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November 5, 2024

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PJM Hears Proposals to Redesign EE Participation in Capacity Market

VALLEY FORGE, Pa. — PJM stakeholders presented several proposals to revise how energy efficiency resources are measured and verified to the Market Implementation Committee during its July 10 meeting as the number of complaints filed at FERC against the RTO’s handling of EE market participants has grown to three. 

Affirmed Energy argued that while the focus on measurement and verification (M&V) has dominated the stakeholder process on EE, it is secondary to the root issue of the addback: a process in which EE that clears in a Base Residual Auction (BRA) is removed by the supply stack and an equal amount of megawatts are added to the load forecast. 

Affirmed’s Luke Fishback said the company’s proposal would aim to improve PJM’s load forecast using data from the Energy Information Administration’s National Energy Modeling System (NEMS) and only allow EE that is not captured by the forecast to participate in the capacity market. Once there is no overlap between the load forecast and market-participating EE, he said the addback could be removed and EE resources could act as reliability resources with the ability to displace other capacity offers. 

The addback is the subject of a complaint that the consumer advocates for New Jersey, Maryland and Illinois filed against PJM last month, arguing that it improperly prevents EE from acting as a reliability resource and is a substantial change that should have been codified in the RTO’s governing documents and approved by the commission prior to implementation (EL24-118). (See PJM Consumer Advocates File Complaint on EE Market Design.) 

Given the complaints pending over the addback, Fishback argued any changes to PJM’s M&V rules likely would be disrupted by commission orders requiring changes to the EE market design. Moving forward prior to the resolution of those complaints and a reworking of the addback would be “putting the cart before the horse,” he said. 

Affirmed itself filed a complaint against PJM on July 5, arguing the RTO is improperly withholding collateral that the company posted for the 2023/24 delivery year even after approving the company’s capacity offer, approving its post-installation M&V report and the conclusion of that delivery year (ER24-124). 

The complaint states PJM is withholding the collateral because of an investigation FERC’s Office of Enforcement initiated in 2021. The company wrote that it has begun laying off employees and, without the return of the funds, could be “forced out of business.” 

The Independent Market Monitor also filed a complaint against Affirmed and several other EE providers in May alleging they had not met the BRA’s M&V requirements and should not be paid for the claimed EE megawatts in the 2024/25 delivery year (EL24-113). (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.) 

PJM: Require Sole Causal Link Between Capacity Market and EE Installations

PJM presented to the committee its own proposal, which would tighten the participation requirements for EE resources to allow only those that can demonstrate that capacity market revenues were the only deciding factor in them materializing. 

PJM’s Pete Langbein said participation should be contingent on auction revenues causing a corresponding decrease in load. “People need to do something to get paid,” he said. 

Affirmed’s Luke Fishback | © RTO Insider LLC

Midstream and upstream programs, which work with manufacturers and retailers to stock shelves with more efficient devices, would be required to validate that participating appliances were installed and in use within the locational deliverability area in which the capacity is participating. End-use customer data would be required upon PJM request for all installations. 

The period for which EE could participate in the capacity market after the installation would be shortened from four years to one, and EE no longer would be permitted to be included in fixed resource requirement (FRR) plans. FRR entities instead would be required to offer EE into the BRA. 

PJM proposed a timeline of endorsement in August, a FERC filing the following month and an order in November. Langbein noted the deadline for post-installation measurement and verification (PIMV) reports is in November, but the aim is to have an order before the 2026/27 BRA scheduled to be conducted in December. 

CPower’s Aaron Breidenbaugh said the 100% causation requirement is the most problematic component of PJM’s proposal and would set the bar so high that none would be able to reach it. 

Fishback challenged PJM’s causation principle by noting that generators are built with the expectation of revenues beyond the capacity market. He said it effectively would eliminate EE participation in PJM’s market. 

CPower Proposes Standardization of M&V, Separate Issue Charge on Addback

CPower proposed creating a process for reviewing M&V methodologies proposed by EE participants, potentially including retaining a third party evaluator. Unlike PJM’s proposal, it would not include any time limit on the validity of using state technical reference manuals (TRM) in M&V plans. 

A tracking system for registering EE installations would be established to ensure that no projects are being double counted between EE providers, which Breidenbaugh said would be akin to the demand response registration process. The physical location of EE installations would be required to be identified to at least the electric distributor company. 

Breidenbaugh said the proposal is designed to create a more standardized process for M&V, including by requiring nonproprietary methodologies to be made public. 

The proposal also includes a problem statement and issue charge focused on revising the addback and EE forecast model, which Breidenbaugh said is meant to “divorce the issues associated with measurement and verification from some of the more contentious issues.” 

Paul Sotkiewicz, president of E-cubed Policy Associates, said the M&V of EE offers stands apart from other resource classes because they are not required to be metered, potentially creating a discriminatory discrepancy compared to generating resources. He questioned whether M&V based on a TRM or external study meets PJM’s sample size requirements, and how EE providers and PJM check and verify the accuracy of those data. 

Breidenbaugh said it’s difficult to compare the metering requirements of a large-scale power plant, where the cost of a meter is relatively small compared to the overall facility cost, with the nature of EE projects that could be as small as upgrading light bulbs. 

Monitor Would Eliminate EE Capacity Market Participation

The Monitor presented a proposal that would remove EE from the capacity market construct outright on the basis that EE has been included in PJM’s load forecast since the 2016/17 delivery year. 

“The tariff states unambiguously that EE is not a capacity resource when EE is incorporated in the load forecast used for the capacity market,” Monitor Joe Bowring told RTO Insider. “As a result, PJM recognized for the 2016/17 delivery year that EE was not a capacity resource and stopped including EE in the capacity market at that time, as they were required to do. But PJM decided to pay EE resources a side payment, or uplift, regardless. The Market Monitor’s proposal is to end that side payment, which is not provided for in the tariff.” 

Monitoring Analytics President Joe Bowring | © RTO Insider LLC

Bowring said consumers are overpaying for a resource that is not a capacity resource and therefore provides no reliability benefits, and there is not evidence that the uplift payments are resulting in changes in consumer behavior. Rather than being compensated through the capacity market construct, he said EE is compensated as a result of the reduced energy and capacity costs to participants. He said it is a double-counting issue that has been recognized by PJM and FERC since the introduction of EE in the RTO’s markets. 

“What we’re calling EE in the PJM world should not be paid through the capacity construct. It is, as a factual and tariff matter, not a capacity resource,” he said. 

Breidenbaugh said it has not been demonstrated that a majority or the entirety of EE is captured in the load forecast. 

“There is a question about how much of this market energy efficiency is included in the forecast and what is not, and I would hope we would agree … that energy efficiency which is not a part of the forecast should not be subject to the addback,” he said. 

Exelon Seeks Protection for State EE Programs

Exelon’s proposal merges components of the CPower and PJM proposals, including the EE registration tracker from CPower and a PJM component that would remove EE from the Capacity Performance construct, exempting EE from performance assessment interval (PAI) penalties and overperformance bonus payments. 

It also would include language that state-authorized EE programs would be de facto qualified to participate in the capacity market, with the state’s legal authority held as the evidence of their validity. 

Exelon’s Alex Stern said PJM approval of the original M&V plan should codify the proposed methodology that the market participant intends to use to support its capacity offer, and that approval of the PIMV report should hinge on whether that methodology was followed. Exelon also proposed to rectify a perceived flaw in PJM’s proposal that would potentially put EE providers in a penalty situation by being unable to rely on the M&V report while then also being unable to fix an after-the-fact identified problem through an Incremental Auction. 

“Market participants need to be able to rely on M&V reports,” Stern said. “It is fundamental to fair EE market participation.” 

Stern said all but CPower’s proposal would impinge on the ability for state-directed EE programs to participate in the capacity market. He encouraged PJM and the Monitor to engage with states to ensure they are educated on the potential impacts to those programs. 

“I still strongly, strongly encourage PJM and the IMM to continue outreach to the states on this effort, but for now we wanted to try to put in a package that preserves and respects the ability for state programs to” continue participating in the market, he said. “As long as the states want the programs in the PJM capacity market, we think the rigor and regulatory scrutiny that characterizes those programs and differentiates them from other market participants should be respected in the PJM market construct.” 

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SPP’s Experience with Seams Could Help Markets+

SPP attempted to allay concerns about its ability to dispatch power among various Western regions during a July 11 webinar intended to illustrate its experience with seams management. 

RTO staff discussed how they address seams issues in the Eastern Interconnection and how power is transacted and delivered between neighboring entities. It’s part of SPP’s effort to differentiate its Markets+ services offering from CAISO’s Extended Day-Ahead Market (EDAM) as both organizations seek to sign up participants for their markets. 

As Western Freedom Executive Director Kathleen Staks said last month during an Infocast conference in Arlington, Va., “We do not have an organized market … we kind of have a mud-wrestling match going on right now.” 

SPP’s outreach was a result of NV Energy’s recent decision to join EDAM, despite the utility’s participation in SPP’s stakeholder-driven effort to set market rules and governance structures. The Nevada utility said EDAM’s expected lineup “provides a significant degree of interconnectivity and supports a diversity of resources.” (See NV Energy Confirms Intent to Join CAISO’s EDAM.) 

Antoine Lucas, SPP’s vice president of markets, told RTO Insider that recent news articles and conversations about connectivity between Western markets following NV Energy’s announcement pushed the grid operator to offer its perspective on seams issues and how Markets+ will dispatch service between the Pacific Northwest and Desert Southwest.

“We wanted to be able to provide a little bit of clarity around what we see and why we feel like the connectivity within the market pretty much remains unchanged,” Lucas said. “I think intuitively, when people look at a map and just focus on geography, the state of Nevada is between the Pacific Northwest and Arizona and the rest of the Desert Southwest. But what really creates that ability to transfer in the market is the availability of firm point-to-point transmission rights that Markets+ participants actually have the right to.” 

He said staff’s initial analysis indicates that the right to transfer between the West’s subregions will not be “materially affected” by NV Energy’s decision to commit to EDAM. 

“What we found is that [transmission rights] remain relatively unchanged without NV Energy’s participation in the market,” Lucas said.  

He told stakeholders during the webinar that establishing effective seams policies will take many parties working together but that SPP is willing to take a leadership role. 

“We just believe it’s in the best interest of Western consumers,” he said. “So, although we don’t know where our market seams will be, nor do we know what the specific seams hurdles that we will need to scale, our priority is to entities formally making their choices on which markets they decide to join.” 

‘One Way or Another’

SPP defines seams as neighbors performing the same function, such as acting as balancing authority, transmission service provider (TSP), reliability coordinator, market operator or, particularly in the West, greenhouse gas area.  

Carrie Simpson, SPP’s senior director of seams and Western services, said during the webinar that after questions arose over the different seams that exist today in the West, “we found that people were using the words interchangeably.” 

With 33 TSPs and BAs in the West, seams will be an issue. Simpson said the current proposal is to retain CAISO’s BA and place EDAM over it, which in turn means the interconnection’s longest seam is retained.  

“We’re going to have seams in the West, one way or the other,” she said. 

“We have a massive geographic footprint [in the West] and the resources are really far away from where the population centers are, so transmission and the coordination between states is imperative,” Staks said at Infocast. 

SPP has largely ported its Markets+ proposed design from its RTO design in the Eastern Interconnection. It includes an independent governance structure and a decision-making process that relies on stakeholder consensus. 

“We largely took the Eastern marketplace rules … and modified them to accommodate the differences and the fact that there are BAs and there are TSPs and there are just unique Western differences,” Simpson said. “Our approach is to optimize the dispatch of these markets, the SPP market, across all those BAs and TSPs using their full capability. 

“This is an important context for how the markets are developing because we’re putting markets on top of the seams, instead of getting rid of the seams first and adding markets,” she added. “I say that not because it needs to happen that way but more because it’s part of the evolution and what’s different about the West and the East.” 

Seams are reduced when BAs or TSPs consolidate their facilities into joint tariffs, such as joining an RTO. Agreements between neighbors coordinating on certain processes can also eliminate seams. 

“We’re trying, as a market operator, to optimize the seams that do exist in such a way that really minimizes them,” Simpson said, noting it will manage the system like an RTO or single BA area. Imports and exports to the market are priced based on footprint needs as a whole and not individual BA areas.  

She warned that without optimized seams, Western markets could see revenue and cost allocation equity undermined by internal seams. Equity is a big deal when you are settling $30 billion in market transactions, as SPP did last year. 

The seams require intentional policies between BAs and TSPs and market design decisions to reduce the effect of internal seams on market dispatch, Simpson said. She said SPP’s marketplace rules have evolved over the last 10 years to “refine equity in cost-allocation principles,” and it will continue to do so in the Markets+ design. 

JOAs

Joint operating agreements (JOAs) are one option for reducing friction on the seams. SPP has such agreements with MISO, ERCOT and Canadian utility SaskPower. During last January’s winter storm, the grid operator was able to rely on JOAs to import about 7 GW of generation to meet unexpected demand. 

Lucas said SPP’s position remains that Markets+ participants will be incented to strike JOAs that will facilitate trade “above and beyond” 1,000 MW of point-to-point rights that will support the market. 

“It can be Markets+ and neighboring markets that really take advantage of the reliability, sustainability and economic benefits that are associated with trade between regions,” Lucas said. “We are always focused on taking steps to add value for our participants and their customers and we think that seams and joint operating agreements are a great way to create efficiencies. We believe that anyone who’s operating the market will see value in joint operating agreements that allow participants in respective markets to be able to trade effectively, to capture those reliability, economic and sustainability benefits.” 

As Western markets and their footprints continue to evolve, Simpson said all staff and potential market participants can do is identify “friction points” that may reduce market optimization or make it difficult to move power from one point to another, a market footprint.  

“By identifying those things, at least we have a path and a framework for how we can reduce that friction,” she said. “The reality is we can start with what we know now. But once we get a better idea of the footprints, that’s really when we can engage. We’ll know who our neighbors are and how to manage that.” 

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Fuel-cell Vehicle Sales Plummet in 1st Half of 2024

Sales of electric vehicles in the U.S. are showing some signs of recovery, while the market for hydrogen fuel cell vehicles (FCVs) has practically collapsed, according to figures from the Hydrogen Fuel Cell Partnership and Baum and Associates, an auto industry research firm.

In the first half of the year, a total of 322 FCVs were sold in the U.S., primarily in California ― an 82% nosedive from the 1,827 sold in the first half of 2023, and the lowest sales since 2016.

Only two FCV models are currently available in the U.S.: the Toyota Mirai (99 sold in the second quarter) and the Hyundai Nexo (26 sold), according to a report by InsideEVs. Honda is expected to introduce a fuel cell, plug-in hybrid model in 2025 ― that is, an FCV with a small electric battery ― called the CR-V e:FCEV, which will only be available in California.

A total of 18,279 FCVs have been sold or leased since 2012, when Baum started tracking sales. California has 66 fuel cell buses, with more than 103 in the pipeline.

California is also the only state with a network of hydrogen fueling stations. The Fuel Cell Partnership lists 54 stations in operation across the state, mostly concentrated around the San Francisco Bay Area and Los Angeles.

When first introduced in the early 2010s, FCVs running on hydrogen were promoted as an alternative to EVs, which then had shorter battery ranges and longer charging times. But the market has shrunk to the point that industry analysts such as BloombergNEF are no longer tracking sales or other developments.

“The vehicles are still expensive; the fuel is still expensive. But most importantly, consumers don’t seem to be very interested in the technology, even in places with really generous incentives,” Colin McKerracher, head of clean transportation at BNEF, said at a recent webinar on the global EV market. (See BNEF: ICE Phaseout by 2035 Critical to Reach Net Zero by 2050.)

BNEF might consider tracking FCVs if and when sales reach 0.1% of the global market, McKerracher said.

Record Q2 for EVs

By comparison, EV sales in the U.S. staged a comeback, according to recent figures from Kelley Blue Book. In the first half of the year, 599,372 EVs were sold, and the second quarter saw record sales of 330,463, a year-over-year increase of 11.3%.

General Motors posted record EV sales in the second quarter as well, with 21,930 EVs on the road, a 40% year-over-year increase.

Stephanie Valdez Streaty, Cox Automotive’s industry insights director, noted that second-quarter EV sales “exceeded expectations.”

“The overall competitive landscape for electric vehicles is intensifying,” Streaty said in a press release. “This increased competition is leading to continued price pressure, gradually boosting EV adoption. Automakers that deliver the right product at the right price and offer an excellent consumer experience will lead the way in EV adoption,” even among consumers still hesitant to go electric.

The Biden administration is also continuing to support the buildout of a domestic EV supply chain with its recent announcement of $1.7 billion in funding to help reopen or retool 11 existing auto factories that have either closed or are at risk of closure.

The funding, from the Inflation Reduction Act, will go to factories in eight states ― Michigan, Ohio, Pennsylvania, Georgia, Illinois, Indiana, Maryland and Virginia — according to the announcement from the Department of Energy.

One example, Blue Bird Body Co. of Fort Valley, Ga., has been selected to receive $79.7 million to convert a factory that previously manufactured vehicles with internal combustion engines into a 600,000-square-foot plant turning out zero-emission buses.

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The Rocky Road to Performance-based Regulation in Connecticut

In the sometimes sleepy world of utility ratemaking, Connecticut is frequently making headlines over public disputes between the state’s utilities and their regulators.

The feud reached a boiling point in May when Eversource Energy announced plans to reduce its investments in the state by $500 million over the next five years. (See Eversource Announces $500M Cut in Connecticut Investments.)

Eversource and Avangrid — which own the major investor-owned utilities in the state — have decried actions taken by Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett, arguing the agency’s approach to several recent rate cases jeopardizes the utilities’ ability to receive a fair return on their investments.

Meanwhile, Gillett has made the case that the agency is simply holding the utilities accountable to existing standards, albeit more strictly than in the past.

The dispute comes at a critical time for the state’s power grid, which is facing a significant expansion to accommodate electrification and increasing volumes of renewable generation. It also comes as Connecticut undertakes a major shift — at the behest of the state legislature — to how it regulates electric utilities.

While New England has experienced a broader trend towards stronger utility performance incentives in recent years, Connecticut is the first state in the region to undertake a full-scale shift to performance-based regulation (PBR).

Ultimately, the success of Connecticut’s transition to PBR could have significant implications for the state’s clean energy transition, the cost and reliability of its electricity, and the proliferation of PBR approaches throughout the broader region.

Misaligned Incentives

In the traditional cost-of-service model, regulators determine utility revenues based on operational expenses, capital investments and an allowed rate of return on investments. While efforts to reform traditional ratemaking predate the clean energy transition, there has been a growing recognition that changes to the basic cost-of-service model are needed to accommodate the changes that are underway.

PBR encompasses a wide range of regulatory approaches including financial incentives and penalties, performance metrics and scorecards, multi-year rate plans, and revenue decoupling, all aimed at achieving goals and outcomes not explicitly considered in traditional ratemaking.

“Under cost-of-service regulation, we see a real tension between the kinds of investments that earn utilities an allowed rate of return and those they pass on to customers as operating expenses,” Oliver Tully, director of utility innovation at the Acadia Center, told RTO Insider. “We see a situation where the high capital-cost investments may not be the ones that are actually best for ratepayers and the grid overall.”

Traditional regulation, Tully said, can lead to “a clear misalignment between the incentives that the utilities face when making investment decisions and the policy priorities that the states have, especially around clean energy, equity, greenhouse gas emissions and affordability.”

Some of the top regulators in New England have also highlighted this dynamic. At a conference in June, Chair Jamie Van Nostrand of the Massachusetts Department of Public Utilities brought up the “cap-ex bias” of investor-owned utilities. (See State Regulators Discuss Affordability, Utility Incentives at NEECE.)

“Utilities tend to want to build more stuff because they get to put it into the rate base and get a return on it,” Van Nostrand said, adding that regulators should consider “incentive mechanisms to align [the utilities’] interests with our interests in pursuing clean energy goals and maintaining affordability.”

This sentiment was echoed by Philip Bartlett, chair of the Maine Public Utilities Commission, who said “we definitely need to move [toward] stronger performance incentives that are really driving outcomes.”

In the coming years, the states with strong decarbonization goals will rely on utilities to help implement demand reduction programs, utilize new technologies to optimize the existing grid and facilitate the deployment of an increasing amount of distributed generation. For advocates of PBR, incentives beyond the cost-of-service model are necessary.

But in Connecticut, which has pushed to implement the most aggressive PBR framework in the region, the development process has served as another stage for clashes between the utilities and PURA.

Shifting Winds in Connecticut

In the late evening of Aug. 3, 2020, Hurricane Isaias made landfall in North Carolina, weakened to a tropical storm, and accelerated inland roughly 100 miles parallel to the coast up through Vermont, eventually dissipating in Québec. The storm left immense destruction in its wake, causing 10 deaths and almost $3.5 billion of damage in the Northeastern U.S.

In Connecticut, Isaias triggered lengthy power outages and, several years later, major new legislation to address concerns about what many lawmakers saw as poor utility performance in response to the storm. Passed in 2023, the state legislature’s Take Back Our Grid Act directed PURA to create a performance-based framework for regulating the state’s electric utilities.

This PBR framework is still in development, with opinions on the current structure varying widely depending on who is asked.

According to the state’s utilities, PURA has largely ignored their concerns, resulting in a proposal that would prevent the utilities from making a reasonable rate of return, and ultimately reduce investments in the state’s grid.

“There’s no transparency as far as I can see into how PURA’s formulating it’s vision of what PBR is,” said Doug Horton, vice president of rates at Eversource, calling for more “collaboration and coordination” in the PBR development process.

“We don’t expect to get everything that we want, but we expect to be heard, and in Connecticut that’s just not been the case,” Horton said.

Representatives from Avangrid echoed Eversource’s concerns about PURA’s approach, arguing that the agency needs to better incorporate the perspectives of the utilities, investors, commercial and industrial end users, and local governments.

But according to organizations representing environmental and consumer advocates, the proceedings have been collaborative, and PURA has been intentional about including a wider range of perspectives than have historically been involved in utility proceedings.

“There has been a great deal of resistance from the electric distribution companies,” said Shannon Laun, vice president at the Conservation Law Foundation. “I think it is troubling that they’ve really been personally attacking the regulators at PURA and have made some pretty outrageous claims that the process has not been collaborative and has not taken into account their perspective.”

Laun emphasized that PURA “really has gone above and beyond to make this a collaborative process.”

Responding to Laun’s contention, an Eversource representative said the company has “never personally attacked PURA or the chair.”

Connecticut Consumer Counsel Claire Coleman said the PBR proceedings have been “a thoughtful process” featuring “a broad range of stakeholders,” while stressing that there is a still lot of work left to do.

PURA issued a ruling on the first phase of the PBR proceedings in April 2023, setting out the “regulatory goals, foundational considerations and priority outcomes to guide PBR development.” It also established three dockets for the second phase of the proceedings, centered around revenue adjustment mechanisms, performance mechanisms and integrated distribution system planning.

PURA is now holding technical sessions for each of the three ongoing PBR dockets, with final decisions on the dockets on track for mid- to late 2025.

The utilities’ concerns about the PBR framework — and the general regulatory environment in the state — ultimately boil down to the rate of return they expect to receive on their investments. Several recent high-profile rate cases have spurred outcry from the utilities about their ability to attract investors, and credit rating agencies have downgraded the outlooks for Connecticut utilities in recent years.

According to Horton, the proposed framework appears to “arbitrarily set rates less than our costs … and that on its own will cause PBR to fail.”

He added that the framework would only push investors away, which would disincentivize the utilities from spending money in the state.

Javier Bucobo, vice president of regulatory affairs at Avangrid, said the current structure would account for inflation on a delayed timeline, and contains performance metrics that appear unattainable.

“It’s setting up the utility to fail,” Bucobo said. “That’s the exact opposite of what PBR is for.”

In contrast, Coleman, along with environmental advocates involved in the proceedings, has a less catastrophic view of the credit downgrades and the PBR proposals.

Regarding the credit downgrades stemming from recent rate cases, “we acknowledge that there is an impact, but it is almost a tertiary impact to consumers,” Coleman said.

While cost-of-debt increases could ultimately result in some higher costs for ratepayers, utility rate increases are “a much more immediate cost to customers,” she added.

“What we’ve said is PURA needs to focus on the legal standard, which is: are the utilities receiving what is sufficient-but-no-more-than-sufficient to keep their business going,” Coleman said. “That really is the correct analysis, as opposed to speculating about how the investment community is going to react.”

Ultimately, Coleman expressed her hope that the new PBR framework will eventually help the utilities’ credit ratings by increasing the certainty around how the utilities can recover their costs, while also meeting the state’s performance goals.

Despite the utilities’ vocal concerns, Bucobo and Horton agreed that it is not too late to develop a PBR framework that can work for everybody.

“It can be turned around,” said Bucobo. “It’s as easy as having a conversation, and we’re willing to do that.”

‘A Model for Other States to Follow’

In New England, PBR at some level already exists in “basically every state,” said Mark Lowry, president of Pacific Economics Group and a leading expert on PBR. “New England was one of the very first to have these multiyear rate plans, and now almost every state is going to have it — that’s pretty amazing.”

Across the U.S, Hawaii is the furthest state along in implementing a comprehensive performance-based framework similar to Connecticut’s ongoing proceeding.

Lowry said Connecticut “was drawn to this very outwardly consumer-friendly PBR approach in Hawaii but didn’t even have the utility protections that there are in Hawaii, much less the ones that are commonplace elsewhere in New England.”

At the same time, Lowry said that the state appears to be reconsidering some of its approach to PBR, adding that “certainly some of [Chair Gillett’s] instincts are correct to second-guess some of what the utilities are saying … maybe Connecticut regulation has been kind of stodgy in the past and needed some fresh air.”

While Connecticut has opted to dive headfirst into PBR, other New England states have taken a much more incremental approach to adopting utility performance mechanisms, said Nathan Phelps of Vote Solar.

“There’s been little policy tweaks here and there in order to move towards what I would consider PBR,” Phelps said.

In Maine, a recent legislative PBR proposal died in the House of Representatives, with opponents citing the controversy that has surrounded implementation in Connecticut.

Some advocates have expressed concern that the pushback to Connecticut’s proceeding could discourage other states from considering the pursuit of comprehensive PBR.

Acadia’s Tully said that, while he views the Connecticut proceeding as “a model for other states to follow,” he has been disappointed by the utilities’ response and is “a little bit fearful of what this could mean for other states.”

In New Hampshire, Eversource included a PBR proposal in a rate case it filed in May. New Hampshire Consumer Advocate Don Kreis called the proposal “a reasonable basis to begin discussions with the utility about what a fair and reasonable performance-based ratemaking initiative would look like.”

But regarding the struggles in Connecticut, Kreis said he would “resist any attempt to try to turn New Hampshire into the anti-Connecticut,” and said it is a “key imperative” for PBR to have a balance of rewards and consequences.

“The utility has to put skin in the game,” Kreis said.

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PJM OC Briefs: July 11, 2024

VALLEY FORGE, Pa. — PJM’s Chris Pilong informed the Operating Committee that the transmission upgrades needed to allow the retirement of Indian River Unit 4 could be complete by the end of the year, potentially allowing the reliability-must-run agreement with the generator to be terminated a year early. 

Pilong said rebuilding of the 138-kV Vienna-Nelson line is ahead of schedule and would resolve the transmission violations that led to the RMR contract negotiations with NRG Energy to keep Unit 4 in operation. While the RMR is in effect, the Maryland Office of People’s Counsel and the Independent Market Monitor have protested the compensation included in the contract, which amounts to $263 million between June 2022 and the original RMR end date of Dec. 31, 2026. (See PJM Monitor and Consumers Protest Indian River Compensation Settlement.) 

The line rebuilding constituted the largest component of the upgrades PJM identified, with the remainder being substation upgrades that are expected to be completed ahead of the line coming back into service. Pilong said the rebuilding of Vienna-Nelson was complicated by the line needing to be in service during the summer, which limited when it could be taken out of service. 

The RMR contract includes a 65-day notification requirement before the agreement can be terminated. 

Stakeholders Endorse Revisions to Manual 12 for Black Start Fuel Requirements

The committee endorsed by acclamation revisions to Manual 12: Balancing Operations to include items approved in the package matrix stakeholders approved in 2022, but which were inadvertently not reflected in the corresponding manual revisions. (See Stakeholders Endorse PJM’s Black Start Fuel Reqs Proposal.) 

The overall proposal stakeholders endorsed established a new category of “fuel-assured” generators and required at least one such unit to be committed in each transmission zone. The criteria to qualify as a fuel-assured unit vary based on resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability. (See “PJM Presents Black Start Manual Revisions,” PJM OC Briefs: June 6, 2024.) 

The latest changes include exempting fuel-assured generators from penalties for going under their minimum fuel inventory while responding to a performance assessment interval (PAI) or if the storage was emptied for regulatory inspections. The revisions also remove an existing six-month fuel assurance inventory notification requirement and replace it with language that generators must verify their fuel and consumables inventory upon PJM request and an annual verification requirement on the black start test form. 

Security Update

PJM Director of Enterprise Information Security Jim Gluck said the FBI has published a public interest notification for renewable energy developers because of attackers targeting the sector, possibly because of the interest and growth in clean energy. 

Recent attacks against automotive dealers have involved impersonations of customer support staff to gain access to sensitive data that was stolen, which Gluck said underscores the need to be cautious when interacting with third parties. 

The Cybersecurity and Infrastructure Security Agency (CISA) has published new network access security guidelines around protecting networks from intrusion and how to ensure users are interacting with external networks safely. 

June Operating Metrics

Interactions between a heat wave with some of the highest peak loads of any June that PJM has experienced and thunderstorms led to high peak load forecast error between June 22 and 25, culminating with actual load being about 7.5% higher on June 25 than the day-ahead forecast.  

PJM’s Marcus Smith said the heat wave subsided faster than expected June 25, causing some regions to see temperatures significantly below forecast. The peak and hourly error was above the 25-month average but fell well below the error rates seen in June 2023 and 2022, he said. 

The month saw three shared reserve events, two spin events, seven hot weather alerts and one geomagnetic disturbance warning. Three shortage cases were approved June 3 because of a unit tripping. 

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Report Looks at Root Causes of Electric Rate Hikes

A new report says residential electric rates have been rising at a pace less than inflation in most states since 2010 and that the clean energy transition is not driving the increase. 

Broadly, transmission and distribution costs are rising faster than inflation, and this is a driving factor behind electric rates increasing nationwide, the report says; more narrowly, wildfires, natural gas price volatility and investments in coal plants contributed to price hikes in certain markets. 

“Clean Energy Isn’t Driving Power Spikes” was announced July 9 by Energy Innovation Policy & Technology, an energy and climate change think tank working to support policy designs intended to reduce emissions. 

The issue of rising electric bills is real, Energy Innovation said in introducing the report, and it is a huge concern for many American families. 

But clean energy, which some opponents criticize for its cost, is not to blame, the organization concludes. In fact, some of the smallest electric rate increases have been in states with high rates of wind and solar generation, such as Iowa, Kansas, Oklahoma and New Mexico. 

In ERCOT, for example, the buildout of wind and solar is estimated to have reduced wholesale electricity costs by $31.5 billion between 2010 and 2022, $11 billion of that in 2022 alone. 

Since 2010, average residential electric rates and the U.S. Consumer Price Index both have increased about 40%, the report notes, but average bills have increased only 24%, because of reduced household energy use. Energy-efficiency measures and rising use of distributed resources such as rooftop solar are credited for this. 

California, with one of the most aggressive clean energy stances of any state, has seen substantial electricity rate increases in recent years. But the report blames wildfire-related investments such as vegetation management and grid investments, which have increased to 16% of the total consumer costs for the state’s three primary investor-owned utilities. 

The grids in Colorado, Hawaii, Oregon and Texas also have sustained damage from major wildfires. 

“As climate-related risks accelerate, the cost to electricity customers of mitigating these risks will be critical to address,” the report states. 

The volatile price of natural gas is identified as another contributing factor in some states, particularly Massachusetts, which drew 64% of its electricity from gas-fired generation in 2023, compared with 49% for ISO-NE as a whole. 

The report flags other factors linked by a common theme: A regulated, guaranteed rate of return incentivizes utilities to make large capital investments rather than operational investments or other options that might be more cost-effective for customers. 

The report notes, for example, that utilities are continuing to invest in aging coal plants to keep them running, taking on significant new debt in the process. 

The report cites data from RMI showing the average remaining plant balance increased from $560/kW of capacity to $745 from 2010 to 2020 for steam boiler power plants, a category that consists mainly of coal-fired facilities. These sunk costs (plus a regulated rate of return) are passed along to ratepayers. 

Transmission and distribution costs are increasing at nearly double the rate of inflation, the report says, because of utility investment in hardening and resilience. It suggests costs could be limited by maximizing the existing grid’s potential with grid-enhancing technologies and reconductoring existing transmission corridors. 

The report cites Edison Electric Institute data showing IOUs boosted their capital investment in transmission and distribution infrastructure 64% from 2016 to 2023, more than double the rate of inflation during the same period. EEI indicates that transmission and distribution costs rose from one-fifth to one-third of total electricity revenue requirements from 2010 to 2022. 

This capital investment has been across the board, including from utilities that serve areas with slower growth of emissions-free generation, the report said, suggesting again that the rise of renewables is not driving the spending. 

The report states that these cost pressures risk canceling out the potential savings offered by renewable energy, the cost of which is expected to decrease through 2030. 

It offers several suggestions: Utilities can adopt better planning processes, use competitive procurement processes, maximize the capacity of the existing grid, enhance regional cooperation, refinance coal debt, adopt fuel cost-sharing mechanisms and change their business models to incentivize energy efficiency for customers rather than incentivizing their own capital investments. 

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NYISO Stakeholders Question Draft CEII Protection Requirements

[EDITOR’S NOTE: A previous version of this article incorrectly reported that the manual updates are being proposed NYISO. They are in fact being proposed by transmission owners.]

The NYISO Transmission Planning Advisory Subcommittee on July 9 criticized a transmission owner proposal to include Critical Energy/Electricity Infrastructure Information (CEII) protection requirements in the ISO’s manuals over what they described as confusing wording and inconsistent requirements. 

The TOs are concerned that with the “explosion” of generator interconnection requests, there is a gap in the CEII protection requirements. 

“There are FERC CEII protection rules, but they apply to information submitted to or generated by FERC; protections do not apply to information exchanged at the ISO level,” said William Derasmo, a partner at Troutman Pepper who presented the updates on behalf of the TOs. “The idea is to try to put something in place to fill that gap.” 

Derasmo explained that the updates would be followed by conforming tariff revisions. He cited a warning from the FBI that renewable energy generation could pose additional cybersecurity risks. (See FBI Warns Power Sector of IBR Cyber Vulnerabilities.) 

“This topic is not going away,” Derasmo said. “It’s a problem that is here, and we can’t wish it away.” 

The proposed revisions would require developers of generation or transmission facilities, their consultants or any nongovernmental organizations requesting CEII from NYISO to:  

    • provide NYISO and the transmission owner with a list of any countries outside the U.S. and Canada in which they operate; 
    • obtain cybersecurity risk insurance in coverage amounts of $5 million; 
    • establish a chain of custody, policies and process to securely handle and store CEII; 
    • not engage with entities owned by, controlled by or subject to the jurisdiction of “foreign adversaries”; 
    • engage in background screenings and security training for personnel accessing CEII; 
    • provide for secure deletion of CEII from systems; and 
    • report cybersecurity incidents to the NYISO and the TO within 48 hours. 

Stakeholders seemed confused that the draft updates used multiple overlapping definitions for “critical energy infrastructure,” “critical electricity infrastructure” and “critical infrastructure.” One stakeholder called it “overkill and unnecessary.” 

“We don’t need to parse it between ‘critical electric infrastructure’ and ‘critical infrastructure,’” they said. “You’re adding an unnecessary complication.” 

Others expressed confusion that the manual updates were being proposed without the accompanying tariff revisions. Typically tariff revisions are approved by FERC first before manual updates to define the scope of revision. 

“I guess I’m really struggling with how to do it this way,” the stakeholder said. “I think you’re maybe unnecessarily causing some confusion, if not complication, here. In any event, we’re not going to have any helpful guidance until you’re proposing the tariff first.” 

One stakeholder raised the issue of “special treatment” of the TOs. The current draft of the rules would require that recipients of CEII inform NYISO and TOs of security incidents and foreign business dealings, but they would not require the ISO or TO to inform recipients of cybersecurity breaches or similar multinational dealings. 

Another stakeholder raised the point that some people who have access to CEII do not represent or work for multinational corporations with large budgets. Requiring $5 million in cybersecurity risk insurance likely would deny people and firms of this kind access to CEII. They suggested having a MyNYISO account would be enough to trigger the insurance requirement.

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ERCOT Hires New VP of Public Affairs

ERCOT announced on July 15 that it has named former American Electric Power executive Gilbert Hughes as its new vice president of public affairs, where he will coordinate communications and government affairs.

The grid operator said Hughes has four decades of experience in the electric utility industry, with a focus on Texas public policy. He served as vice president of external affairs for AEP, where he also had leadership positions in regulatory services, governmental affairs and community relations.

Hughes replaces Robert Black, who will serve as executive adviser during a transition period that begins immediately. Hughes will be responsible for the organization’s external communications, government affairs and customer support.

ERCOT CEO Pablo Vegas said in a statement that a key component of meeting the state’s reliability needs will be transparent communications with the public and close collaboration with state leaders and agencies, market participants and lawmakers.

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Pathways Participants See ‘Pivotal’ Chance to Build New Kind of RTO

The West faces a “pivotal” opportunity to develop a fresh approach to managing its electricity markets, one that could update RTO governance to better accommodate the public policy and new technology driving changes in the sector.  

That was the view shared by some stakeholders participating in a July 12 workshop hosted by the West-Wide Governance Pathways Initiative. It was the first in a series of four virtual meetings to explore how a proposed Western “regional organization” (RO) would structure its stakeholder processes after assuming oversight for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market. 

The workshops, which are being facilitated by nonprofit Gridworks, will provide a comparative examination of stakeholder processes for six RTOs and ISOs — including CAISO and SPP — and the Western Power Pool’s Western Resource Adequacy Program (WRAP) to identify the best practices to be adopted by the new Western RO. 

“I think we need a bit of a reset here, because in my mind, my perception of what we’re doing with the Pathways process is to change the RTO governance model,” Fred Heutte, senior policy analyst at the NW Energy Coalition (NWEC) said during the meeting. 

The changes should go beyond procedural matters, Heutte said, “to reflect a new approach that combines market operations, grid dispatch and public policy, as represented primarily in state policy across all the diversity of all the different state policies across all the diverse states.” 

Given that emphasis, Heutte cautioned against borrowing too heavily from processes in existing RTOs. 

“The amount of friction and controversy in the East because public policy is not aligned with market design and operation — it’s been a problem for a long time, [and] it’s a growing increasingly more difficult problem,” he said. 

Mona Tierney-Lloyd, head of regulatory and institutional affairs at Enel North America, “endorsed” Heutte’s comments and added that Pathways is in a “unique position relative to every other organized market” to take a “fresh view” on governance.

She said her experience participating in “several markets” across the U.S. indicates that interests representing distributed resources have been marginalized and “relegated to some sub working group that isn’t given the same kind of attention or weight … as other member classes.” 

“We’re also at this really pivotal time of looking at new technologies coming online and really changing what is [recognized as] an electricity resource, looking at the distributed side of the resource equation more fully,” Tierney-Lloyd said, calling it “an opportunity to take a more modern look at the way the electricity system is changing and trying to incorporate that view into a stakeholder process.” 

Brian Turner, Advanced Energy United’s director of regulatory engagement in the West, took up that theme. 

“We have the opportunity to create something new that takes the best of what is and perhaps new ideas as well. Coming from a perspective of an organization that represents a lot of the new technologies that are increasingly important in the energy system, I think that that’s a perspective that is shared with nontraditional voices that have the opportunity to be represented here,” Turner said. 

‘Fair Process’

Some workshop participants offered a more positive take on existing stakeholder processes in RTOs, particularly in the East.  

Cathleen Colbert, senior director of Western markets policy at Vistra, said experience working in both CAISO and PJM helped her develop a “nuanced view” of the grid operators’ different approaches to stakeholder process. Colbert said she found CAISO’s staff-driven process suffers from an “asymmetry” of information and access, and while the ISO provides any stakeholder the opportunity to provide input, it has no obligation to consider that input.  

“Because it doesn’t have any incentive to really engage stakeholders, because they don’t need stakeholder support to get anything through their processes and environments … there’s no incentive for them to truly be involved with their stakeholders unless you have a special relationship, unless you have figured out how to build a rapport and a relationship where you get offline access,” she said. 

In contrast, Colbert finds the PJM stakeholder process, with its committee structure, to be “very open … in practice.” 

“I don’t know if it’s the voting, but the PJM stakeholder process was incredibly collaborative and inclusive, versus the CAISO one, [which] is very, very hard for stakeholders to actually participate in meaningfully,” she said. 

Heutte said CAISO’s stakeholder process is not perfect but has provided him “a relatively easy” way to submit his input on issues, while he thinks SPP’s “well structured” approach can be “very isolating.”   

“If you’re not a formal member of a committee, then you’re really not treated as others are,” he said. “And it’s not just about the voting; it’s also about who gets recognized for speaking; it’s about the weight that your comments get, if you’re not a formal member of that group.”  

Ryan Millard, senior director of West region regulatory and political affairs at NextEra Energy Resources, said “having a discussion at some point about the nuances of each process will be valuable, because maybe one process is more responsive in practice than another.” 

“I think having some discussion with folks that are familiar with PJM, SPP and other RTOs can kind of marry up the practical realities of how this structure actually works, and how responsive it is,” Millard said. 

Scott Miller, executive director of the Western Power Trading Forum, noted that some stakeholders see efficiencies in the “top-down” approach of CAISO’s stakeholder process, while others see benefit to the “bottom-up” approach they’ve experienced in SPP’s Markets+ and in some Eastern RTOs. 

“The struggle, I think, is how we can get something that’s very efficient, but one in which people feel it’s transparent, they’ve got equal access, and it’s a fair process,” Miller said. 

Huette expanded on that idea. 

“It’s not just the challenge of do we pick a voting-oriented approach or a nonvoting-oriented approach, but rather, what is the key challenge is to make sure that we have synchronized the stakeholder engagement process to the overall direction that we’re trying to establish with this new approach to governance,” he said. 

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MISO Monitor Spotlights Congestion Fixes, Market Mismatches in 2023

MISO’s Independent Market Monitor debuted six new market recommendations this year as part of his annual State of the Market report, released last month. 

Two of the recommendations this year stem from MISO’s ongoing struggle with expensive transmission congestion. Independent Market Monitor David Patton said the RTO’s congestion management would improve if it could decommit resources that were committed in the day-ahead market. 

Addressing the MISO Board of Directors’ Markets Committee in a July 11 teleconference, Patton said the RTO doesn’t have a process to ask day-ahead committed resources to stand down, even when they contribute to “severe congestion.” MISO could likely save several million dollars in congestion costs annually if it had a process for requesting resources to abandon their day-ahead obligations, he said. 

MISO should further develop procedures outlining when it’s appropriate for its operators to derate transmission constraints to manage congestion, Patton recommended. Operators have inconsistently applied deratings, and those out-of-market actions have produced an average of $200 million in congestion costs for the past two years. He said MISO doesn’t have a “clear procedure” that indicates when its operators should implement deratings. 

“While it’s important to derate transmission, we should only derate the transmission when it’s necessary,” Patton said. 

Outage Details

Beyond that, Patton recommended that MISO compel generation owners to fill out the reasons behind outages or outage extensions in the ticketing system the RTO uses to track scheduling. 

Patton said MISO should be requiring “clear reasons” behind outages and extensions. He said better explanations will help its understanding of the nature of outages. 

“In a lot of cases, the reason for the outage is unclear or left blank,” Patton told the board. 

Patton said descriptions have become more important because now outages can count against resources’ capacity accreditation. “Accurate outage reporting informs operations — and monitoring — in the short run and is critical for capacity accreditation in the long run.” 

Patton: More Sloped Curves

On the capacity auction front, Patton recommended that MISO use demand curves at the zonal level to better model demand in its local resource zones and produce more accurate local clearing requirements.  

Patton said he was puzzled that MISO didn’t develop a plan for zonal-level curves alongside its successful bid with FERC to use sloped demand curves in the auction at the subregional and footprint-wide level. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

Without the use of zonal curves, zones that bind on either their export or import limits in the capacity auction could experience clearing prices that have little to do with reliability value, he said. 

Patton said the capacity auction this year cleared “inefficiently high shortage pricing” in Missouri’s Zone 5, which hit $720/MW-day in spring and fall. Missouri’s expected unserved energy from the shortage isn’t as risky as the clearing prices suggest, he argued. 

Nevertheless, Patton called it an “amazing step in the right direction that we now have” sloped demand curves to value capacity. 

Market Recommendations

Patton said MISO could improve market performance if it aligned its definition of aggregate pricing nodes between its financial transmission rights market and real-time and day-ahead markets. 

Currently, the aggregate pricing hubs in the FTR market change with new load. On the day-ahead and real-time markets side, load additions do not influence the aggregation of pricing nodes. Patton said MISO’s influx of large, uneven loads has caused aggregate pricing nodes in the FTR market and day-ahead and real-time markets to vary “substantially.” He recommended that MISO eliminate discrepancies in aggregation definitions between the markets. 

“You would like these aggregation zones to be identical. But in a number of cases, they’re not,” Patton said. 

Multiplying data centers and cryptocurrency mining facilities will exacerbate the problem, he added. Patton called his recommendation “complicated but fairly important.” 

MISO should begin looking into studying loads like it does interconnecting generators in the queue, Patton said, because large loads can also affect the transmission system and necessitate upgrades. 

“Some of these large loads create comparable problems to generation that’s interconnecting,” he said. 

Patton also said this year he revived an old recommendation to enforce requirements for MISO’s 30-minute reserve products. He explained that MISO often commits resources outside of the market to solve voltage and local reliability issues in load pockets. He said in some cases, shortages that weren’t priced have occurred in load pockets. 

Those situations would be best handled by allowing the market to naturally summon short-term reserves to maintain reliability, he said. The problem is most pronounced in East Texas, where MISO has come close to shedding load. Patton said that if MISO honored a requirement to use reserves instead of out-of-market actions, generation owners might be motivated to build more generation or delay retirements. 

MISO is reviewing the Monitor’s recommendations and will deliver a public reaction to the State of the Market report in October. 

At the end of the Markets Committee teleconference, Clean Grid Alliance’s David Sapper criticized MISO’s timeline for reviewing the State of the Market report for not setting aside enough time for stakeholders to discuss the merits of the Monitor’s recommendations. 

Sapper said stakeholders have only minimal time at a single Market Subcommittee meeting to react to the recommendations and aren’t allowed in on the process of MISO determining which recommendations should be taken up and which can be disregarded or delayed.