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November 18, 2024

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Plans Would Boost OSW Infrastructure, Supply Chain Development

A new road map issued by an offshore wind trade association lays out the onshore infrastructure that could help the marine power source reach its potential in the United States.

The plan offered by the Business Network for Offshore Wind is neither modest nor inexpensive: It calls for $36 billion in spending on a network of up to 119 ports nationwide.

The U.S. offshore wind industry now has a mere 42-MW nameplate capacity but is poised to grow as state and federal leaders try to expand it to several dozen gigawatts by midcentury.

Spiraling costs are commanding headlines because they will filter down to consumers, but constraints on the supply chain and supporting infrastructure are just as problematic.

Monday’s report followed a separate but not unrelated announcement by the White House last week: Nine of the East Coast states at the center of first-generation offshore development efforts have signed a memorandum of understanding with four federal agencies to develop joint implementation plans to help the industry grow.

The goal is to expand manufacturing, port facilities, workforce development and supply chain capacity in a coordinated and sustainable way.

Port Buildout

BNOW in its report Monday underlined the need for public and private investment in port development and suggested ways to unlock the funds to accomplish this.

After more than a decade of study, development and delays, the U.S. offshore wind sector began to gain momentum in the past two years, culminating this year with the first substations and turbines being installed for the first two utility-scale projects in U.S. waters.

The industry ran into economic headwinds and the practical reality of creating an entire industry to fabricate and install supersized equipment under challenging conditions. Ports are on the shopping list.

“The shortage of port infrastructure developments is a critical bottleneck to industry growth that risks derailing progress,” BNOW President Liz Burdock said in a news release. “Federal and state governments must work together with private industry to incentivize and finance new offshore wind port projects to support our growing industry and create thousands of jobs in the process.”

BNOW identified 35 shoreline facilities in operation or in development and said more than $2.5 billion has been invested. But it placed the need at 99 to 119 ports along the Atlantic, Pacific and Gulf coasts. That breaks down into facilities specializing in pre-assembly; staging and integration; flexible laydown; manufacturing; and operations and maintenance.

BNOW suggests a mix of public- and private-sector steps to secure this investment, including state and federal subsidies, project de-risking strategies and accelerated permitting for construction projects.

BNOW said the investment would bring substantial returns: The 110 GW of offshore wind envisioned by 2050 carries an estimated $440 billion to $660 billion price tag in 2023 dollars, it said.

Regional Cooperation

Offshore wind is a signature initiative of President Biden, who has set a national goal of 30 GW online by 2030 and directed his administration to make progress toward it.

But states have a large regulatory role of their own in the buildout, as well as individual targets that add up to more than 30 GW.

The potential exists for competing and/or duplicated efforts if each state pursues its own priorities without coordinating with its neighbors.

The East Coast Memorandum of Understanding on Offshore Wind Supply Chain Collaboration announced Thursday includes Connecticut, Maine, Maryland, New Hampshire, New Jersey, New York, North Carolina, Rhode Island and the U.S. Departments of Commerce, Energy, Interior and Transportation.

The states will develop subregional plans to harness each other’s strengths and fill high-priority gaps while advancing economic development and environmental justice.

The Cabinet agencies will provide technical support to the states and help develop a share procurement and leasing timeline.

The Atlantic Coast from North Carolina to Massachusetts is the focus of early offshore wind development, because existing fixed-bottom turbine technology can be used there. Floating turbine technology still in development will be needed in the deeper waters off the Pacific coast and off Maine. To the south, the first Gulf of Mexico wind lease auction this summer fell flat.

But the White House said these early investments in the Northeast will bring future benefits of national scope, creating a viable U.S. supply chain for the new industry.

Also last week, the U.S. departments of Energy and Interior issued an action plan to build an interregional offshore transmission grid cable in Northeast and Mid-Atlantic waters.

The plan is a suggested road map for Northeast states to follow in the interest of reducing the price tag and increasing capacity.

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Coastal Virginia Offshore Wind Environmental Report Published

Federal regulators on Monday published the final environmental impact statement for Coastal Virginia Offshore Wind, setting the stage for approval of the largest wind farm yet in U.S. waters.

Dominion Energy proposes to erect 176 wind turbines and three substations in a 112,800-acre lease area 27 miles off the Virginia coast.

In its environmental report, the U.S. Bureau of Ocean Energy Management said CVOW could have major adverse effects on the fishing industry, the North Atlantic right whale, vessel navigation, onshore wetlands, and search and rescue operations.

Monday’s report is the fourth final environmental impact statement BOEM has published this year. Completion of the study typically is followed in fairly short order by a Record of Decision — the last major hurdle in the federal regulatory process.

All four Records of Decision issued so far have been approvals.

The final environmental report was published this month for Empire Wind, putting it in line to be the fifth major offshore wind project green-lighted in U.S. waters. Unless CVOW jumps ahead, it would be sixth.

The CVOW environmental impact statement specifies a project with up to 202 turbines and up to 3,000 MW nameplate capacity. A Dominion news release Monday specified a 2,587-MW project, which would be larger than the five wind farms ahead of it in the federal review process.

The CVOW environmental impact statement differs from some of the others in that it does not list cumulative impacts.

The first two utility-scale offshore projects to start construction, Vineyard and South Fork, are part of a tight cluster of lease areas off the New England coast; the New York Bight contains another grouping of lease areas. Such concentrations of projects create potential for a collective impact beyond whatever individual impact a given project might have.

But CVOW still has few potential neighbors at this stage in the U.S. push to develop an offshore wind sector.

As with the other projects’ environmental impact statements, the potential effects of CVOW are presented as a range of possibilities — some of them positive, some negative, some either.

The net impact on air quality, for example, is predicted to be minor but could be adverse or beneficial. Birds might suffer negligible, minor or moderate adverse effects, or they might see minor beneficial effects.

Even the for-hire recreational fishing industry might see some benefit, if the underwater structures create habitat favorable for the species sport anglers like to catch.

Commercial fishing, however, potentially faces a double negative — changes in the number or behavior of species that are valuable for food and constraints on catching them near underwater infrastructure.

Dominion welcomed the environmental impact statement in a news release Monday, saying it reflects feedback from stakeholders.

CEO Bob Blue said: “The completion of CVOW’s environmental review is another significant milestone to keep the project on time and on budget. Regulated offshore wind has many benefits for our customers and local economies — it’s fuel free, emissions free and diversifies our fuel mix to maintain the reliability of the grid. Today’s announcement reinforces the confidence that the company, our vendors and our suppliers have in our project’s completion, providing further motivation to maintain focus on delivering on time and on budget knowing we and our government partners continue to meet critical milestones.”

The company said more than 750 people in Virginia are working on the project directly or in a supporting role.

The Business Network for Offshore Wind said approval of CVOW would bring the pipeline to more than 7 GW. It also supports critical supply chain development as the industry gets started in the U.S., said John Begala, a vice president at the trade organization.

In a news release, Begala said: “Dominion’s CVOW project is anchoring a critical corner of the emerging domestic supply chain, and advancing this project means supporting development of America’s first wind turbine installation vessel, the siting of a blade assembly factory and substantial port redevelopment work. The Hampton Roads area is abuzz with offshore wind activity, and the federal government’s advancement of the CVOW project will continue advancing the area as a hub for the whole industry. The network applauds BOEM for maintaining consistent, timely reviews of COPs while ensuring environmental protection.”

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PJM MRC/MC Briefs: Sept. 20, 2023

Stakeholders Approve Generation Deactivation Issue Charge

VALLEY FORGE, Pa. — The Markets and Reliability Committee voted Wednesday to approved a joint PJM and Independent Market Monitor issue charge to create a new senior task force charged with exploring changes to the timeline in which generators must notify PJM of their intent to retire a resource and how compensation is determined under reliability-must-run (RMR) contracts.

The issue charge passed with 67% support over a competing issue charge proposed by Vistra, which would have tackled the same core topics, but with additional language intended to make the in and out of scope components more explicit. Vistra’s Erik Heinle said the company’s language was built off the PJM/IMM proposal and also would have sought to ensure minimal disruption to the markets when an RMR is implemented, provided better balance by taking the need for operator flexibility into account, added education items — including around the reliability backstop — and tightened the focus of when an RMR contract should be considered.

Presenting the problem statement and issue charge, PJM’s Chris Pilong said there is a concern the increasing pace of generation retirements expected over the next decade will increase the need for RMR contracts. He said the process of reaching an agreement with generators is not standardized and takes considerable time, prompting a desire to get more lead time from resources ahead of their desired deactivation date and to streamline the process.

The committee deferred voting on the proposal during its August meeting as stakeholders continued fine-tuning the scope. (See “Stakeholders Defer Vote on Generation Deactivation Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)

While Pilong said PJM didn’t have any deal-breaking objections to Vistra’s language, he felt the core of what Vistra was seeking already had been captured in PJM’s issue charge and the additional language around the scope of the discussion was unnecessary and raised procedural issues around how detailed issue charges should be.

Both the PJM/IMM and Vistra issue charges originally would have precluded any solutions that included changes to market rules. However, several stakeholders argued the existing rules do not adequately define how resources operating under an RMR contract fit into the energy and capacity resource stacks and interact with the clearing price. The revised issue charges drafted during the meeting were both modified to include the supply stack and clearing price as being in scope. The Vistra proposal also saw added language about minimizing impacts to consumers added during the meeting.

Pilong said PJM’s intention was that interactions with the supply stack and clearing price would be an educational item and if stakeholders determined that market changes are necessary, that could be referred to another stakeholder group.

Constellation’s Adrien Ford said she believed the resource stack would be considered in scope and having it be to the contrary would cause her to second-guess her support for the issue charge. She said the use of RMR contracts are an indicator of market failures and she would not be comfortable with altering RMR rules without considering changes to rules to address the impact of a potential RMR on the market.

Independent Market Monitor Joseph Bowring said he was happy to see stakeholders interested in addressing how RMR resources fit into the supply stack but cautioned against making the issue charge too broad.

“You can’t solve every problem in every issue charge,” he said. “… Let’s start a parallel one and get started on it immediately.”

Following stakeholder feedback during the first read of the issue charge, the PJM/IMM issue charge was revised to remove a third in scope focus for the new task force to address additional triggers for a retiring resource to qualify for an RMR contract beyond transmission constraints, with the given example of preserving ample supply of black start resources in a region.

Consumer advocates said the scope of the discussion should be balanced with the need to move quickly to shore up issues with the RMR process before an uptick in retirements manifests.

Susan Bruce, representing the PJM Industrial Customer Coalition (ICC), said it makes sense that if the compensation for RMR resources is open for discussion, the impact on the energy and capacity markets also should be part of the solutions on the table.

“Customers that are having to pay for an RMR want to make sure they’re getting the benefit they’re paying for. So I want to make sure we’re not foreclosing on options available in the future,” she said.

PJM Issue Charge on Reserve Certainty Approved

Stakeholders approved an expansive issue charge that aims to rework several areas of PJM’s reserve markets. The PJM proposal received 59% support over a second issue charge proposed by the Market Monitor, which would have focused the scope solely on addressing the decline in synchronized reserves response rate since a market overhaul was implemented in October 2022. (See “PJM Provides First Read on Reserve Certainty Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)

The document lays out a phased process for addressing six core issues over 12 to 18 months under a new senior task force. Resource performance and penalties, aligning the offer structure with fuel procurement and reserve deployment would begin immediately with the goal of completing in six to nine months. The task force would work concurrently on procuring a quantity of reserves that reflects system needs, with the goal of arriving at a solution in nine to 18 months.

Once the most immediate needs have been addressed, the remainder of the timeline has the task force moving on to the reserve product participation requirements and incentivizing resource flexibility.

PJM’s Donnie Bielak said the issue charge was revised since its first read to add education, particularly around how technology could be used to improve existing practices.

Brock Ondayko of AEP Energy questioned if there’s an opportunity to discuss PJM’s practice of holding resources to a 10-minute response time expectation, rather than the 15-minute mandate under NERC’s Disturbance Control Standard (DCS). Bielak said PJM would consider that a change to PJM’s compliance with reliability standards and therefore out of scope.

Bruce said the scope of the issue charge could cause it to overlap with ongoing work in other stakeholder groups and she questioned whether there is potential for a “feedback loop” where multiple groups take actions to increase reserve response or procurement and overcorrect.

PJM’s Becky Carroll said staff have worked with the Electric Gas Coordination Senior Task Force (EGCSTF) when shaping the issue charge and which components should fall under that group and the new task force.

Deputy Market Monitor Catherine Tyler said the PJM issue charge seeks to roll three different issues under the umbrella of a single issue charge: the synchronized reserve response rate, market issues highlighted during the December 2022 winter storm and maintaining adequacy reserves throughout the clean energy transition. She argued that the EGCSTF already is at work on issues related to Winter Storm Elliott and topics related to the transition and renewable resources would fall best under a separate issue charge.

By having all the issues PJM seeks to address under one issue charge, she said it’s likely any solution would focus on increasing reserve procurement at the expense of other possibilities, including changes to dispatch, market timing and unit commitment.

Ford said the Monitor’s language wouldn’t include discussion of compensation, which she believes needs to be addressed as part of a solution.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said state advocates preferred the Market Monitor’s proposal for being more narrowly focused on response rates, which he said is a clearly documented issue, whereas the other topics in PJM’s proposal have more moving parts and interactions with issues before FERC.

Jurisdictional Questions Raised Around Co-located Load Proposal

Stakeholders discussed a proposal that would create new rules for wholesale generators with co-located loads without supply from the system. The package, which was sponsored by Exelon in the Market Implementation Committee, was the only one of several proposals to pass, receiving 51% of the vote in August. (See “Stakeholders Endorse Proposal on Co-located Load,”  PJM MIC Briefs: Aug. 9, 2023.)

Generators would be permitted to retain their capacity interconnection rights (CIRs) equal the amount of energy supplied to co-located loads under the proposal and would be treated as a load serving entity (LSE) responsible for service charges and retail delivery costs. Current PJM rules require that generators relinquish a portion of their CIRs equal to co-located load they are serving under these configurations.

Several amendments were offered to the proposal, which largely were opposed by Constellation, with the exception of removing outdated language around cost-based offers. The amendments would remove the requirement that the load be capable of curtailing within 10 minutes on the basis that treating the generator as an LSE means the configuration would have its own metering and would be part of PJM’s load forecast. Any member can block amendments to the MRC’s main motion.

Exelon’s Sharon Midgley suggested the amendments could be considered as an alternate package.

Ford urged the committee to vote against the proposal, saying it would violate the Federal Powers Act (FPA) by treating load that isn’t receiving power from the PJM grid as being FERC jurisdictional. Constellation, joined by Brookfield Renewable, was one of several companies to offer proposals during the Market Implementation Committee’s discussion of the subject.

“It’s in the title. This is a not grid-connected package,” she said.

Midgley said the Exelon-sponsored and MIC-endorsed proposal considers the co-located load as end use and retail load, in line with Constellation’s definition. The MIC-endorsed proposal also allows the generator to offer the entirety of its resource into the PJM capacity market, which accommodates one of the key interests as expressed by Constellation and Brookfield.

Economist Roy Shanker said he believes the proposal would run into jurisdictional issues at FERC and it could set a bad precedent of states ceding jurisdiction over retail loads.

“This sets the stage for a real legal mess. The load being discussed here simply is not FERC jurisdictional load,” he said.

First Read of 2023 RRS Values

PJM’s Andrew Gledhill gave a first read of its recommended values for the 2023 Reserve Requirement Study (RRS), which calls for an uptick in its capacity procurement targets.

The installed reserve margin (IRM), which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year (DY) in the 2022 study to 17.6% for the 2027/28 DY. The forecast pool requirement (FPR), which considers forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs. (See PJM Presents Preliminary 2023 Reserve Requirement Study to Stakeholders.)

The study continues to base its results on the PRISM software PJM long has used to conduct its reliability modeling, rather than using the hourly model developed from its Effective Load Carrying Capability (ELCC) accreditation studies. PJM ran both sets of modeling for this year’s study and plans to phase over to just using the hourly approach in future studies. The hourly results would have resulted in higher IRM and FPR values.

Gledhill said this year’s study used a more granular hourly approach for its load modeling, separate from the ELCC model, which yielded a more comprehensive look at load uncertainty. Based on that data, PJM believes it has been under-forecasting summer load uncertainty.

James Wilson, a consultant for several state consumer advocates, said he has not heard concerns expressed about summer resource adequacy and questioned why PJM proposes to raise summer requirements by over 3 GW of additional capacity. He encouraged stakeholders to vote against the RRS values.

In addition to setting an initial IRM and FPR value for the 2027/28 DY, the study resets the figures for the previous three years. The preliminary results would be increased by a similar margin for each of those years.

Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-22 and use that figure, which landed at 1.5%, instead.

Fifth CONE Area Under Consideration

Stakeholders discussed a proposal to create a fifth cost of new entry (CONE) area for the Commonwealth Edison (ComEd) region in Illinois. The gross CONE in the new area would be $201,714/MW-year, while CONE Area 3, which ComEd is currently under, is $197,800/MW-year. (See “Competing Proposals Addressing Local Factors on Net CONE Merged,” PJM MIC Briefs: Sept 6, 2023.)

The change is the result of a process exploring how to account for local or state factors that could impact cost to build the reference resource in a specific region. PJM’s Gary Helm said the primary reason for calculating a separate CONE value for resources in the ComEd region is the requirement that generators be emissions free by 2045 under the state’s Climate and Equitable Jobs Act (CEJA).

“There is debate over whether that can or cannot be achieved, but in this case for all intents and purposes we would reflect that all natural gas resources, which is the reference resource, would have a reduced asset life,” Helm said.

The proposal would calculate a new CONE value for the new area by effectively applying an asset life factor with the assumption that the reference resource, currently a combined cycle resource, would retire in 2045. All other variables would stay the same at this time but could be changed during the next quadrennial review.

J-Power USA introduced a package to implement an automated process for the creation of new CONE areas in the future. That proposal was dropped when it concurred with PJM that the existing stakeholder process is sufficient.

Clara Summers of the Illinois Citizens Utility Board (CUB) said the proposal is very specific to Illinois and could set a precedent that other state consumer advocates should note.

Proposed Changes to Load Forecast Adjustment Timeline Discussed

The MRC reviewed proposed revisions to Manual 19 that would change the data PJM requests when electric distribution companies (EDCs) or LSEs submit load forecast adjustments. The new language would request hourly data as well as a 15-year forecast with a public document detailing how the forecast was created and move up the Load Analysis Subcommittee’s review of forecast adjustment requests to initiate in September and October. (See “PJM Presents Quick Fix on Load Forecast Guidelines,” PJM PC/TEAC Briefs: Sept. 5, 2023.)

The proposal is focused on providing PJM with more insight into data center load growth. In past MRC meetings, PJM’s Mary Mooney said data centers often can be built faster than other large loads, meaning there’s less time to plan and build needed grid adjustments, and the load often is not captured in the existing forecasting structure that is based on projected labor data.

Mooney said PJM would avoid double-counting load already captured in the forecasting it does based on economic data, but she does not anticipate this to be a major concern as data centers have outsized electric needs compared to their employment figures.

Wilson argued the proposal should require that a load adjustment be in the footprint of the relevant EDC. He also recommended PJM hire an independent consultant to do a study and forecast of long-term data center load, rather than rely on information provided by EDCs.

Members Committee

Nominating Committee

The Members Committee elected a new slate of sector nominees for the 2023-24 Nominating Committee during Wednesday’s meeting. The representatives will be as follows:

    • Electric Distributors: Bill Pezalla of the Old Dominion Electric Cooperative (ODEC);
    • End Use Customers: Susan Bruce of the PJM ICC;
    • Generation Owners: Marji Philips of Rolling Hills Generating;
    • Other Suppliers: Sean Chang of Shell Energy North America; and
    • Transmission Owners: Laura Yovanovich of PPL Utilities.

PJM Revises Code of Conduct to Promote Civil Discourse

PJM General Counsel Chris O’Hara said the code of conduct staff and stakeholders are held to has been updated in the wake of incidents where personnel have been singled out and attacked during meetings. The changes reflect expectations during stakeholder meetings and how PJM will respond to future incidents.

“These personal attacks are completely inappropriate. Personnel presenting on PJM’s behalf have the full backing of the PJM administration,” he said.

PJM has a legal obligation to create a workplace that is free of discrimination for its employees, O’Hara said. The appropriate venue for stakeholders to comment on PJM staff performance is the Liaison Committee.

Members Committee Chair David “Scarp” Scarpignato encouraged stakeholders to maintain a friendly decorum during meetings.

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PJM Members Lobby Board Ahead of Expected CIFP Filing

PJM members of all sectors have written letters to PJM’s Board of Managers urging that it direct PJM to file disparate changes to the capacity market in the wake of the critical issue fast path process (CIFP) that concluded in August with no proposals carrying the sector-weighted support of the membership.

American Municipal Power (AMP) called on the board to direct a narrower filing focused on reworking the nonperformance penalty rate generators pay should their units not meet their obligations during an emergency, as well as the corresponding annual stop loss limit, to be based on the Base Residual Auction (BRA) clearing price rather than the net cost of new entry (CONE).

AMP noted that although none of the CIFP proposals received sector-weighted support in August, the only proposal to receive a bare majority of support consisted of the changes to the nonperformance penalties. Shifting to penalties based on auction clearing prices also was endorsed by the MC in May, but was not included in a subsequent filing revising the capacity performance (CP) construct. (See FERC Approves PJM Change to Emergency Triggers.)

AMP said the August vote also showed considerable support for deeper changes to PJM’s capacity market, but also hesitation about making major changes with little time to conduct analysis and simulations to determine the potential effects.

“Many of the reforms discussed during the last five months still require more time for developing details and analyzing impacts. As AMP communicated early in the CIFP-RA process, the October 1 deadline is arbitrary and was an unnecessary impediment to developing a fully implementable set of reforms with broader support. Had more time been allotted the CIFP-RA process, stakeholders would have had adequate time to more fully understand the elements of each proposal and express their informed preferences,” the AMP letter said.

A broader consortium of power co-ops and industrial customers recommended a limited filing, followed by continued discussions with stakeholders on how to make changes to the core of the capacity market.

“The implications of those changes must be thoroughly evaluated in order for market participants, other stakeholders and this coalition in particular to understand the financial impacts on suppliers, load-serving entities and consumers. Implementation of reforms will require several capacity auctions in quick succession, and implementing these changes without fully considering their impact risks irreparable harm, and equally hasty and noncomprehensive follow-on mitigation efforts. Accordingly, additional time for consideration of all proposals is needed to ensure fair outcomes for everyone,” the letter said.

The PJM Industrial Customer Coalition (ICC) supported PJM’s proposal to increase modeling of winter risk, so long as the RTO continues to capture the reliability risks faced during the summer and the potential for electrification to exacerbate those risks. The ICC also supports the proposed expanded weather history, seasonal capacity testing requirements, adopting CP penalties and a stop-loss based on capacity prices, and requiring that generators report whether their fuel procurement contracts include firm service and potentially incorporating that into their accreditation.

Shell Energy North America argued the fast timeline for the CIFP process prevented a holistic and durable proposal from emerging and the discussion of market changes did not include full understanding of the barriers to investment in the capacity market. It stated that the forward markets have lost a significant amount of liquidity and seen a rise in the amount of risk investors take on. PJM’s proposed accreditation changes, new qualification standards for capacity resources and performance requirements would further increase market uncertainty, exacerbated by existing “regulatory uncertainty, administrative complexity and rule intervention.”

The Shell letter stated that many of the CIFP proposals would increase the administrative complexity of the capacity market and argued that future discussions should include the energy and ancillary service markets with the goal of increasing revenues from those markets to reduce reliance on the capacity market for maintaining reliability.

“Reliance on capacity markets as the primary mechanism for ensuring resource adequacy should be reduced over time as PJM transitions to a system with more intermittency. Energy and ancillary service market design enhancements can be administratively simple and transparent enough to effectively create market signals needed to address the unprecedented system changes and concomitant needs,” the letter said.

Several generators, including LS Power, J-Power and Talen Energy, submitted a letter recommending a “surgical filing” in October that includes portions of PJM’s proposal, while leaving the bulk of the capacity market intact. The recommended changes include shifting the reliability metric to expected unserved energy, a more granular hourly modeling in the reserve requirement study (RRS), seasonal capacity testing requirements, using weather history data going back to 1993 and more explicitly modeling the relationship between load patterns and weather in the RRS, fuel procurement contract reporting, and shifting the CP penalties to be based on the BRA clearing price with a corresponding market seller offer cap that reflects all capacity market risks.

The generators also recommend PJM continue to work with stakeholders to overhaul the capacity market in a way that improves transparency and replicability of market components, provides confidence that any changes will function as intended and has visibility into market risks and opportunities.

A letter from Talen Energy Marketing focused on how nonperformance penalties affected resources with long lead start times, arguing that not including an excusal for those generators unduly penalized them for operating according to the parameters included in their capacity offer.

“Shifting responsibility with respect to knowledge of the grid needs, including commitment and dispatch decisions, to generators by penalizing them during long start times, even if PJM dispatches them late or not at all, is untenable. It introduces risk that cannot be mitigated and likely will lead to the retirement of the very resources that are critical for reliability today and necessary for a reliable transition to a cleaner future,” Talen wrote to the board.

The East Kentucky Power Cooperative (EKPC) also encouraged a limited approach for any filing made in the near term, encouraging the board to revise the nonperformance penalty rate and to have resources dispatched consistent with their physical and fuel constraints. In the long term, EKPC recommended that the board direct staff to continue engaging with stakeholders to work toward a capacity model with hourly commitment.

Several environmental organizations and consumer advocates argued the cost implications the CIFP proposals would have for consumers was not adequately understood throughout the process and any filing should contain rules to protect against seller market power. It stated that PJM’s proposal includes a capacity performance quantified risk (CPQR) formula that would not include energy and ancillary service revenues, which it said would increase capacity costs without increasing reliability, would weaken the IMM’s ability to review capacity offers and would dilute the cost benefits of a seasonal capacity market with the design of the proposed demand curves.

The letter also said PJM’s proposal would not accurately reflect seasonal risk by not capturing the trend of increasing temperatures resulting from climate change and would zero out the capacity benefit of ties value by relying on a “binary, unrealistic and untested assumption” that no outside capacity will be available during critical hours.

The Organization of PJM States Inc. (OPSI) submitted a letter stating the majority of member states support PJM’s proposed changes to reliability risk modeling and increasing testing requirements for generators, which they believe would improve the ability to ensure generators that rarely are dispatched would be operational for future events such as the December 2022 winter storm.

The variability that led PJM to back away from a longer 50-year historical weather lookback displayed the sensitivity of PJM’s modeling, leading OPSI to recommend PJM justify its approach annually and develop a plan to use appropriate data selection going forward. The states opposed PJM’s proposal to retain the exemption that intermittent, storage and hybrid resources have from the requirement that generators enter the capacity market, which OPSI said raises market power concerns. Instead, the organization recommended that a future capacity market design align with all resources’ operating characteristics and require that all generation participate.

“Allowing certain exempt resources to retain Capacity Interconnection Rights will not allocate and properly ration costly and scarce transmission access rights to resources relied upon by customers to ensure reliability,” OPSI said.

American Electric Power, Dominion and Duke Energy Kentucky submitted a letter calling for a transitionary period for fixed resource requirement (FRR) entities to adjust to any new market design, arguing the potential for the changes to be effective for the 2025/26 BRA — scheduled for June 2024 — leaves them with little time to coordinate with state commissions and make necessary changes to their integrated resource plans or generation fleets.

The utilities requested the board include an expanded FRR transition mechanism of at least four delivery years and an off-ramp for new FRR entities for the first five years after they elect to go that route, maintain the physical penalty option for CP penalties and expand it to be applicable to all RPM capacity resources, and maintain the ability to net performance during a performance assessment interval. The letter also argues that any proposal should include recognition of the impact accreditation changes could have on state resource planning.

PJM’s proposed changes to resource accreditation were particularly worrisome to the utilities, which stated they could face a reduction in the rating of their resources amounting to as much as 30% with less than a year to make up for the lost capacity. Paired with PJM’s proposed changes to the penalties FRR entities could face if they fail to procure adequate capacity or do not perform during an emergency, the letter states FRR entities could face “unjust and excessive penalties” if they’re not provided with time to adjust to market changes.

“These changes, combined with the expedited nature of the CIFP-RA process, make it very difficult for FRR entities to understand what their underlying positions and obligations will be under the new construct, thus creating greater uncertainty and introducing additional risk,” the letter said.

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Stakeholder Soapbox: Beware of Government-driven Climate Policy

By Kenneth W. Costello

Climate change presents a daunting challenge for economists, political scientists and policymakers: It features a global shared resource (namely, the atmosphere) magnified by massive uncertainty over both physical and economic processes; everyone contributes to its cause, and everyone potentially bears the costs of its consequences.

Three policy challenges ensue: (1) taking collective action, where cooperation of countries is essential to achieve targeted reductions in greenhouse gas emissions, (2) incentivizing individuals and businesses to reduce their GHG emissions, and (3) identifying the preferred institutional arrangement — namely, markets versus government — to alleviate the damages from climate change.

climate policy

Kenneth W. Costello |

A major problem is that when one country benefits from initiating reductions in GHG emissions, other countries also benefit. The reality that controlling climate change in one country cannot deprive others of the benefits motivates individual countries to avoid paying for mitigation, creating the problem of what economists call free ridership.

Since changes in GHG emissions affect the entire world, any successful coordination would require virtual unanimity rather than just coalition building. But as past experience has shown, reaching mutual consent among multiple heterogenous countries is a Herculean task. (How many U.N. Climate Change Conferences have we had? I lost count.)

Policymakers confront the task of trading off the risk of doing too little to combat climate change with excessive spending or regulating. The ideal policy position on climate change depends critically on the size and likelihood of negative outcomes, considering the best available scientific and other fact-based evidence.

Reasonable people can disagree over the cost of an overly active climate strategy versus the cost of a passive one. Disagreement starts with the credibility of the scientific evidence. People may question the sureness of the scientific evidence. They may also have trouble distinguishing scientifically sound evidence from advocacy evidence.

Disagreement may then shift to the relevance of this evidence for public policy. Here, self-interest motives and ideology play key roles. People tend to adhere to their prior beliefs irrespective of the scientific evidence. These beliefs carry over to the relative costs they place on an overly aggressive climate policy relative to an overly passive policy. All of these factors contribute to the difficulty of reaching political consensus.

For example, the preferred strategy depends (among other things) on people’s risk aversion to the damage that climate change can cause. Some people may struggle more with an incorrect scientific conclusion that climate change has a high risk when in fact it has a low risk; the opportunity cost is in the form of excessive resources allocated to slowing climate change, which inevitably results in lower economic growth and other social costs.

Climate policy certainly falls into a space where government action could very likely have bad consequences. This is especially true for green subsidies for renewable energy and energy efficiency, which although widely popular likely fails a cost-benefit test.

Subsidies encourage rent seeking by special interests and allow policy makers to determine which technologies to champion. Subsidies for renewable energy have been especially attractive because of their claim to improve air quality and create new jobs, while their costs are concealed in the larger government budget. It is harder to sell the public on, say, a carbon tax whose costs are more visible and concentrated on consumers.

Economists consider subsidies for almost anything to be economically inefficient, usually politically motivated, and lasting too long. Their preference is to have the government reallocate funds for basic research. But, not surprisingly, political forces have given higher priority to existing clean technologies with their strong lobbyists than to potentially future ones.

Rent seeking in the form of exploiting government to gain favors tends to concentrate the benefits to these groups while spreading the costs to the general population. A good example is interest groups pressuring state utility regulators and legislatures to use subsidies funded by utility customers and taxpayers to promote energy efficiency, distributed generation, electric vehicles, and other clean-energy technologies.

This inevitably leads to cost subsidization, which (among other things) is unfair to both utility customers and taxpayers who do not benefit. Unfortunately, the evidence confirms that an increasing number of states have been at the vanguard of bad policies that have inflicted a regressive-tax-type wound on lower income people. The reason is that lower-income households spend a larger percentage of their incomes on electricity, and these policies tend to increase electricity prices. For the electric industry, an obsession with climate change threatens policy objectives long adhered to by state utility regulators.

But isn’t it also true that a fixation with climate change, bordering on irrational climate hypochondria, can deprive impoverished people, especially in less-developed countries, of the resources required for survival or progress? This makes little economic sense and reflects the insensitivity to the plight of poor people from those in wealthy countries absorbed with climate change and renewable energy, and the ridding of fossil fuels. Fossil fuels have been a vital factor in the economic growth of less developed countries. There is a serious “equity” problem here.

Relevant to climate action is also the intergenerational issue of whether people today should sacrifice under an aggressive climate policy to benefit people in the far-out future, who are likely to have a much higher standard of living. Some climate activists view anything less than an all-out effort to attack climate change as a social injustice.

In economics, public choice theory predicts that government, composed of bureaucrats and politicians, lacks the necessary information and the right incentives to pursue policies that are in the public good.

We see numerous real-world examples where actual public policies in all areas of society deviate far from what so-called “blackboard economics” would say is ideal. Such divergence typically results from information deficiencies, institutional realities, and the government’s incentive to serve its self-interest and appease special interests rather than the public good. Can we then expect any climate policy dominated by interest-group politics to be in the public good?  What we have seen up to now says no.

Either for ideological or monetary reasons, climate advocates want to shape future climate policy, and the sooner the better. Their self-interest motive benefits only themselves, not the broader public interest. Their vision of the future entails filling up their pockets (e.g., clean-energy vendors) or satisfying their followed doctrine (e.g., environmentalists). They have relentlessly lobbied politicians and bureaucrats at all levels of government for special favors. This reality by itself warrants nongovernmental options to address climate change.

Given the problems faced by government-driven climate policy — a particular one that I have mentioned is subsidies for clean energy — more attention should focus on measures that strengthen market signals for individuals to adapt to climate change. These measures may include adaptation based on the pricing mechanism, companies satisfying the demands of consumers and investors for clean products, and governmental assistance for basic research in clean-energy technologies (for instance, nuclear power, renewable energy, and hydropower) and climate engineering. Consumers and investors can reveal their preference for financial assets or products and services that explicitly account for climate change. They have done so already, and we should expect this development to proliferate in the future. But, so far, regretfully market-centric approaches have taken a back seat to government-driven climate policies.

We will surely see in the years ahead more political posturing in mitigating climate change. So much talk and money has been expended on government-driven climate policy. What have we gotten out of it? I would say probably very little in terms of global temperature – no more than a rounding error. Don’t expect things to improve in the future.

The bottom line: spending a lot of money on climate change with status quo policies will likely have a negative social return. The sooner we realize that, the better off we will be.

Kenneth W. Costello is a regulatory economist and independent consultant.

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ERCOT IMM Raises Concerns over Newest Ancillary Service

ERCOT’s Independent Market Monitor says the grid operator’s recent implementation of its first ancillary service in 20 years has nearly doubled the amount of required online reserves, resulting in “enormous” increases in market costs and shortage pricing when the market is long.

Carrie Bivens, the IMM’s vice president, told stakeholders Friday that procuring and deploying the ISO’s newest ancillary service (AS), ERCOT contingency reserve service (ECRS), has reduced supply and liquidity in the day-ahead market and “significantly” raised demand for AS products. That has resulted in inefficient day-ahead AS price spikes, she said.

“We’re seeing a disconnect between the operational realities and the pricing outcomes,” she said during a Wholesale Market Working Group meeting. “It’s also causing reliability issues, in our opinion, by increasing the challenges with managing congestion because fewer megawatts are available for scheduled dispatch to manage congestion … we’ve seen that on a few days you’re seeing a huge increase in market costs.”

Carrie Bivens, Potomac Economics | © RTO Insider LLC

AS services have incurred $1.56 billion in costs this year through August, Bivens said. ECRS, which began June 10, is responsible for almost 39% of those costs, or just over $608 million.

She said while the costs are substantial, they are much lower than the effects of removing the additional reserves from real-time market dispatch. Increasing online reserve procurements with ECRS “likely” raised the real-time market’s energy value by $8-10 billion in three months, Bivens said.

“Price spikes in the day-ahead market are not necessarily reflective of the underlying conditions,” she said. “The huge costs that we are really keying in on are the ones from [the] real-time market by removing those reserves. Taking megawatts that would have been available for energy dispatch and making them unavailable is reducing the supply available … that is causing this increase in real time energy prices, even though we have tons of reserves.”

The new AS is economically dispatched within 10 minutes of deployment, using capacity that can be sustained at a specified level for two consecutive hours. ECRS essentially meets the same reliability requirements that previously were met solely by responsive reserve service (RRS), the IMM pointed out.

ECRS has resulted in a 2,500-MW increase in online reserve procurements, moving the MWs behind the high ancillary services limit (HASL). Bivens says that has resulted in artificial pricing shortages when total reserve levels are high and a negative effect on congestion management, as more MWs needed to address congestion are reserved for ECRS or RRS.

She said the artificial tightness is “episodically mitigated” by the operators’ deployments, which interferes with day-ahead market decisions, whether to self-commit resources in real time and resource offers — all of which are based on expectations of real-time prices.

IMM staff arrived at the $8-10 billion figure by simulating the real-time energy market with reconstructed offer curves for lower ECRS procurements. Their analysis cleared the input MW quantity at the generation requirement’s original SCED execution. Once a baseline scenario was done, staff modeled incremental 25% releases of ECRS in subsequent scenarios and calculated energy cost reductions.

Real-time ECRS deployments were maintained so that none of its additional capacity was released if deployments exceeded the release percentage. The simulation did not model congestion, ramp limitations, controllable load resources’ dispatch or the power balance penalty curve.

“We wanted to show is this a small problem or is this a big problem?” Bivens said. “This is an order of magnitude type of analysis and what this is showing is that indeed it is a large problem.”

Jeff Billo, ERCOT’s director of operations planning, pushed back against Bivens’ presentation and the IMM’s call for a holistic review of ECRS, among other recommendations. He acknowledged inefficiencies and additional market costs but said ERCOT is getting the reliability it needs.

“When I look at the data that was presented, I don’t see anything that backs up those recommendations other than ancillary services are really expensive or they’re causing outcomes in the market that are really expensive. I don’t see any data showing that we’re getting more than we actually need,” he said. “I also don’t agree with the term artificial scarcity because this is a reserve product that we are buying, so it is meant to be held in reserve. It’s not artificial, it is on purpose. We are reasonably reserving megawatts that we may need for various conditions that may occur on the system.”

“I think we just want to make sure that you’re buying what you need to be reliable, and no more than that,” Bivens responded. “And also, I think we need to ask the question of the ECRS that we got this summer, ‘Was it worth $10 billion?’ That’s something that I think I would ask people to think about.

“A lot of these megawatts, particularly during the summer, they’re going to be online anyway,” she added. “All you’re doing, and why I’m calling it ‘artificial scarcity,’ is you’re taking megawatts that would have been online for energy and putting them behind the HASL. And that’s what’s causing the cost increase. It’s not that we’re getting more megawatts. It’s just how we’re treating them.”

The IMM recommends ERCOT reduce the ECRS’ two-hour duration requirement to a single hour to encourage more storage participation. Its other recommendations include:

    • Reducing ECRS’ frequency recovery MW procurement;
    • Removing the 2,800-MW floor on RRS;
    • Changing the non-spin error requirement from six hours ahead to three; and
    • Using 10-minute ahead net load errors for ECRS methodology.

The recommendations are based on the 2023 AS methodology and will be updated when ERCOT staff publishes its 2024 for the services, Bivens said.

The Texas grid operator launched ECRS in June. It was the first daily-procured ancillary service introduced to the market in more than 20 years.

ECRS’ development began as a protocol change, approved in 2019, designed to address forecasting errors from the increased penetration of renewable resources or to replace deployed reserves. The change also modified responsive reserve service to be primarily a frequency response.

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FERC OKs MISO Removal of Annual Reviews for Long-term Tx Projects

MISO is off the hook for having to conduct annual cost-benefit analyses of its major transmission projects, FERC has ruled.

FERC on Friday allowed MISO to cut the portion of its Tariff requiring it to conduct annual benefit reviews of its long-term transmission projects. The RTO still will conduct its more comprehensive triennial reviews (ER23-2478). The commission’s approval was effective Sept. 24.

FERC said it was persuaded the annual reviews “have become less useful over the years given the development of alternative sources of similar information.” The commission said it didn’t think the discontinuation of the reviews would affect project transparency in MISO.

In July, MISO proposed eliminating the four limited annual reviews required of it for long-term transmission projects. That will leave the RTO conducting two triennial reviews of projects following project approval. It said the move will “drive administrative efficiency for MISO, its stakeholders and regulators.”

According to MISO, removing the limited reviews will allow it to spend more time planning portfolios of other long-range transmission projects. It also said the annual reviews usually only uncover “minimal data changes” year-over-year and said info on transmission projects’ progress is available to stakeholders on its website, through its Transmission Expansion Plan (MTEP) quarterly status updates and contained in its variance analyses. MISO performs variance analyses on projects only when they materially change in cost, schedule or design from MISO approval.

MISO’s triennial review requires it to calculate economic benefits of major projects, such as congestion and savings and the ability for the RTO to carry a smaller amount of reserves. It also requires MISO to evaluate achieved public policy targets, like the amount of new renewable energy the line can bring to the system, and perform five-year historical examination of the line’s effect on the fleet mix, interconnection trends, energy prices, fuel costs and margin requirements.

On the other hand, the limited reviews required MISO to calculate the latest data available of the economic benefits and five-year historical trends.

The Organization of MISO States supported the pruning of reviews, saying its remaining reporting requirements are sufficient to stay up to date on transmission projects. However, the group of state regulators requested FERC order MISO to “consistently and accurately” update its long-range project dashboard and quarterly status reports on its MTEP portfolios to ensure they’re useful. OMS said MISO has been inconsistent in updating actual project costs and in-service dates, which limits regulators’ ability to question transmission developers’ cost containment efforts.

FERC, however, said the OMS concerns were beyond the scope of the proceeding and declined to address them. MISO said FERC should disregard the OMS request because it’s already working to upgrade its admittedly outdated MTEP project portal, the database it maintains for approved projects.

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NYISO Stakeholders Discuss Enhanced Regulations for Information Sharing

RENSSELAER, N.Y. — NYISO soon could significantly tighten its security and information protection requirements, according to a presentation given to stakeholders last week.

Troutman Pepper, an energy law firm, advised the Transmission Planning Advisory Subcommittee and Electric System Planning Working Group meeting that as digitization grows, enhancing NYISO’s critical energy and electric infrastructure information (CEII) protection has become increasingly important.

Kat O’Konski, an associate at Troutman Pepper, said, “there is a pressing need” to improve CEII requirements because both “physical and cyber assaults on the grid are at a record high.” (See Feds Charge Idaho Man in Dam Attacks; NERC’s Cancel Details Grid Threats to House Energy Subcommittee; DERs’ Deployment Leads to Increasing Cyber Threats.)

Troutman wants to toughen measures around NYISO’s data dissemination by requiring third parties working with and around the ISO’s supply chain to implement more stringent protocols for CEII sharing and access.

These enhancements include mandatory cyber-training for certain workforces and obtaining cybersecurity risk insurance, as well as recommending that sensitive data be stored in multiple geographically isolated data centers to provide an added layer of redundancy.

Troutman requested that its proposals to tighten NYISO’s security and information-sharing procedures be approved quickly but some stakeholders were skeptical about the proposed implementation timeline and whether the CEII protections were more restrictive than protective.

Doreen Saia, an attorney with Greenberg Traurig, said Troutman was unrealistic to expect its proposals could be approved before the end of the year, given the number of meetings and the upcoming holiday season, as well as considering the breadth of the proposal.

Stu Caplan, partner at Troutman Pepper, asked what a realistic timeline would be. Saia responded that her firm would need at least a month or more to review the requirements, but that multinational organizations likely would need even more time to comply with the requirements, particularly those related to geographic data storage.

Glenn Haake, vice president of regulatory affairs at Invenergy, concurred with Saia, noting how multinational companies might struggle with these requirements, particularly if the rules vary by country of origin.

O’Konski sought to mollify these concerns by noting how Troutman’s proposals are intended to create a single set of CEII standards applicable for everyone.

Kevin Lang, partner at Couch White, in reference to expanding the list of personnel required to obtain CEII clearance, said Troutman needs to consider that not every NYISO market participant has the same level of resources as transmission owners and to ensure its requirements are not preventing smaller businesses from accessing the ISO’s data.

There was a consensus on the need for enhanced CEII protections and no one opposed the measures outright, but stakeholders wanted to guarantee a balance between security and accessibility.

Troutman will return with a more detailed proposal and requested feedback be sent to either Caplan or O’Konski by Sept. 28.

System & Resource Outlook

NYISO updated stakeholders that the base case lockdown date for the biennial System & Resource Outlook report has been set for Oct. 15.

The base case serves as the foundational set of initial conditions, scenarios and assumptions used in the Outlook’s modeling.

The 20-year forecasting report examines how New York’s transmission system develops, performs, and responds to the state’s aggressive climate and energy legislation. (See “System & Resource Outlook,” NYISO Previews New York City Transmission Needs Assessment.)

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FERC Directs J.P. Morgan to Declare Affiliations of Two Holding Firms

FERC issued an order Thursday finding J.P. Morgan Investment Management qualified as an affiliate of Mankato Companies and IIF US Holding 2, through which it is tied to other firms, including El Paso Electric.

The order came after a Section 206 briefing process FERC started after consumer group Public Citizen questioned the investment bank’s ties to firms it said were not appropriately disclosed.

Public Citizen said the investment bank effectively controlled IIF, through Mankato and other subsidiaries. The two legal entities share employees and effectively let the investment bank make decisions on running IIF.

FERC found the relationship between J.P. Morgan Investment, IIF and Mankato was such that there is liable “to be an absence of arm’s length bargaining in transactions between them,” so it’s appropriate to consider them affiliates for the protection of investors and consumers.

The two firms share operations under an Investment Advisory Agreement and a Partnership Agreement, which delegate J.P. Morgan Investment broad duties to run IIF. A J.P. Morgan Investment employee sits on the board of directors of Onward Energy as a representative of IIF.

“We emphasize that in the market-based rate context, an assessment of affiliation is necessary to understand the relationships between entities to ensure that rates are just and reasonable, to protect against the exercise of market power and to protect customers from affiliate abuse that can result from affiliate transactions, regardless of the presence of fiduciary duties,” FERC said.

Employees of J.P. Morgan and J.P. Morgan Investment signed the partnership agreement and investor advisory agreement for both firms. That at least shows J.P. Morgan was empowered to execute documents that bind IIF into agreements, including agreements with the investment bank itself.

The investment agreement between the firms authorizes J.P. Morgan as investment adviser to “have full authority to undertake and perform any and all acts deemed necessary or appropriate by it in connection with the rights, powers and duties delegated to it.” The partnership agreement explains J.P. Morgan has the power to manage IIF’s business and affairs, to make business decisions, to act on its behalf and take any actions it deems appropriate.

“These rights and powers allow J.P. Morgan Investment to make virtually every major decision on behalf of IIF US Holding 2,” FERC said.

The commission directed Mankato to file a change in status and update its asset appendices to reflect J.P. Morgan Investment as an affiliate. The firm’s market power analysis will need to be updated to reflect the affiliation.

The order drew a concurrence from Commissioner James Danly, and a response to that from Chairman Willie Phillips.

Danly wrote to make clear that while he supports the outcome of the order, he takes issue with the majority’s reasoning. He argued concurrences should be the same as a dissent as a result.

“I disagree with the means by which we arrive at that conclusion,” Danly said. “I do not believe that we need to disclose privileged information to the extent we do to justify our conclusion. We could and should have been more measured.”

Phillips said concurrences amount to the opposite of a dissent and Danly cited no precedent supporting his view that concurrences should be treated that way on review by the courts.

“Commissioner Danly is, as ever, entitled to his opinion,” Phillips said. “I write separately to stress that I do not share that opinion and to underscore that Commissioner Danly is not stating the commission’s view on this issue. As Commissioner Danly correctly notes in his concurrence, it is our agency’s ‘institutional decisions — none other — that bear legal significance.’”

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ISO-NE Must Include Pumped Hydro in Inventoried Energy Program, FERC Rules

ISO-NE must include pumped storage resources in its Inventoried Energy Program (IEP), FERC ruled on Thursday, siding with Brookfield Renewable Trading and Marketing in the company’s complaint against the RTO (EL23-89).

The IEP is intended to compensate resources for storing extra fuel they otherwise would not procure during periods of winter reliability risk. (See FERC Approves Updates to ISO-NE Inventoried Energy Program.) The D.C. Circuit Court of Appeals ruled in 2022 the IEP cannot extend to nuclear, coal, biomass and hydroelectric resources because the program would not result in a change of their fuel storage behaviors.

Following the D.C. Circuit ruling, ISO-NE submitted — and FERC approved — a version of the IEP which excluded the specified resources, including pumped storage. Brookfield Renewable, which operates a 633-MW pumped hydro storage facility in western Massachusetts, filed a complaint over the exclusion of the resource type in August.

In FERC’s ruling on Thursday, the commission said the D.C. Circuit ruling does not preclude the inclusion of pumped storage because these facilities fall under the category of electric storage facilities, which are allowed to receive payments in the IEP.

“As the ISO-NE tariff currently permits battery storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, it is unduly discriminatory to prohibit pumped storage electric storage facilities, which similarly store energy to later inject the energy into the system, from being eligible to participate in the Inventoried Energy Program and receive those payments,” the commission wrote.

FERC wrote that IEP payments likely would incentivize pumped storage facilities to alter their behavior and boost reliability in the region.

“Allowing pumped storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, similar to other electric storage facilities, can alter their incentives and thus their behavior by providing an incremental financial incentive to store energy,” the commission wrote in the Sept. 21 ruling.

FirstLight Power and the New England Power Generators Association both submitted comments in August supporting Brookfield’s complaint, while a group of consumer-owned power companies opposed it.

The consumer-owned power companies argued the complaint was attempting to relitigate previous findings and that including pumped storage in the IEP would not result in more stored energy.

“Brookfield’s complaint fails to show that any system-wide incremental energy production would result from extending the IEP’s incentive compensation mechanism to pumped storage hydro facilities,” the group wrote.

In its complaint, Brookfield argued pumped storage operates in the same way as any other type of electric storage.

“The fact that one ESF [electric storage facility] may use pumped storage technology and another ESF may use a chemical battery is irrelevant because they both are able to provide the identical winter reliability service through the IEP,” Brookfield wrote. “Because all ESF technologies operate under the same economic principles, the same incentive exists for all ESFs to provide reliability service through the IEP.”

ISO-NE told FERC it did not oppose the inclusion of pumped storage in the IEP but said it believed the D.C. Circuit ruling prevented their inclusion in the program.

“The D.C. Circuit’s Belmont decision did not differentiate between pondage and pumped hydroelectric resources, but instead simply indicated that ‘hydroelectric’ resources must be excluded from the IEP,” ISO-NE wrote. “The Belmont court did not provide any exception for pumped hydroelectric resources to participate in the IEP as ESFs.”

ISO-NE had said it needed a FERC order by Sept. 22 to include pumped storage in the IEP for the upcoming winter.