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August 1, 2024

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As EV Penetration Rises, Utilities Turn to Smart Charging Strategies

A pilot program using smart EV charge management to smooth distribution loads and improve demand response has been so successful a utility is adopting the program permanently before completing the pilot. The interim results of the U.S. Department of Energy-funded pilot were shared at a workshop at RE+ in Las Vegas earlier this month.

“Baltimore Gas and Electric found the initial residential pilot results are impactful and have included a permanent smart charge management program in their multi-year plan,” said Joshua Cadoret, senior project manager at Exelon, which received an award from DOE for a Smart Charge Management (SCM) pilot program with three of its utilities: Baltimore Gas and Electric, Delmarva Power and Light and Potomac Electric Power.

The pilot study, which is ongoing, includes about 3,000 residential EV customers with more than 3,600 vehicles as well as 850 public chargers throughout their territories as of Sept. 7. Commercial EV fleet owners also were targeted, but only one has been recruited successfully to date.

The SCM pilot recruited Tesla owners to enable their cars’ charging to be throttled to reduce peak demand and encourage off-peak charging. WeaveGrid software shares the utilities’ signals with the vehicles. The EV owners received a $10/month electric bill credit, equal to 10% of an average monthly bill, and were able to override the demand response request up to four times each month. The public charging pilot program offered customers two options: the default opt-in where charging is throttled at certain times and charged at a discounted cost/kWh or opt-out to get the full capacity of the charger at the standard rates.

Managed charging aims to solves two problems utilities face: their distribution systems’ ability to cope with an increasing number of EVs and the utilities’ need to respond to renewables, said Shane O’Quinn, senior director of business development at WeaveGrid, a company whose software optimizes EV-grid integration for utilities. “Whenever you have a large number of EVs coming online where 80% of the charging is happening at the residential level, and the residential distribution network is designed to support really relatively modest loads at the household, we’re ultimately going to get to a point to where we have distribution system challenges.”

EV charging incentives can be designed with the goal of spreading the load into times that lower the need for grid upgrades, O’Quinn said: “One of the first things you have to consider is how are people actually going about charging their EVs today and where do you ultimately want them to be in terms of how they charge in the future?”

The default for most EV drivers is to plug in their car when they arrive home from work, which usually coincides with peak demand as most housholds turn on HVAC and use appliances at the same time. This is shown in the first scenario in Weavegrid’s  graph, which shows eight cars on a single distribution feeder plugging in when they return from work, although one works late shifts so that car draws on the grid later than the others.

“Many utilities take the next step and think about how they might be able to implement time-of-use rates which can shape behavior so that people are starting to charge after the on-peak times are over,” O’Quinn said. That can help the drivers manage the cost of electricity but may not be optimal for the utility.

The initial stage of the residential pilot tested the ability to use SCM to move charging to off-peak times and resulted in 96% of the more than 40,000 charging sessions being done off-peak. While the drivers may plug in when they get home, the SCM works with vehicle telematics so charging begins when off-peak rates start, the second scenario in the graph.

“There’s another technique that can more actively push the charging into periods that are beneficial for you as a utility. For instance, we can utilize an approach where we’re smoothing out the charge levels on various distribution system assets, making sure that you’re not overloading transformers, for instance,” O’Quinn said, “or you might be able to push the charging into a period where you can soak up renewables on the grid.” The third scenario in the graph shows SCM being used to even out load on distribution grid assets.

Helping utilities use managed charging to absorb renewables on the grid is driven by economic realities, said Russell Vare, who heads automotive OEM partnerships for Kaluza, a vehicle-to-grid software provider. Using data from the UK as an example, he showed how the move from 17% to 35% renewables resulted in a substantial increase in price volatility.

The UK market shows that increased renewables penetration leads to greater wholesale power price volatility. | Kaluza

While regulated markets may not have that degree of price volatility, this data shows the need for utilities to use EVs to absorb peak renewables supply.

The pilot also looked at potential cybersecurity risks and vulnerabilities of EV chargers and vehicle telematics software, according to the Phase 1 Review distributed by the Smart Electric Power Alliance (SEPA).

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Northeast Stakeholders Discuss The Future of Alternative Fuels

New England regulators, policymakers and industry representatives convened in downtown Boston last week to discuss the potential of alternative fuels in the region’s push for decarbonization.

The conference was organized by the Northeast Energy and Commerce Association and featured talks and panels about the future of the natural gas network, along with the potential of fuels like hydrogen, renewable natural gas (RNG), biodiesel and renewable diesel in the energy transition.

The uncertain future of the region’s gas network loomed large over the course of the conference. Massachusetts, New York and Rhode Island all have ongoing state investigations into the future of their natural gas systems, with options ranging from widescale decommissioning to doubling down on the infrastructure.

“It’s so important to consider all options — that includes using the pipes which are in the ground, and potentially expanding pipes — to be able to meet the energy needs of the future,” said Max Bergeron of Enbridge.

From left: Jose Costa, Northeast Gas Association; Donny McCallum, Smartpipe Technologies; Max Bergeron, Enbridge. | © RTO Insider LLC

The company recently announced an open season for a project that would increase its pipeline capacity of natural gas to the northeast. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

“We anticipate we will see a growth in demand for gas utilities of about 6½% over the next five years,” Bergeron said. “We also have to keep in mind that the power grid is very much reliant here in New England on natural gas-fired generation, so we see a strong need for incremental pipeline capacity to alleviate some of those bottlenecks.”

Carleton Simpson, a commissioner on the New Hampshire Public Utilities Commission, said fuel availability “appears to represent a significant challenge moving forward” and added that a “NERC-style entity” may be needed to ensure the reliability of the gas network.

Jessica Waldorf, chief of staff and director of policy implementation at the New York Department of Public Service, said the state faces a tough task of maintaining the functionality of the gas network while keeping up with decarbonization.

“There’s certainly a lot of pressure for us to move quickly away from use of natural gas,” Waldorf said, while noting the state’s gas utilities simultaneously connect “tens of thousands of new customers to the natural gas system.”

Waldorf said if utilities continue to add customers at current levels, the state will be required to ensure the system can “safely and reliably meet the demand of those customers.” She added this will result in “really hard infrastructure decisions.”

“It also is increasingly challenging because we’re balancing those decisions against the requirements of the Climate Act, in addition to all of our other statutory responsibilities,” Waldorf said. “And that means additional review processes and additional analysis is needed to really justify the need for these projects on the basis of reliability.”

Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities (DPU), echoed the concerns about gas availability while questioning whether utilities should continue their pace of new gas hookups.

“To some extent, it seems to be business as usual in the natural gas industry with respect to new residential hookups and continuing levels of load growth,” Van Nostrand said. “Is that consistent with the statutory emissions limits that we need to achieve?”

Van Nostrand called the dynamic “a disconnect,” adding, “things seem to be that bad that [the gas utilities] are worried about the need to keep the Everett Marine Terminal open to address reliability concerns, but it doesn’t seem to have any impact on policies with respect to accommodating new connections.”

The DPU chair also called for a greater focus on reducing the energy burden on residents as the state transitions away from fossil fuels.

“We want to start a proceeding to focus on the energy burden, to figure out if there are rate designs … that would allow us to move rapidly forward on a clean energy agenda, while still recognizing that people have a hard time paying their bills,” Van Nostrand said. “That’s a very high priority for this commission.”

Hydrogen And RNG

State policy concerning the future of the gas networks frequently has pitted climate organizations against the gas industry, with climate groups pushing to rapidly decommission gas networks and the industry advocating for a continued reliance on the gas system and the blending of alternative fuels like RNG and hydrogen.

Bergeron said RNG and hydrogen could be blended into the gas network to lower its carbon intensity, while acknowledging fossil fuels like natural gas will have an “ongoing role.”

“We see RNG as an opportunity to leverage our existing network,” Bergeron said.

Jose Costa of the Northeast Gas Association echoed Bergeron’s support for fuel blending and added that legislative and regulatory help is needed to bring RNG into the region’s gas network.

“Electrification of everything is not the sole answer,” Costa said. “The natural gas distribution network, it’s going to be there, it’s going be needed, and I’m not sure if fully renewable energy will be the energy source of the future — it’s going to be a mixture.”

alternative fuels

Massachusetts Rep. Jeff Roy, co-chair of the Joint Committee on Telecommunications, Utilities, and Energy. | © RTO Insider LLC

Massachusetts Rep. Jeff Roy, (D) co-chair of the Legislature’s Joint Committee on Telecommunications, Utilities and Energy, told the conference Massachusetts “must use all the tools at its disposal to remain both a national leader in climate mitigation efforts and a prosperous, affordable home to residents.”

Roy highlighted a bill he introduced this legislative session (H.2938) that would promote the use of alternative fuels including RNG and hydrogen in the state’s gas network, calling the bill “a starting point for our conversation on the role of fuels in the Commonwealth’s future.”

Lobbyists for gas industry groups including Enbridge, National Grid and the Propane Gas Association of New England have supported Roy’s bill, arguing it would make efficient use of the existing gas network.

Meanwhile, members of climate organizations including the Green Energy Consumers Alliance, Mothers Out Front and Gas Transition Allies have opposed the bill, arguing that using the fuels in the gas network simply would perpetuate fossil fuel reliance and would lead to high costs to ratepayers due to the mounting expenses of maintaining the state’s aging gas network, combined with the high costs of hydrogen and RNG.

“The Commonwealth’s clean energy and climate plans indicate that the best pathway to clean heat is through electrification, not renewable natural gas and hydrogen, which this bill subsidizes,” Carrie Katan of the Green Energy Consumers Alliance told a legislative committee in June, adding the fuels are better suited for hard-to-decarbonize sectors like air travel.

Katan said biofuels like RNG are “fundamentally inefficient fuel sources” constrained by the feedstocks used to produce them, adding “no amount of state subsidies will overcome these problems for RNG, just as no amount of federal support could make ethanol the future of transportation.”

The environmental groups also argued that blending in alternative fuels would perpetuate the health effects and safety issues from the natural gas network. A 2022 study from Boston College’s Global Observatory on Planetary Health found that air pollution contributed to nearly 3,000 excess deaths in Massachusetts in 2019, largely attributed to burning fossil fuels.

Boston College biology professor Philip Landrigan, a co-author of the study, told NetZero Insider that blending hydrogen or RNG into the natural gas supply would have little effect on the local air pollution associated with the gas system, including the release of air pollutants like NOx gases, benzene, and other toxic chemicals.

Landrigan added that while the local air pollution impacts of natural gas are not as bad as coal or oil, natural gas is “every bit as powerful a greenhouse gas.” The professor added that he considers the effort to mix hydrogen into the gas network to be “a desperate attempt by the fossil fuel industry” to maintain a market for gas and protect their investments in gas infrastructure.

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Stakeholders: Pathway Initiative Offers ‘Fresh Look’ at Western Market

Stakeholders from across the Western electricity sector say they see renewed potential for developing a more organized regional market through the open-ended process offered by the West-Wide Governance Pathway Initiative.

But many of them also caution the initiative must become more transparent, both in its processes and its sources of funding.

Those were two of the key takeaways from stakeholder comments filed in response to questions in an Aug. 29 letter circulated by the backers of the initiative, who are seeking to quickly work through “Phase 1” of the effort to define a governance framework and seat a founding board of directors by next January. (See Backers of Independent Western RTO Seek to Move Quickly.)

Utilities regulators from Arizona, California, Oregon, Washington and New Mexico established the initiative in July to improve the prospects for developing a single, West-wide electricity market that pointedly includes California — a response to the competition for members between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.

The comments were posted on the website of the Western Interstate Energy Board. The solicitation received 36 individual comments and five sets of joint comments — a few of which also included contributions from some of the individual commenters.

‘Fresh Look’

The Aug. 29 letter asked stakeholders to address questions related to the initiative, including the pros and cons of it being facilitated outside of any existing organization and the preferred structure, process and scope for Phase 1. It also asked for opinions on the best stakeholder engagement model for enabling broad stakeholder involvement and ensuring efficiency.

Multiple parties pointed to potential benefits of conducting Phase 1 of the Pathway Initiative outside the auspices of any existing organization or process.

A group calling itself “Joint Commenters” — which includes RTO advocacy group Western Freedom; American Clean Power Association; multiple utilities in California, Oregon and Washington; and other industry groups — said the approach offered the advantage of separating “the discussion from existing market institutions and can enable a fresh look at certain structural and governance issues that have been examined in other contexts.”

The Bonneville Power Administration, which some Northwest stakeholders say is leaning toward joining Markets+, said the initiative “offers the opportunity for a different approach to create a multistate entity for market development than other entities have taken.”

“It has the opportunity to be a new, intentionally designed entity, separate from existing organizations. As a new entity, it could develop appropriate practices about how a multistate entity can operate and engage,” BPA wrote.

But one downside, BPA said, is that “[t]he new entity and its structure will need to be created rather than being able to rely on an existing structure,” which could hinder “the ability to move quickly.”

BPA has said it will issue a decision on which day-ahead market to join in March 2024, a timeline some Northwest stakeholders consider to be too aggressive given the importance of the agency’s transmission and generation for the wider West and all the variables currently in play. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.)

In its individual comments, Portland General Electric, one of the Joint Commenters, said the open-ended nature of Phase 1 could bring “renewed enthusiasm” to the effort to develop a Western market. But the Oregon utility also said “it is crucial to demonstrate continued support of key California political leaders, especially the California Energy Commission and California Public Utilities Commission.”

“Past efforts at regionalization have faced skepticism and resistance within California, and strong engagement from both California and Western leaders is needed to ensure that this effort produces an outcome that is acceptable to both California stakeholders and the wider West,” PGE said.

BPA suggested the first phase of the initiative focus “on demonstrating the viability of establishing an independent entity capable of administering contracted market services from an existing market platform.”

“While establishing effective independent governance of the initiative is of critical important [sic] to Bonneville, the requirements for an independent governance structure have been well-discussed through the existing market initiatives (WRAP, EDAM and Markets+). The initiative can draw from those experiences rather than spending the bulk of Phase 1 focused on what is needed for independent governance,” BPA wrote.

BPA also said it “respectfully” disagreed with an assertion by backers of the initiative that there was “broad stakeholder agreement” that the WEIM’s joint authority governance model would be sufficient for governing the EDAM.

“While Bonneville participated on the Governance Review Committee and supported its final recommendations within these constraints, we cautioned that ‘Broad adoption of EDAM across the interconnection is likely to be challenging if the market design is not founded upon an independent governance structure.’”

Transparency Required

A recurring theme in comments was the need for transparency around the initiative.

“It is important that whoever is leading this work create a process that is truly open, transparent, impartial, and inclusive,” said the British Columbia Ministry of Energy, Mines and Low-Carbon Innovation.

The ministry “strongly” encouraged the organizers “to identify which state/provinces [sic] are leading the initiative, the source of any funding received to date, and how decisions will be made with respect to a proposed governance structure.”

Arizona Public Service (APS) noted that “assistance from outside experts” will be needed to advance the effort in a timely way and “influence potential market participants’ decision making.

“Transparency is requested to monitor the source of funding for and perspective of initiative facilitators. At this juncture it is also unclear whether the regulator sponsors or broader WIEB membership is at the helm of the initiative,” APS said, expressing a concern shared also by NV Energy. The Nevada-based utility urged initiative backers to be transparent about the source of funding throughout the process.

Lack of transparency about funding appeared to be one of the key concerns for the Idaho Public Utilities Commission, which earlier this month voted unanimously to decline to sign on to the initiative. (See Idaho PUC Declines to Join Western RTO Governance Effort.) The PUC reiterated that concern in its terse filing.

The Utah Office of Consumer Services said the Aug. 29 letter’s “simple statement” that the funding is “derived from 501(c)(3) sources” was “wholly inadequate.”

“Unfortunately, experience has shown that having this tax status does not ensure that the organization has a mission consistent with the public interest and/or includes organizations with highly specific objectives that at best represent a subset of the public interest. Those promoting this initiative must disclose the specific funders so that potential participants can better understand potential goals associated with the funding,” the Utah agency said.

The Utah consumer advocate sought clarity on the rationale for seating the entity’s board during Phase 1.

“The timing does not appear to allow for a fulsome recruitment, vetting, and selection process. If only ‘key elements’ of governance are in place by December, that barely allows for enough time to have sectors coalesce and select nominating committee members by January,” the agency said.

Competitive Advantages

The initiative won strong praise in comments from a group that includes Western Freedom, Silicon Valley Leadership Group, Environmental Defense Fund, CalChamber, American Clean Power Association, California Environmental Voters and the Union of Concerned Scientists.

The proposal “identifies maximizing benefits for customers as the goal for the new entity and future market services it will provide,” the group said. “This sends a clear message that market decisions should be driven by and be able to demonstrate those benefits. It also signals a clear understanding of the sense of urgency for regionalization efforts to maximize benefits through expanded market services.”

The group said that large industrial and commercial electricity customers “face very real barriers to expansion in the West” because the region lacks an organized market to “provide affordable, reliable, and cleaner energy. A centralized market offers the ability to lower costs by unlocking the full potential of existing generation and decreasing costs.”

The group also pointed out that 80% of Western residents live in areas with clean energy targets that can’t be met without the benefit of a “fully integrated market” across the region.

The group was among those commenters, including BPA, who cautioned about the large investment of time and resources required to pursue the effort, advising that “there is some essential research and analysis that needs to be conducted at the earliest stages of this process to ensure there is a viable path forward.” It called for the initiative’s backers to identify a lead organization that can hire consultants, including “a facilitator, legal counsel and technical research.”

“The Western Interstate Energy Board through the Committee on Regional Electric Power Cooperation could be ideal, given its membership of states and its Department of Energy funding,” the group said.

A group calling itself “Joint Competitive Stakeholders” also pointed to a different set of competitive benefits from a West-wide market — for competitive power suppliers, transmission and generation developers, and financial institutions. The group includes independent power producer associations in California and the Northwest; energy traders such as DC Energy and Shell; and developers like New Leaf Energy and Vistra.

“Phase 1 of the Initiative, and any future phases, must provide fair representation for all types of market participants and interested parties. This representation will ensure that any new regional Western market establishes policies and operates in a fair and non-discriminatory manner to foster competition and unlock the greatest benefits,” the group wrote.

The Competitive Stakeholders said the initiative’s first deliverable should be to develop “a conceptual framework” on governance in a process that includes members of its sector, followed by drafting of governing documents.

“It will be key to establish a sound governance framework and good governance principles in Phase 1 to be used in implementation by the founding board in Phase 2,” the group said.

NV Energy said it seeks to “have up front agreement on the objective — to develop a governance structure that is independent in both reality and perception.” Both APS and NV Energy urged that a new entity not differentiate by the size of participating states. The latter also raised the need for equal treatment of different public policies.

“If a Western organized market is to have broad participation it must accommodate states that have adopted GHG programs, states that have pursued decarbonization by means of renewable portfolio standards, and states that have not established carbon-related regulations,” NV Energy wrote.

The Nevada utility also asked the initiative to address some practical matters, such as: which CAISO activities could be transferred to the new entity; whether the entity would be responsible for reliability coordinator activities as well as market functions; the potential for the new entity to assume the role of a balancing authority; and the entity’s role related to transmission planning and cost allocation.

‘Broader’ Representation

Oregon-based PNGC Power, an electric cooperative with 16 members in seven Western states, expressed support for the Aug. 29 letter and encouraged expansion of the regulators’ coalition “to include broader industry sector representation.”

“This includes entities with an interest in exploring pathways to an RTO, including strong representation from the Northwest region, including BPA’s public power customers that explicitly and clearly support forming an RTO as an end state,” PNGC wrote.

The co-op also urged the coalition “to ask for financial and resource commitments from all participating members of the Founding Board to ensure that they are fully committed to the effort and that they are not just attending to express opposition and slow down the process.” The commitments should be significant enough to “weed out” those who might seek to impede development of an RTO but “reasonable enough” to allow participation by organizations of “varying sizes,” it said.

While backers of the Pathways Initiative appear to assume that a new entity would contract with CAISO to provide market operator services, some commenters suggested the selection process should be opened to competition.

BPA said the new entity should consider “all options” for a potential market operator and possibly rely on an “RFO-type solicitation” (request for offer) for making its choice. APS said the initiative’s Phase 1 activities should be expanded to include exploring a governance structure that could be applied to any potential market operator.

“Currently, both CAISO and SPP are maneuvering to offer expanded market services to the region. Additional program facilitators may emerge,” APS wrote.

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FERC Rebuffs PJM, SPP on FTR Credit Rules

FERC said last week it remains dissatisfied with PJM’s and SPP’s financial transmission rights (FTR) credit policies, while ending inquiries into those of CAISO, ISO-NE and NYISO.

The commission ordered PJM to institute a 99% confidence interval in its policy and said SPP’s tariff “appears” to be unjust and unreasonable in the absence of a mark-to-auction collateral requirement or comparable alternative.

Following a 2021 technical conference on RTO/ISO credit practices, FERC in July 2022 opened investigations under Section 206 of the Federal Power Act into SPP, CAISO, ISO-NE and NYISO. (See “Collateral Requirements” in FERC Proposes Allowing RTOs to Share Credit-related Info.)

The commission said it was concerned the grid operators’ tariffs did not ensure that FTR traders maintain sufficient collateral to reduce mutualized default risk, where a default by a market participant unsupported by collateral must be socialized among all participants.

The commission’s concerns were sparked by the 2018 bankruptcy of GreenHat, which cost the PJM membership nearly $180 million — only $1.4 million of which could be recovered from the company’s principals once GreenHat was insolvent. (See FERC OKs GreenHat Settlements.)

Excluding PJM and SPP, the commission last week found the other grid operators’ tariffs remain just and reasonable and terminated their proceedings. (See below.)

PJM Ordered to Institute 99% Confidence Interval

In its Sept. 21 order on PJM, FERC accepted all aspects of the RTO’s June 2022 filing revising its FTR rules, except for the RTO’s proposal to use a 97% confidence level in its historical simulation (HSIM) model. It ordered use of a 99% level instead (EL22-32).

The commission said a 97% confidence interval would capture only events occurring more than once every 2.75 years, failing to account for rare, but high-risk events such as large, unexpected transmission outages or the February 2021 winter storm that caused generation outages across Texas.

“The record before us fails to show that considering such a short period of time will produce adequate collateral requirements, as it would exclude major, albeit potentially infrequent, events that cause significant price moves affecting the value of FTRs. For example, such a short period of time could exclude extreme but foreseeable events like Winter Storm Uri or the 2014 Polar Vortex, which occurred more than three years apart,” the order states.

The commission said the 99% value would include events that occur at least once every 8.25 years. It directed PJM to submit a compliance filing within 30 days reflecting the change.

“As a general matter, FTR market participants should be, and are, in the best position to bear the principal cost of insuring against their risk of defaulting on the FTR portfolio positions that they acquire voluntarily. An HSIM model with a 99% confidence interval puts that principle into practice by striking an appropriate balance in requiring adequate collateral to protect market participants against the consequences of default without begetting the adverse impacts, e.g., reduced market liquidity, of over-collateralization. And contrary to PJM’s earlier claims, there appears to be little danger of significant ‘collateral shock’ or ‘market disruption’” by requiring FTR market participants to cover more of their own risk instead of transferring a portion of it to other PJM members,” the order states.

FERC agreed with the Independent Market Monitor’s contention that PJM’s cost-benefit analysis was flawed and did not capture the full benefits of a 99% vs. 97% confidence interval. PJM held throughout the proceeding that the costs of a 99% interval would exceed the benefits; several load serving entities, including Duke Energy and Old Dominion Electric Cooperative filed comments agreeing with PJM’s stance.

The commission accepted the remainder of PJM’s filing as is, including replacing the long-term FTR credit recalculation with real-time price updates, revising the $0.10/MWh volumetric minimum charge to apply after adjusting for auction revenue rights credits or mark-to-auction value and revising its tariff to explicitly state that a decline in FTR portfolio value leads to an increase in the FTR credit requirement, as well as the inverse. The order also removes the undiversified adder, which applies to market participants deemed to present heightened risk from being undiversified. Following the GreenHat default, PJM said, the adder was determined to not correlate with fluctuating market risk.

SPP Ordered to Show Cause on Lack of Mark-to-auction Mechanism

In a separate order, the commission expanded the scope of its show cause proceeding for SPP and directed further briefing (EL22-65).

The commission gave SPP 60 days to show cause as to why its tariff remains just and reasonable and to respond to eight questions. It directed the RTO to explain the tariff changes it believes would remedy FERC’s concerns.

The commission faulted SPP’s transmission-congestion rights (TCR) market for lacking a mark-to-auction collateral requirement or a comparable alternative. The mechanism can mitigate excessive risk-taking by allowing the grid operator to make a collateral call if auction prices reveal that FTRs acquired in a prior auction are declining in value.

The commission said SPP’s credit policy failed to “address the credit default risk the commission identified in the show cause order.”

The commissioners said the RTO’s existing reference price methodology relies solely on historical congestion patterns and does not incorporate updated TCR portfolio valuations. FERC also said SPP’s improved credit requirements for TCR market participants did not directly address the increased default risk.

The commission said it remained “concerned” that a mark-to-auction mechanism or comparable alternative was not included in SPP’s tariff and noted the grid operator said its TCR auction process is not within the show cause order’s scope. FERC said SPP’s response raised issues that “require augmentation of the existing record” and it included a list of questions.

SPP staff said they are reviewing the order and plan to respond by Nov. 20.

CAISO

In terminating the proceeding regarding CAISO, the commission found that the ISO’s mark-to-auction valuation addresses the risk that an FTR portfolio — congestion revenue rights (CRR) in CAISO’s nomenclature — may decline in value over time (EL22-62). “We also find that CAISO’s existing volumetric alternative minimum collateral approach ensures that market participants maintain some minimal level of collateral that scales with the size of their CRR portfolio and cannot minimize their required collateral without correspondingly reducing their risk,” the commission said.

“The risk of a CRR portfolio changing over time is captured by incorporating the most recent CRR auction results as part of the financial security requirement calculation,” the order continued. “As noted in CAISO’s response, this approach incorporates a mark-to-auction mechanism and captures risks that emerge when auction results diverge materially from historical outcomes.”

The commission said several other factors reduce overall risk in the CAISO CRR market: CRRs are offered with a maximum open position of only three months and may be purchased only for paths associated with physical supply delivery.

The commission noted that CAISO uses a different approach from PJM, MISO or SPP, all of which require a flat $/MWh amount on FTR portfolios. “CAISO nonetheless requires a volumetric value to be posted as collateral that is weighted to produce a $/MWh amount, which imposes a higher requirement on negative or low positively valued CRR portfolios,” it said.

ISO-NE

FERC said ISO-NE’s collateral requirements are just and reasonable, agreeing with the grid operator that the tariff’s existing provisions require market participants to maintain collateral scaled to the size and risk of their FTR portfolio (EL22-63).

It agreed with the RTO that “the lack of a volumetric minimum collateral requirement does not render ISO-NE’s existing collateral requirements unjust and unreasonable.”

The commission took issue in the show cause order with ISO-NE’s lack of a volumetric minimum collateral requirement. The RTO responded that it is already well protected from risk due to its FTR financial assurance requirements and the fact that it doesn’t offer long-term FTRs.

NYISO

The commission said NYISO convinced it that it has adequate protections against defaults in its FTR market — called transmission congestion contracts (TCC) — despite the absence of a volumetric alternative minimum collateral requirement (EL22-64).

The commission cited the ISO’s alternative approach to ensure market participants “maintain some minimal level of collateral that scales with the size of their FTR portfolio and cannot minimize their required collateral without correspondingly reducing their risk.”

Unlike PJM and MISO, NYISO requires full payment for TCCs purchased in auctions upon completion of the auction, except for the second year of a two-year TCC. “We find that this key difference in settlement design ensures that market participants at a minimum must post the full auction price of an awarded TCC and, thus, prevents a market participant from minimizing its collateral without reducing its risk,” the commission said.

The commission cited a NYISO analysis that found the grid operator’s existing collateral requirements — $0.15/MWh for balance-of-period TCCs, $0.40/MWh for future six-month TCC, and $0.053/MWh the second year of a two-year TCC — were always greater than the minimum requirements in other markets ($0.10/MWh for PJM and SPP, and $0.05/MWh for MISO).

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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.