeld said. “And I know there’s some friction here, but the chairman, as a former state regulator, is focused on keeping states front and center on this important issue.” 

Another issue on FERC’s plate is what to do about dynamic line ratings, on which it has an open Notice of Inquiry. On that front, Herzfeld told the EBA crowd to “stay tuned.” 

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FERC Denies Permit for Pumped Storage Hydro on Navajo Land

FERC on April 25 denied an application for a 3.6-MW pumped storage hydropower facility on the Little Colorado River in Arizona — near the Grand Canyon and entirely on Navajo Nation land — after the tribe protested that it had not been consulted by the developer (P-15024). 

The order, approved unanimously at FERC’s monthly open meeting, follows a commission policy issued in February saying it will not issue preliminary permits for projects proposing to use tribal lands if the affected tribe opposes the permit. Tribal lands are administered directly by the U.S. government, not by the states in which their territory lies. FERC said this makes the policy consistent with how it has treated permit applications opposed by federal land managers or similarly affected federal agencies. 

“Because the proposed project would be located entirely on Navajo Nation land and the nation has stated that it opposes issuance of the permit, we deny the application,” FERC said. “To avoid permit denials, potential applicants should work closely with tribal stakeholders prior to filing applications to ensure that tribes are fully informed about proposed projects on their lands and to determine whether they are willing to consider the project development.” 

The developer, Pumped Hydro Storage, argued that because it had filed its application in 2020, the new policy should not apply to it. It also claimed that gaining tribal approval is difficult before being granted a permit, but that gaining one would give it more “resources” to consult with the Navajo. 

“We are not persuaded by Pumped Hydro’s arguments,” FERC said. “Pumped Hydro provides no support for its assertions that gaining tribal approval at the permit stage is particularly difficult and that issuance of a permit, which is simply a placeholding action, would provide any additional resources to a developer.” 

The developer had named the proposed project the “Navajo Nation Big Canyon Pumped Storage Project,” but the text of the order omitted “Navajo Nation” from the name and refers to it simply as “Big Canyon” throughout. In an unusual footnote, FERC said the project was “not in any way affiliated with” the tribe, so it removed it from the name “to avoid the impression that the Navajo Nation is involved in developing the project.” 

The project would have consisted of three new dams with walls spanning a collective 11,450 feet, a building to house nine 400-kW turbines and two double-circuit 500-kV transmission lines, among several other facilities. The Navajo Nation said it would adversely impact its water use and historic and cultural resources. Other commenters raised concerns about the fitness of the developer for such a project and the application’s completeness. The commission did not address these concerns. 

“This disastrous project could have devastated the Little Colorado River and pushed the world’s last large source population of humpback chub toward extinction,” Taylor McKinnon, Southwest director at the Center for Biological Diversity, said in a statement. “It’s good news for these embattled fish that federal officials heeded the Navajo Nation’s staunch opposition and rejected this project.” 

Cabin Run Permit Approved

FERC did approve a preliminary permit for Cabin Run Pumped Storage to study the feasibility of a 57.5-MW, closed-loop pumped storage hydropower facility near the Stony River in Tucker and Grant counties, W.Va. (P-15318). 

The West Virginia Division of Natural Resources, Potomac Riverkeeper Network and Friends of Blackwater opposed the permit, arguing the project would adversely impact the river’s habitats, especially those of the native brook trout. 

The commission did not address these arguments, noting that “a preliminary permit does not authorize access to project lands or project construction. Therefore, addressing the commenters’ concerns at the permit stage is premature.” 

“The purpose of a preliminary permit is to secure the permit holder’s priority for filing a development application while it studies the feasibility of a project, including studying potential impacts, such as those identified by the commenters here,” FERC said. “The commission will consider in any future licensing proceedings potential project effects on water quality, water quantity and nearby infrastructure. Accordingly, it would be prudent for the permittee to consider and study these issues during the term of the permit.” 

That term ends April 1, 2026. 

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Energy Lawyers Debate the Impact of Losing the Chevron Deference

WASHINGTON — With the Supreme Court likely to overturn Chevron deference, the general counsels of FERC and the U.S. Department of Energy told the Energy Bar Association last week they doubt it would lead to massive issues with their agencies. 

Under the doctrine, stemming from the 1984 case Chevron v. NRDC, if a statute’s meaning is unclear, and the agency’s action administering the law was reasonable, courts should defer to the agency. (See Supreme Court Hears Oral Arguments on Overturning Chevron.) 

Chevron makes sense as a legal doctrine and provides judges with an easy way of affirming an agency’s decision-making when there is ambiguity in the law, FERC General Counsel Matthew Christiansen said at the EBA’s Annual Meeting. But underlying those decisions is some basic common sense being applied by the judges. 

“Because I think that Chevron is largely deployed as a way of providing a compelling path to affirm an agency action, I’m not convinced that the loss of Chevron in many cases, if that is indeed what happens, is going to lead to wildly different outcomes,” Christiansen said. “I’m sure it’s going to lead to different outcomes on the margins. But at the end of the day, I’m a big believer in agencies’ ability to still put forth compelling justifications.” 

Chevron has provided a lot of value over the decades, but the politics have reversed completely since it was first decided, DOE General Counsel Samuel Walsh noted. The late Justice Antonin Scalia, a textualist, was a big fan of the doctrine, and Justice Clarence Thomas authored the Brand X decision in 2005 that extended deference to the Federal Communications Commission and kept internet service providers from being regulated as common carriers. 

“Some of the most important Chevron cases were cases where agencies were using the flexibility afforded by deference to regulate in a more light-handed way, or maybe not at all,” Walsh said. 

The biggest area where DOE might be affected by the change in precedent would be on its ability to set efficiency standards for electric appliances, he said. 

“But to my knowledge, we’ve only been upheld at Chevron Step 2 once,” Walsh said; Step 1 is deciding whether the law’s intent is clear from the text. “We’ve done hundreds of rules over the last four decades, and I think we’ve only benefited from it in a clear and explicit way once.” 

DOE has benefited from the law more in its other functions such as litigation around nuclear waste storage in the 1990s and in litigation against the federal power marketing administrations it oversees. The law that governs sales from federal dams specifically calls “municipalities” preferred customers, so in the early 1990s, some “clever” city governments asked the Western Area Power Administration to sell them cheap electricity, Walsh said. WAPA argued that the term “municipalities” meant municipal utilities, and Chevron helped it carry the day in court. 

Based on how the oral arguments went and other cases before the court, Victoria Nourse, a professor at the Georgetown University Law Center, said she thought Chevron deference would be overturned, as would the Skidmore deference that was used before Chevron was decided. The 1944 decision held that courts should defer to agencies’ interpretation of a statute as long as they essentially show their work. 

“There were a lot of negative comments by Justice [Brett] Kavanaugh, who is very, very powerful and influential in statutory interpretation,” Nourse said. “A lot of the disruption is going to come because there are also FERC and other agency models that they may not consider. They’ll probably have a safety valve.” 

Hopefully, she added, that safety valve allows courts to give some credence to agency expertise on areas where engineers and scientists are bigger experts than lawyers ever could be. 

“This is a court that is a full employment bill for lawyers … because your clients can now challenge regulations, not only because they don’t meet the best interpretation; anything that ever relied on legislative history is a no-no up there, and if it was Chevron,” Nourse said. 

Several of the appeals circuits lean so far on one side of the political spectrum that litigants now regularly engage in “forum shopping” by picking the circuit where their arguments are most likely to win out, Walsh said. Losing Chevron would only exacerbate that trend. 

While the combination of polarized courts and the lack of deference to agencies could create significant issues for some parts of the government, Christiansen downplayed the risks in the electric and natural gas markets. Many of the major regulations FERC has issued have vastly influenced the industries it oversees. 

“Maybe I’m overly optimistic, too sanguine,” Christiansen said. “I’m not terribly concerned those foundational precedents that I think are the bedrock for the way the industry operates now are at great risk.” 

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Ariz. Looks to Public Safety Power Shutoffs to Prevent Wildfires

Arizona Public Service is prepared to implement public safety power shutoffs for the first time this year, and another utility in the state is laying the groundwork to use the wildfire prevention technique. 

“It is a tool that we expect to use very, very seldomly, but one that we are prepared to use if conditions warrant,” said Scott Bordenkircher, APS forestry and fire mitigation director. 

Bordenkircher’s comments came during an Arizona Corporation Commission workshop April 23 on electric utilities’ summer preparedness.  

Salt River Project is also evaluating the possibility of a public safety power shutoff (PSPS) program. 

“We are in the development stages and looking at what that could look like for SRP,” Jace Kerby, director of transmission line design, construction and maintenance at SRP, said during the workshop. 

The utility has brought in a vendor to help model wildfire threat in SRP’s service territory — information that would be key in designing a PSPS program, Kerby said.  

Utilities in other Western states have used PSPS as a wildfire prevention technique. In California, there have been 72 preemptive shutoffs since 2018, according to a California Public Utilities Commission dashboard. 

Oregon’s first PSPS event was in 2020. (See High Fire Danger Prompts First Oregon PSPS Event.) 

Xcel Energy implemented the first PSPS in Colorado in April in response to a severe windstorm forecast. The shutoff affected an estimated 55,000 customers April 6-7. 

After the event, Gov. Jared Polis (D) criticized the utility for failing to minimize outages and effectively communicate with customers. The Colorado PUC has opened an investigation into Xcel’s use of PSPS and will explore potential regulation of prescribed outages. 

As the risk of wildfire increases nationwide, some predict that more states will be facing public safety power shutoffs. 

“Ultimately, it’s a national push. This will happen very likely with all utilities in the nation very soon,” Commissioner Nick Myers of the Arizona Corporation Commission said during a wildfire mitigation town hall meeting April 4.  

PSPS Design

Bordenkircher at APS said the utility has targeted 13 circuits in high fire-risk areas in Yavapai, Coconino and Gila counties for potential power shutoffs. 

He said shutoffs would occur during “really bad fire weather,” when high temperatures, low humidity and strong winds elevate the risk of wildfires igniting and spreading quickly. He estimated that a shutoff would last about 20 hours, from when winds pick up in the afternoon and evening until crews could get out the next morning to inspect power lines for damage. Customers would be alerted four days in advance of a potential shutoff. 

Kerby said SRP is exploring circuit segmentation to reduce the number of customers affected by an outage if the utility proceeds with PSPS. 

Utilities are taking other steps to reduce wildfire risk, with two goals: to prevent utility equipment from starting wildfires and to protect utility infrastructure from wildfires of any origin. 

Kerby at SRP said vegetation management “has got to be the biggest key component to helping drive down the risk when it comes to wildfire mitigation.” Utilities are clearing vegetation from rights-of-way, removing trees at risk of toppling onto lines and clearing space around power poles. 

Another strategy at SRP is replacement of wooden poles with steel in its transmission and distribution systems. Tucson Electric Power (TEP) also has a pole-replacement program. 

High-tech Approaches

Other wildfire mitigation efforts are more high-tech. 

SRP has installed 12 artificial intelligence smoke-detection cameras on its transmission system as part of a research project. The cameras learn the topography in a 10-mile radius and send an alert if smoke is spotted. A limitation is that transmitting the data requires cellular service, Kerby said. 

TEP is also testing a fire detection system in the Gila National Forest and in grassland areas around Fort Huachuca. 

APS is adding weather stations and cameras to its circuits to better monitor conditions.  

The utility is using covered conductors in high fire-risk locations and undergrounding lines “where it makes sense,” APS’ Bordenkircher said, noting the difficulty of digging through granite prevalent in parts of the state. 

Another upgrade in fire-prone areas is expulsion-limiting fuses, which contain sparks rather than letting them fall to the ground. APS is using the fuses, as is TEP.  

Kerby said SRP partners with APS on a “no reclosing program” for circuits in high fire-risk areas. If a fault occurs on one of those circuits during periods of high fire danger, it will remain out of service until it’s been inspected and found to be in good condition, he said. 

Ultimately, Kerby said, “It should be every utility’s end goal to not need a PSPS,” and measures including equipment replacement, system hardening and vegetation management will help make that possible. 

“[So] that ultimately our system is in a good enough shape and the environment around the system is in a good enough shape that it can withstand the environmental conditions that could come its way,” he said. 

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Western Officials Get Rundown on ‘Irritating, Inefficient’ Market Seams

DENVER — Utility staff responsible for real-time operations will be equipped to manage the seams between two Western day-ahead markets, but the situation will be far from ideal, state energy officials from across the West heard April 24 at the joint spring conference of the Committee for Regional Electric Power Conference and Western Interconnection Regional Advisory Body (WIRAB).   

“I can say that I have a positive outlook that maybe you will be happy to hear: that system operators are going to make it work,” Kelsey Martinez, director of regional markets and transmission strategy at Public Service Company of New Mexico, told the officials during a panel discussion on the potential impact of seams between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. 

“Even if we give them subpar designs regarding the seams, even if we give them amateur joint operating agreements [on] Day 1 with the seams, system operators will make it work. They will keep the lights on and there won’t be any large reliability event that we can point to and say that ‘Seams were the smoking gun on that,’” Martinez said on the panel, which was moderated by New Mexico Public Regulation Commissioner Gabriel Aguilera.  

“That’s the good news,” according to Martinez, who based her views on five years’ experience as a former system operator and three years managing real-time operations. “The bad news is that seams show up in all kinds of little irritating, inefficient ways in the control room.” 

Those irritants include: 

    • use of different sets of “situational awareness” tools and data sets among neighboring balancing authority areas (BAAs), making it difficult for operators to troubleshoot in real time; 
    • challenges for vendors in configuring those tools because they must translate different market rules among adjacent BAAs; and 
    • differing time frames among BAAs around when schedules are due and market operating runs take place and are published. 

Dividing the West into two day-ahead markets also would roll back some of the gains system operators have seen from improved visibility into neighboring areas provided by widespread participation in CAISO’s Western Energy Imbalance Market (WEIM), Martinez said. The WEIM now includes BAAs representing about 80% of the load in the Western Interconnection. 

“Now there’s going to be some visible information and then some invisible information, and that also includes communications,” she said. “So, we’re going to continue to get communications in real time from our market operator, but we may not be getting real-time communications from the other market operators that will affect our system.” 

Taken together, those issues add up to what Martinez called a “low-level reliability degradation.” 

“These aren’t things that are going to represent huge events on the system, but what they will do is just create economic inefficiencies that are hard to measure but are very prevalent, and could be improved with mature seams operations,” she said. 

Perpetuating Inefficiencies

“Having one seam between two markets is a lot better than having 32 seams and no transparent pricing [and] no hourly trading,” said Johannes Pfeifenberger, principal at The Brattle Group, referring to the current patchwork of BAAs that characterizes the Western grid. “But what you get with two markets is you [can] have intertie [trading] between the markets if that feature is enabled, at least; so there’s a lot of work that needs to be done.” 

Bilateral trading faces the highest number of “hurdles” under a scenario with multiple BAAs in a non-organized market, Pfeifenberger said, while bilateral trading between two organized markets becomes more efficient due to increased transparency and liquidity. 

He said market simulations have shown that an organized day-ahead market in the West would increase trading volumes by 20 to 30% (60 to 90 TWh) compared with the “bilateral” status quo. And while a scenario in which most Western entities participate in one market would bring the highest increase in trading, a two-market scenario still would provide a boost. 

But based on evidence gleaned from Eastern RTOs, Pfeifenberger said, seams can “perpetuate” five types of inefficiencies. 

A key inefficiency is “largely ineffective” interregional transmission planning, and Pfeifenberger warned that coordinated planning in the West could decline under a two-market scenario compared with the status quo. 

“Once you have these markets, that planning between the markets is almost worse than what you have now because these markets are so focused on their region, more so than individual utilities can afford to do,” Pfeifenberger said. “The [West] has a better track record with regional planning than the East.” 

The other inefficiencies include: 

    • generator interconnection delays and cost uncertainty created by affected system impact studies;   
    • a reduced — or overlooked — value of resource adequacy at interties across seams due to restrictions on capacity imports and differences in RA accreditation across two markets; 
    • difficulties in managing loop flows through market-to-market coordinated flowgates; and 
    • inefficient trading across contract-path market seams. 

Pfeifenberger said the last problem must be addressed by “intertie optimization,” a mechanism that allows for trades across seams to respond to fast-changing real-time prices in adjacent markets. 

Fondest Dream

But seams between day-ahead markets will pose problems beyond those experienced at the boundaries dividing the full RTOs in the East, said Scott Miller, executive director of the Western Power Trading Forum (WPTF). 

Miller pointed to a recent study WPTF commissioned in partnership with the Portland, Ore.-based Public Generating Pool to examine the potential impacts on trading from a West divided between EDAM and Markets+. The study pointed to increased barriers to contracting across markets, inefficiencies related to greenhouse gas accounting and associated generation dispatch, and differences in market power mitigation approaches, among other issues. It also noted that, given the lack of BAA consolidation seen in RTOs, the two day-ahead markets still will contain “seams within seams.” (See Western Market Seams Issues to Differ from East, Study Finds.) 

“We found that, indeed, day-ahead markets are going to be different in many respects, and that the seams areas may present certain challenges that need to be addressed [in ways] that will be not informed by what the RTOs do,” Miller said. 

“And this is not to rain on the parade of day-ahead markets; this is definitely going to be an improvement on the status quo,” he said. “But recognize you are talking to somebody whose fondest dream — at least professionally —would be that there is a single market [with] security-constrained economic dispatch across the West. But we are where we are, and we do things incrementally.” 

Past and Future Seam?

Rachel Dibble, vice president of power bulk marketing at the Bonneville Power Administration, cautioned against conflating day-ahead seams issues with what would happen in an “eventual RTO.” BPA has been heavily involved in the design of Markets+ and its staff recently recommended the federal power agency select the SPP day-ahead market over CAISO’s EDAM, a move criticized by some proponents of a single Western market. (See BPA Staff Recommends Markets+ over EDAM.)  

“I just want to clarify that the seams that exist today between balancing authorities, transmission service providers and transmission operators — [they] will still exist in a day-ahead market,” Dibble said. “Now, there are efficiencies that Kelsey [Martinez] and Scott [Miller] both talked about, even with the day-ahead market that can improve things, but those things don’t go away with a day-ahead market.” 

Dibble said she would expect “experienced and responsible” market operators (that is, CAISO and SPP) to work together to “find the efficiencies to be able to allow power to flow across those boundaries in the most efficient way possible and bring participants into that discussion.” 

She added that BPA has “a lot of experience” working with CAISO on seams issues, considers the ISO a “valued business partner” and is a WEIM participant. 

Dibble noted that BPA negotiated a coordinated transmission agreement with CAISO when PacifiCorp joined the WEIM as the market’s first member in 2014, “long before” BPA joined. 

“And that was essentially a seams agreement that identified ways that we could operate efficiently and address that seam and going across,” Dibble said. “So, yes, I agree, it’s a big seam. It’s a seam that’s there today and may be there in the future as well.” 

“We can’t really tackle this until we know where the boundary is,” Miller said. “And so, when we get to that point, I think sometime this year, then we can engage meaningfully in what we can do to manage the seams that are unique to the day-ahead market.” 

Uncertainty is part of the landscape, according to panel moderator Aguilera. 

“Many of you in one way or another are thinking about this in your job, which is whether a utility should join a day-ahead market, and we’re hoping that this session will confuse you further,” Aguilera joked with his fellow commissioners. “We’re not hoping for that, but I believe that our panelists will give you more to think about.” 

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PJM MRC Briefs: April 25, 2024

Stakeholders Defer Vote on Long-term Planning Proposal

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee delayed voting on a proposal establishing a multiscenario long-term transmission planning process to allow stakeholders to first see what action FERC may take on regional planning. The motion to defer received 78% sector-weighted support. 

The proposal would create two reliability-focused scenarios identifying transmission violations eight and 15 years in advance; two policy scenarios looking at new generation development backed by state legislation eight to 15 years out; and an additional policy scenario including higher generation entry not backed by signed legislation. It also would expand PJM’s two-year planning cycle to three years to accommodate the increased number of scenarios. (See “Stakeholders Long-term Regional Transmission Planning Proposal,” PJM PC/TEAC Briefs: March 5, 2024.) 

FERC announced it intends to vote on an order related to cost allocation for regional transmission expansion during a May 13 special meeting. (See FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming.) 

Paul Sotkiewicz, president of E-cubed Policy Associates, said the proposal is deficient from both policy and process standpoints, arguing it would replace the ideal of having markets driving planning decisions with PJM picking “winners and losers.” By constructing the proposal through workshops, rather than committees, he said the stakeholder process was bypassed, preventing the language from being fully vetted by members. 

“There are some real deep concerns from a process standpoint and from a concept standpoint,” he said. 

Sotkiewicz introduced the motion to defer to a month after FERC is expected to issue the order on the basis that members should have time to understand how it may interact with PJM’s proposal. 

“This is a major change. You’ve got a FERC rulemaking sitting out there that’s going to come out in three weeks. There’s no reason to vote on this now,” he said. 

Gregory Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said advocates are frustrated that alternatives to the standard stakeholder process increasingly are being used to seek endorsement of changes with reduced stakeholder input. 

Denise Foster Cronin, of the East Kentucky Power Cooperative (EKPC), said the proposal could lead to significant costs for market participants and should be implemented by revising the governing documents rather than by edits to Manual 14B and Manual 14F alone. 

PJM argued a delay was unnecessary as its proposal is in line with the notice of proposed rulemaking (NOPR) the commission issued in April 2022 (RM21-17). PJM’s Jason Connell clarified that expectation is entirely based on the NOPR, and RTO staff has not discussed the contents of the order with FERC. 

The RTO’s Michael Herman told the committee that if it endorsed the proposal without a deferral, a competitive window could be opened in 2025, whereas a delay could compromise its ability to implement the new process on its envisioned timeline. 

PJM CEO Manu Asthana admitted there could be unintended consequences, such as PJM projecting too much load growth and overbuilding transmission, but the reliability needs outweigh the risks. 

“There’s many risks, but not doing this is a bigger risk,” he said. 

Ryann Reagan, of the New Jersey Board of Public Utilities (BPU), said the scenario-based planning paradigm is a major improvement that could relieve the interconnection backlog and contribute to proactive planning connect generation to the grid at the most cost-effective locations. 

PJM Re-evaluating CONE Inputs

Rising interest rates and construction costs have prompted PJM to initiate a re-evaluation of the inputs used to calculate the cost of new entry (CONE) for the reference resource in the quadrennial review. That parameter is a factor used to determine demand curve scaling. (See FERC Approves PJM Quadrennial Review.) 

The new analysis will be for the values used in the quadrennial review accepted by FERC on Feb. 14, 2023, effective for the 2026/27 Base Residual Auction (BRA) scheduled to be run in December 2024. The Brattle Group has been hired as an independent consultant for the review; the firm also was brought in for the initial quadrennial review. 

PJM’s Pat Bruno said initial analysis of the change suggests updated figures could lead net CONE to increase between $50 and $100/MW-day. He said the review will be limited to the inputs used to calculate the reference resource CONE and will not affect other values produced by the quadrennial review. 

Several stakeholders questioned why the energy and ancillary service (EAS) offset is not also being reconsidered given the potential for forward energy prices to change significantly between the quadrennial review’s completion and the BRA. Two significant changes made in the most recent quadrennial review were shifting the reference resource from a combustion turbine to a combined-cycle generator and using a forward EAS offset, which uses forward energy forecasts to estimate revenues a market seller will receive outside the capacity market. 

Stakeholders also suggested that developing a trigger for PJM to review quadrennial review figures or periodic reviews could increase transparency. 

Additional Guidance on Co-located Load

PJM has revised its guidance for generators with co-located load clarifying how it conducts grid impact studies, the difference between co-located load configurations where the load is connected to the PJM grid or only the generator, and the circumstances under which generators with a capacity obligation can serve non-network load. 

The guidance initially was posted in March and presented to the Market Implementation Committee on April 3. PJM updated the language with feedback received from stakeholders and reposted the document April 17. (See “PJM Provides Guidance on Co-located Load Configurations,” PJM MIC Briefs: April 3, 2024.) 

PJM’s Tim Horger presented the revised guidance, saying the RTO’s preference is that co-located load be interconnected with PJM, which provides firm service and subjects consumers to all service charges. However, the guidance acknowledges that jurisdictional constraints prevent it from requiring that configuration. 

The alternative configuration is for the co-located load to be behind the generator’s meter and not directly connected to the PJM grid, thereby not receiving firm service and allowing it to avoid service charges. The generator’s capacity interconnection rights (CIRs) would be reduced by the amount of non-network load being served. 

If the generator trips offline or otherwise cannot serve non-network load, the configuration must prevent the load from being able to draw from the PJM grid instead. A portion of the generator’s committed capacity can serve non-network load; however, it must be approved to go on forced outage by PJM, which could expose the unit to capacity performance penalties if it is dispatched by PJM and does not switch its output to the grid. 

The revised guidance clarifies how backup generators submit forced outage requests and adds that energy-only resources always will be approved for an outage to serve non-network load but still must request an outage to provide visibility to operators. 

The co-located load is required to reduce its consumption to zero before the generator can coordinate with PJM to switch from the primary resource to the backup generator. 

Adrien Ford, Constellation Energy’s director of wholesale market development, said the requirement that load power down before being served by the backup generator ignores technologies for which the load could remain online while the power source is switched over without risking the load inadvertently drawing off the PJM grid, such as battery storage. 

Under both configurations, PJM requires a network impact study be completed before co-located load comes online so PJM can analyze any potential reliability issues that arise, such as a need for more reactive power capability. If grid upgrades are required, the costs would be assigned to the generator. 

“We need to know about these configurations. If there’s co-located load coming onto the system, we need to know it’s out there, so it needs to go through the proper interconnection system,” Horger said. 

Connell said it typically takes fewer than nine months to complete network impact studies on co-located load requests, depending on the configuration, with simpler arrangements often being completed much quicker. 

Horger said PJM plans to draft manual revisions addressing co-located load over the next sixth months with the aim of arriving at governing document revisions. As the amount of co-located load has increased, he said it started to affect PJM planning and operations, necessitating clear rules. 

Stakeholders voted on rule change packages for co-located load in October 2023, but none received adequate support. One of the core sticking points between the proposals was whether capacity resources should be permitted to retain their CIRs while serving non-network co-located load if that load could be quickly curtailed to allow the generator to meet its capacity obligation. 

Quick Fix for Dual-fuel Classification Endorsed

Stakeholders endorsed a quick-fix proposal from Calpine Energy to adjust the qualifications for a generator to offer capacity as a dual-fuel resource to include gas units that can operate on an alternate fuel after starting on gas. 

Calpine’s David “Scarp” Scarpignato said the change would be implemented in the 2026/27 BRA due to how far into pre-auction activities the 2025/26 BRA is. The quick-fix process allows a proposal to be voted on concurrently with an issue charge and problem statement. (See “Calpine Proposes Changes to Dual Fuel Classification,” PJM MRC/MC Briefs: March 20, 2024.) 

Scarp said many combustion turbines and combined-cycle units capable of operating on an alternate fuel still consume gas to start, but the amount is so miniscule they could start multiple times on residual fuel in the pipeline even if supply was so compromised that they couldn’t use gas as their primary fuel. 

Erik Heinle, Vistra director of PJM market policy, said the change addresses an oversight in the governing document language establishing dual-fuel classification, leading to no dual-fuel combined-cycle generators being offered for the 2025/26 auction.  

Stakeholders Endorse Additional ELCC Data Posting

The committee endorsed a PJM proposal adding a paragraph to Manual 33, which pertains to administrative services, allowing PJM to post aggregated forced outage data broken down by effective load carrying capability (ELCC) class.  

PJM’s Pat Bruno said manual language requires that any aggregated data must include four or more generation owners to be posted, which could prevent PJM from publishing outage data for ELCC classes in some hours. The revisions would allow PJM to post data for those hours while excising data for ELCC classes for hours in which the four-generation owner threshold was not met. 

Heinle said the data could help market sellers better understand their ELCC accreditation and performance as PJM shifts to using marginal ELCC to determine the amount of capacity they can offer into the market. 

Independent Market Monitor Joe Bowring said posting aggregated data would be a major departure from PJM’s practice of posting such data only after major events, such as storms resulting in high outage rates. He said the difference in forced outage rates could allow identification of which resource went online and the revealing of market-sensitive data. 

Changes to Capacity Assignments for Large Load Additions Contemplated

PJM’s Pete Langbein presented a first read of a proposal revising how capacity obligations are assigned for serving large load additions (LLAs) — forecast load interconnection requests not captured in PJM’s economic forecasting. (See “Stakeholders Endorse Proposal on Large Load Capacity Obligations,” PJM MIC Briefs: April 3, 2024.) 

The Tariff and Reliability Assurance Agreement (RAA) revisions would rework how PJM calculates capacity obligation assignments to exclude LLAs included in Table B-9 of the load forecast from base zonal scaling factors and add those LLAs back when determining the obligation peak load input. 

Bowring argued that PJM’s processes for reviewing LLA submissions and assigning capacity need a deeper look as they can result in consumers buying excess capacity if forecast load does not manifest in the expected delivery year. 

Michael Cocco, of Old Dominion Electric Cooperative, agreed with Bowring but said LLAs receive some high-level review by the Load Analysis Subcommittee and PJM staff, which ultimately accept or reject the LLAs. 

PJM’s Andrew Gledhill said the RTO has rejected LLA submissions and would retain the power to review and ultimately determine whether they are incorporated into the load forecast and translated into capacity obligations. 

Alex Stern, Exelon director of RTO relations and strategy, said the proposal aims to ensure capacity assignments accurately reflect the load that’s expected to materialize in a region. 

“This seems to be an enhancement to the load forecasting process and that’s a primary goal and objective of what we do here, which is making sure we’re investing in what we need to invest in, but also making sure that costs on the transmission and generation side are properly allocated to all customers,” he said. 

Other MRC Business

Stakeholders endorsed with 67% sector-weighted support a set of revisions to PJM’s governing documents drafted through the Governing Document Enhancement and Clarification Subcommittee (GDECS), with the most notable being lowercasing the term “end-use customer” in the language detailing load management participation in the capacity market. Bowring and some stakeholders argued the change could significantly alter which entities can participate in demand response and said the change should have been made through the stakeholder process. (See “Governing Documents Revisions Endorsed Through GDECS Process,” PJM MRC/MC Briefs: March 20, 2024.) 

The committee endorsed by acclamation governing document and manual revisions adding definitions of three synchronous condenser parameters — condense startup costs, condense-to-generate costs and condense energy use. PJM’s David Hauske said the parameters are in use and the new language codifies ongoing practice. (See “Other Committee Business,” PJM MRC/MC Briefs: March 20, 2024.)

PJM reviewed revisions to Manual 3, which details transmission operations, and Manual 36, pertaining to system restoration, following the documents’ periodic review. Both proposals are slated to be voted on by the MRC at its May 22 meeting. 

The changes to Manual 3 would include a requirement that transmission owners notify the Operating Committee prior to implementing dynamic line ratings (DLRs) and rules for rescheduling canceled transmission outage tickets. 

Manual 36 revisions update the list of TOs within PJM and the list of TO deadlines for submitting annual restoration plan reviews. 

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NY Reaches Deals for 2.4 GW of Onshore Renewables

New York state has reached tentative contracts with developers proposing 24 land-based renewable energy projects totaling nearly 2.4 GW of capacity. 

The announcement April 29 is the result of the rush solicitation issued in late 2023, as 81 onshore projects with a total 7.5-GW capacity were in the process of cancelling renewable energy certificate contracts that were no longer economically viable. 

The New York State Energy Research and Development Authority expects to negotiate and finalize the tentative new contracts over the next few months. NYSERDA won’t release details on the projects or their costs until final contracts are awarded. 

The state’s vaunted renewable energy development pipeline imploded in late 2023 and early 2024. Dozens of projects contracted years earlier had not begun construction when inflation and interest rates skyrocketed.  

En masse, developers in June 2023 said they could not proceed to construction under terms negotiated and asked for more money. (See OSW Developers Seeking More Money from New York.) 

The state Public Service Commission rejected their petitions in October, saying that renegotiating deals would undercut the competitive process by which they were selected. (See NY Rejects Inflation Adjustment for Renewable Projects.) 

Along with the 7.5 GW of land-based contracts that were canceled, developers bailed out on 4.2 GW of offshore wind projects. 

It was a serious blow to New York’s hopes of reaching the first of its climate protection milestones: 70% renewable energy flowing through the grid by 2030. 

NYSERDA undertook immediate damage control efforts, including onshore and offshore solicitations carried out far more quickly than past procurements.  

The resulting tentative contracts fell far short of the cancellations, however: 1.73 GW of offshore wind was announced Feb. 29, and the 2.4 GW of onshore wind and solar was announced April 29. That’s 4.1 GW of tentative contracts to replace 11.7 GW of finalized contracts. 

And the equation is worse than even that sounds: NYSERDA on April 19 announced tentative offshore wind contracts totaling 4 GW could not be finalized because the specified turbines would not be available. (See NY Offshore Wind Plans Implode Again.) 

Contract cancellations do not equate to project cancellations, however. NYSERDA expects many of the developers will attempt to proceed to construction eventually. But the reset inevitably will mean longer time frames and higher price tags in a state where energy development is already slow and expensive. 

One positive detail: The two provisional offshore wind projects chosen in February are mature plans that previously held contracts and are approaching construction-ready status. 

NYSERDA said all the tentative onshore contracts announced April 29 also are for mature, late-stage projects, and said some of them were among the mass cancellations of late 2023.  

That was a requirement to submit bids in the latest onshore solicitation: Projects had to have achieved late-stage interconnection and permitting milestones. 

The trade organization representing the developers that canceled the contracts, the Alliance for Clean Energy New York, welcomed the latest news. It said via email:  

“Any day a renewable energy project makes progress is a good day, and we thank NYSERDA for announcing these 24 provisional contract awards from the recent competitive solicitation. Since the projects provisionally awarded today are further along than previous competitive solicitations, it is exciting to know they could be on the grid serving New Yorkers as soon as 2025.” 

Also on April 29, NYSERDA issued a request for information that will help it shape its eighth large-scale onshore renewable solicitation, which it expects to kick off as soon as late May and which could yield provisional contract awards as soon as October. 

However, NYSERDA is looking at pushing the timetable back a few months to better mesh with the NYISO Class Year 2023 Study. This could give potential bidders a better understanding of their expected upgrade costs prior to submitting a bid proposal. 

Responses to NYSERDA’s request for information are due by May 13. 

NYSERDA on April 23 issued a request for information to help shape its next offshore wind solicitation, planned to be issued in the summer of 2024. Responses are due by May 21. (See IPF24: New York Starts Another OSW Rebound.) 

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IPF24: Moving Offshore Wind Beyond Contract Cancellations

NEW ORLEANS — Five Northeast states have seen contracts for offshore wind projects totaling more than 12 GW canceled in the past year. 

Getting them back on track to construction and avoiding future derailments for other projects is a central concern for the advocates and officials working to expand offshore wind in the United States. 

An International Partnering Forum panel discussion April 25 looked at lessons learned and ways to move forward. There is much to learn from and much to move forward from: The Northeast scratch sheet reads like a who’s who in the offshore wind industry. 

In the past year, the contracts for SouthCoast and Commonwealth in Massachusetts, Park City in Connecticut and Skipjack in Maryland were canceled because of rising construction costs, as were Empire 1 and 2, Sunrise and Beacon in New York; Ocean Wind 1 and 2 in New Jersey were canceled due to construction costs and nonavailability of installation vessels; and provisional contracts for Attentive 1, Community 1 and Excelsior were canceled in New York after development of the 18-MW turbine specified in those contracts was halted. 

Empire 1 and Sunrise already have tentative replacement contracts with New York, and bids have been resubmitted for some of the others.  

But the wholesale reset of the pipeline in Northeast states inevitably will raise costs and extend timelines. 

“You can’t look at everything that has happened over the last year and say, ‘No, we should just keep doing everything exactly the way we have been doing it,’” said Abby Watson, president of The Groundwire Group. “We clearly have designed a system that was not sufficient to meet some of the potential shifts in the market and macroeconomic environment that could come along, and so we need to find more resilient strategies for building this out because these are really long timeline projects … we’re going to have other shocks and disruptions to the system.” 

Fred Zalcman, director of the New York Offshore Wind Alliance, said policymakers need to be flexible. 

“Let’s remind ourselves that what we’re trying to achieve here is nothing short of standing up a new U.S.-based heavy industry,” he said. “It’s not just the steel in the water, but it encompasses localizing our manufacturing, standing up a new workforce, Jones Act-compliant vessels, community benefits. Those are all very laudable public policy goals, and I don’t mean to question them, but it also comes with some risks and some cost.” 

Zalcman said he already is seeing that flexibility in the actions of the New York State Energy Research and Development Authority, which is seeking stakeholder input through a request for information (RFI) as it prepares the state’s fifth offshore wind solicitation and concurrent requests for supply chain development proposals. 

NYSERDA Director of Offshore Wind Greg Lampman described the situation as a clean slate. 

“We are now … working to not continue to engage and negotiate and revise but really just to start fresh, build a new solicitation gathered by input from the RFI and push forward to continue to develop the industry.” 

Power Advisory President John Dalton said his firm is working with Massachusetts and Rhode Island on their latest offshore wind solicitations. 

He said the contracts in Massachusetts involve electric distribution companies as counterparties, so they have a more commercial focus than the holistic contracts NYSERDA pursues. 

Dalton said the interest rate considerations outlined in New York’s RFI are intriguing. 

“Hats off to NYSERDA. The RFI that came out on Tuesday has an interesting formula, which I think really moves the industry forward in terms of one possibility how to better reflect interest rates and the impact on contract pricing,” he said. 

Watson raised a larger consideration about renegotiating failed contracts: “Something that we need to be really mindful of in this environment is that there are risks here regarding public perception of offshore wind,” she said. 

Traditionally there have been three public selling points for offshore wind, Watson explained: A significantly higher capacity factor to offset its slightly higher levelized cost of electricity; hedging against future increases in the cost of renewables by locking in huge blocks of capacity with a single contract; and development of supply chain, with its economic benefits.  

The second and third points have been undercut by the contract cancellations and rebidding, she said. Supply chain confidence is particularly important, she added, because of the long time frames involved. A manufacturer cannot commit to retooling for a project that may change. 

“Developers are hugely incentivized to take big risks and big gambles in securing these procurement awards because that’s the way that our process tends to be — expect the developer to take on a lot of that risk and they’re competing on the lowest price with a very limited amount of information about their lease areas,” Watson said. 

“We have to find a way to do this better if we want to attract those domestic manufacturing jobs and the supply chain piece,” she added, “also making good on our commitments to the people who have gone through workforce programs expecting to have jobs on a certain timeline that now we’re looking at pushing those timelines out.” 

Lampman called that a chicken-and-egg problem: Manufacturers want market certainty before setting up factories to build offshore wind components, and offshore wind developers won’t give it to them until it is too late to add new production capacity for a given project. 

Dalton said a helpful change would be a steadier cadence in development — a sense that there will be regular, manageable procurement, rather than states trying to lock down the supply chain for themselves with ever-larger procurement goals. 

Watson flagged another issue: Financing is expensive and the interest costs for a new offshore wind farm trickle down to electric ratepayers. 

“I think it’s worth noting that if you can get close to 6% on a Treasury bond right now, to be putting your capital at risk on something as long term and challenging as an offshore wind project, it is a fundamental challenge that the industry is facing,” she said. 

Lampman said projects bids often are viewed as too high for ratepayers to afford or too low for developers to follow through on. The middle ground is missing in the conversation, he said. 

“People sometimes cringe when I say this: We want everybody to make money — just not too much money,” Lampman said. “We continually say we’re trying to build an industry that’s going to be sustainable in the long term and keep persevering.” 

Zalcman said the industry and those surrounding it could do a better job communicating the value of offshore wind, explaining why costs are high and explaining the requirements placed on developers — whether it’s sailing ships more slowly to avoid killing whales or expending money and effort for community benefit. 

“We really don’t expect of other energy resources what we’re expecting of onshore wind,” he said. “We’re not asking coal plants to do workforce development or invest in ports and harbors, drive the trucks slower. We are encumbering the offshore wind industry with a lot of expectation. And again, I’m not challenging that, I just think as an industry, we probably need to do a little bit better messaging about the value proposition of onshore wind.” 

Additional IPF24 Coverage  

Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:  

Central Atlantic Region Prepares for OSW Development 

How Best to Address OSW’s Effects on Fisheries 

Interior Announces Updated OSW Regs, Auction Schedule at IPF24 

Louisiana Manufacturers Expand into Offshore Wind 

New York Starts Another OSW Rebound 

Offshore Wind Sector Leaders Emphasize Tailwinds 

Voices of the OSW Supply Chain, as Heard at Trade Show 

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PJM Monitor and Consumers Protest Indian River Compensation Settlement

The Maryland Office of Peoples Counsel and the Independent Market Monitor for PJM are urging FERC to reject a settlement to compensate NRG for keeping a portion of its Indian River coal-fired generator online under a reliability-must-run (RMR) contract (ER22-1539). 

The agreement would pay NRG $263 million to continue operating the 410-MW Indian River Unit 4 between June 2022, the generator’s initial deactivation date, and the end of the RMR term on Dec. 31, 2026. The payment is split between $35 million for project investment costs and a $228 million “black box” sum, which combined amount to a $164 million cut to the $357 million NRG had requested for RMR service in its initial filing April 1, 2022. 

In addition to decreasing the RMR compensation, the settlement would reduce the notice PJM must provide NRG to terminate the contract early, include the Monitor in reviewing new project investments and create a requirement that updates be provided at least three quarters before transmission upgrades are completed to resolve the reliability violations created by Indian River’s retirement. The terms were signed onto by NRG, the Delaware Public Service Commission, Old Dominion Electric Cooperative, Delaware Municipal Electric Corp., the Delaware city of Dover and PJM. The settlement also states that it was not opposed by the Delaware Energy Users Group, Delaware Division of the Public Advocate, Maryland Public Service Commission and Southern Maryland Electric Cooperative. 

The Maryland OPC and Monitor both argued the black box nature of the settlement figure prevents the commission from evaluating the merits of the compensation and that about half of the payment would be for sunk costs that NRG already had written off as impaired investments in 2013 and 2017. 

The Monitor argued that PJM’s tariff has two pathways for recovering costs incurred to provide RMR service, neither of which allow for sunk costs from prior to the start of the RMR period. In an affidavit, Monitor Joseph Bowring argued the proposed compensation would include $115,862,358 in sunk costs. 

“The goal of the tariff language is to ensure that a generation owner who operates a unit past its intended retirement date for reliability reasons is compensated for all the costs that it incurs in order to provide that service. Part V service has the limited purpose of allowing PJM time to complete transmission upgrades needed to ensure the reliable operation of the system after a unit deactivates,” the Monitor wrote, citing PJM’s tariff. 

Based on figures included in NRG’s initial RMR filing, the OPC stated that about 43% of the compensation would be for investments made prior to the start of the RMR period. It argued that would put consumers in the position of being asked to pay for losses Indian River experienced during its time as a merchant generator or face increased reliability risk if the resource retired prematurely. 

“NRG’s proposition to the commission embedded in the proposed settlement, to the affected states, and to affected electric consumers — boiled down to its essence — is that absent securing the windfall of recovery of a substantial and disproportionate quantum of its already-written-off investment, it will retire the plant, thereby putting at risk operation of the electric grid. The commission cannot and should not endorse this. The plant can be fully compensated for those ongoing operating costs incurred so the plant remains in service during the RMR period without providing it a windfall for sunk investments that it had no investment-backed expectation to recoup years following their write-off,” the OPC wrote. 

If sunk costs were allowed to be included in RMR compensation, the OPC argued an incentive would be established for aging generators with poor capacity factors to deactivate early to pursue compensation far higher than what they could receive in PJM’s markets. It estimated the Indian River RMR would come out to about four times higher than recent Base Residual Auction (BRA) clearing prices for the DPL South zone. 

“The distorted incentives resulting from possible recognition of an inflated rate base due to sunk, fully loss impaired, investment, for RMR service units will only accelerate this process. The recent filings by Talen Energy … seeking RMR service for the Brandon Shores and Wagner power plants in the constrained (Baltimore Gas and Electric Locational Deliverability Area) is an exponential exacerbation of this problem,” the OPC wrote (ER24-1787, ER24-1790). 

In initial comments on the settlement, FERC trial staff stated the settlement is “fair, reasonable and in the public interest” and recommended Settlement Judge Stephanie Nagel certify the agreement. 

“The settlement reflects reasoned negotiations undertaken by all participants in good faith and resolves all issues in this proceeding. The settlement provides lower rates through a reduction in the monthly fixed cost charge and elimination of carrying charges in the project investment tracker,” trail staff wrote. 

PJM stakeholders are considering two proposals to rework rules around generation retirement requests through the Deactivation Enhancements Senior Task Force. A PJM package would increase the amount of time generation owners must provide of their intent to shutter a resource ahead, while the Monitor introduced a proposal to establish a formula for calculating RMR compensation based on going-forward costs. (See PJM Stakeholders Considering Changes to Generation Deactivation Compensation and Timelines.)