In a newly published white paper, NERC warned that remaining industry “knowledge gaps” around electric vehicles and their charging systems may make it difficult for grid operators to maintain reliability.
The Potential Bulk Power System Impact of Electric Vehicle Chargers report, released Feb. 8, examines the effect that the adoption of EVs — specifically, the widespread installation of EV chargers at homes and businesses — might have on the reliability of the North American electric grid.
NERC has studied the topic before, releasing a report last April with WECC and the California Mobility Center on the performance of EV chargers during grid disturbances. (See NERC, WECC Outline EV Charging Reliability Impacts.) The new white paper was intended to build on this study, as well as a similar report by Pacific Northwest National Laboratory released in 2021.
Citing a 2022 projection from online EV marketplace Recurrent Auto, NERC noted that EVs are now expected to account for more than half of new vehicle sales in the U.S. by 2030. This is more than double the expectation when Recurrent first performed the projection in 2018 and is based on market factors such as growth in consumer demand and supply chain improvements.
An EV owner is necessarily also an EV charger, and grid planners will need to account for the load created by all these new sources of demand for electricity. This challenge comprises the main focus of NERC’s white paper.
The ERO noted that “larger EV charging loads are anticipated to use higher charging levels that necessitate direct connection to the BPS to supply a large EV charging load.” At the same time, the mobile nature of EVs means they could conceivably charge at any location, whether they have the specialized equipment for faster charging or not. This adds an element of uncertainty to load forecasting.
In addition, NERC pointed out that EV charging can be “grid-friendly” or grid-unfriendly depending on the approach used. Grid-friendly charging supports the stable operation of the grid by reducing voltage when grid voltage drops, while unfriendly charging increases voltage during such times, putting more strain on the grid. An overabundance of grid-unfriendly charging stations could have a negative effect on reliability.
The white paper includes the results of a study performed by NERC to evaluate the potential effect of EVs on reliability. In the study, a single base connection represented the Western Interconnection, with the team altering elements of the scenario to simulate large-scale EV adoption. Four cases were developed: a long-term horizon under heavy summer conditions with and without high EV adoption, and near-term horizon under light spring conditions with and without high EV adoption.
The study team found that EV chargers did exhibit some troubling behavior in their simulations. For example, some chargers appeared to exhibit a delay in sensing system faults and performing ride-through behavior or changing their tripping modes, which could slow system recovery. The team also noticed delays in returning to pre-disturbance consumption, which might also complicate operators’ visibility into the state of the system.
NERC recommended that manufacturers of EVs and charging systems improve their collaboration with electric utilities and “establish performance criteria and standards regarding grid-friendly EV charging methods.” The ERO said that if such collaboration proves difficult, policy makers may need to intervene.
The white paper also recommended that transmission planners incorporate charger performance into their planning criteria to indicate the performance types that are grid-friendly for their area. NERC suggested manufacturers could “address these criteria with EV charging software updates.”
ISO-NE told the NEPOOL Markets Committee on Feb. 7 that it is proposing a major redesign to its capacity market, moving from a three-years-ahead schedule to a prompt and seasonal design.
To accommodate the change, the RTO is also proposing an additional two-year delay of Forward Capacity Auction 19 for the 2028/29 capacity commitment period (CCP).
FCAs are currently held more than three years prior to each CCP. ISO-NE is proposing to break up the CCP into distinct seasons and hold the capacity auction just several months before its start.
ISO-NE has been contemplating the move with NEPOOL stakeholders for several months and commissioned Analysis Group to study the proposed changes. The consulting firm recommended that the RTO make the move, writing that it would “support the transition toward a grid of the future.” (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)
To provide time to complete the changes, ISO-NE is also proposing a “backstop” two-year delay of FCA 19 if the redesign is not approved by the time it is to be held in February 2026. FERC had approved a one-year delay of the auction to allow the RTO to implement its resource capacity accreditation (RCA) changes and contemplate the move to a prompt and seasonal market. (See FERC Approves ISO-NE’s One-Year Delay of FCA 19.)
ISO-NE expects the MC to vote on the delay of FCA 19 in March. The RTO did not comment on when it would put the redesign before stakeholders.
Chris Geissler of ISO-NE said the changes would better prepare the region for the changing resource mix and demand profile. A prompt market would better reflect “demand and resource capabilities used to determine capacity awards, thereby producing more cost-effective outcomes,” he said.
While New England’s grid reliability risks have historically been concentrated in the summer, ISO-NE anticipates that winter will surpass it in the coming years with the increase in heating and transportation electrification. Geissler said a seasonal market would help the region prepare for this shift because it “more accurately accounts for seasonal differences in resources’ supply capabilities and forecast energy demand.”
Geissler also highlighted some design components that have yet to be determined. These include when exactly the prompt auction would be held, the number and length of the seasons, and whether seasonal auctions would be held separately or all at the same time.
A prompt and seasonal market would also mean significant changes to the resource retirement process, which is currently connected to the FCM, Geissler said. While ISO-NE could decouple the retirement process from the capacity market to maintain the current retirement notice timeline, a shorter timeline could provide some benefits, he said.
“ISO plans to prioritize evaluating retirement process reforms, including tradeoffs between shorter and longer time frames, and to discuss its recommendations with stakeholders early in the prompt/seasonal design discussions,” Geissler said.
Geissler noted that the proposal “includes language allowing resources with early in-service dates to submit qualification materials in 2025 and 2026” to allow them to quantify for earlier reconfiguration auctions.
In a public letter to ISO-NE issued in mid-January, Jamie Donovan, an analyst in the Energy and Environment Bureau of the Massachusetts Attorney General’s Office, expressed support for a seasonal market but said the AGO is “still weighing the tradeoffs of a prompt market.”
Donovan added that the AGO is concerned “that the expanding scope of capacity reforms could increase project implementation risk and [about] the difficult situation that could arise if FCA 19 is further delayed for the development of a prompt/seasonal market design that is not completed in time or rejected by FERC.”
Once stakeholders have voted on the additional delay, “we encourage the ISO to release as much of its impending market design as quickly as possible for stakeholder review and feedback,” Donovan said.
Alex Lawton of Advanced Energy United said the organization is “concerned that this change is moving forward without sufficient stakeholder discussion.”
“There are several important concerns that will not be addressed until after stakeholders are asked to vote on the issue,” Lawton said. He added that the organization would like to see more analysis on how the transition would impact price formation and “whether a prompt market can adequately incentivize new resource entry without the three-year forward price lock under the status quo.”
Slower anticipated growth in California’s population has prompted state regulators to downwardly revise the electricity demand forecast used for grid planning.
The reduced demand relative to a 2022 forecast is projected to continue to about 2033. But after that, the latest forecast shows a surge in demand compared to previous predictions, as the state’s potential new requirements for zero-emission appliances are expected to kick in.
The forecast is part of the California Energy Commission’s 2023 Integrated Energy Policy Report (IEPR). The proposed final IEPR will go to the commission for approval Feb. 14.
The CEC calls its California energy demand forecast “foundational” to state energy planning. The California Public Utilities Commission uses the forecast in overseeing energy procurement, while CAISO uses it in transmission planning.
Like previous forecasts, the CEC’s new projections show a steep growth in statewide electricity demand due to California’s rapid shift toward electrification of transportation and buildings.
Climate change is also expected to increase load, as heat waves are projected to become longer, hotter and more frequent, CEC said.
From the 2018 forecast to the 2022 forecast, the expected peak demand in 2030 increased by more than 5 GW.
Population Trends
In contrast, the latest forecast has revised energy demand downward compared with previous predictions — at least through about 2033.
The change is based on a statewide population growth of 0.2% a year, which is less than the previous projections of 0.4% annual growth. The slower expected population growth follows a state population decrease of about 0.5% in 2022. The population data come from the California Department of Finance.
“The slowdown in population growth can be attributed to slow in-migration and steady out-migration on top of an aging baby boomer population and declining fertility,” the report said.
Other factors that contributed to a lower load forecast are anticipated electric rates that are higher than previously predicted, and projections of greater growth in rooftop solar generation.
But after 2033, projected load starts to rise above previously predicted levels. That’s partly due to the expected impacts of zero-emission appliance rules that the California Air Resources Board (CARB) is considering.
Last year, CARB started holding workshops on the potential rules, which would apply to new natural gas-powered space and water heaters for residential and commercial buildings. If approved, the regulations are expected to become effective in 2030. (See California Considers Zero-emission Appliance Rules.)
2040 Peak Demand
The IEPR forecast shows CAISO peak demand growing by 1.8% a year and hitting 63,442 MW by 2040. CAISO’s record peak demand is 52,061 MW, set on Sept. 6, 2022. Peak demand in 2023 was 44,534 MW on Aug. 16, the ISO reported.
The energy forecast also includes projections for managed electricity sales, in which customer generation is deducted from consumption. The figures also factor in the projected impacts of energy efficiency, building electrification and transportation electrification.
Managed electricity sales are expected to grow from about 245,000 GWh in 2023 to 352,563 GWh in 2040. Solar generation is expected to hit 64,460 GWh by 2040.
CEC continually works to improve its energy demand modeling. For the 2023 forecast, CEC moved away from relying on historical data for its weather forecasts. The agency worked with Lumen Energy Strategy to incorporate global climate models into its projections.
CEC considers the impacts of regulations, policies and programs through an “additional achievable scenario” framework. Additional achievable load modifiers are applied for energy efficiency, transportation electrification and the fuel substitution that occurs with the shift to electric appliances.
The forecast includes estimates of the impacts from planned data centers, as well as load growth from increased cannabis consumption.
Port electrification is “partially accounted for,” CEC said. But electricity needed for hydrogen production is not included “because of the high uncertainty around the future of hydrogen,” the report said.
State legislators peppered the leader of New York’s clean energy transition with questions Feb. 7 about the sputtering progress and controversial details of the effort, but got few firm answers.
Doreen Harris, president of the New York State Energy Research and Development Authority (NYSERDA), instead emphasized what has been long and widely known: It was a very tough year for renewable energy development, in New York as elsewhere, and the state is in the midst of a reset.
NYSERDA President Doreen Harris | N.Y. State Senate
She urged that greater attention be paid to longer-term goals than to near-term targets that appear increasingly out of reach.
New York has a statutory requirement of 70% renewable energy by 2030, popularly known as 70×30; under questioning, Harris said the power portfolio stands at about 25% renewable now, much of that hydropower.
However, the pipeline of projects contracted but not constructed brings that total up to 63%, she added.
The accounting here is unclear — NYSERDA was placing its portfolio-plus-pipeline at 66% renewables a year ago, before contracts totaling 7.5 GW of renewable energy capacity were canceled.
Under additional questioning — friendly or pointed or rude, depending on the party affiliation or disposition of a given legislator — Harris appeared to concede that NYSERDA was counting canceled contracts toward the 63% total.
But a day later, her staff told NetZero Insider that in fact, 63% does reflect the subtraction of canceled contracts. The staff did not explain further but said the picture would be clearer this spring, after two rounds of new contract awards.
But the state has a way to go: The expedited onshore solicitation launched in late 2023 closed Jan. 31. Only 51 of the canceled projects were rebid. Six new bids brought the total to 57 projects with a combined 5-GW capacity.
The hope is that when the renewable energy industry returns to some semblance of pre-2023 normality, more projects with canceled contracts will be rebid.
A NYSERDA spokesperson said Feb, 8:
“As developers realign their project schedules and plans, NYSERDA is optimistic most will continue to take advantage of these competitive opportunities, helping New York’s pipeline continue to advance apace toward the 70×30 Climate Act goal and throughout the following decade.”
Public Perception
NYSERDA does not just lead the actual work of adding renewable energy capacity to New York’s grid, it works to build public support for the clean energy transition.
New Yorkers not only will be footing the enormous cost of the transition, they also will be called upon to make changes in their everyday lives to reduce their demand for power and emissions of greenhouse gases. Their buy-in is indispensable to the transition, literally and figuratively.
Wherever possible, Harris and her counterparts at other state agencies emphasize the benefits of change or the risks of the status quo in their public comments and sidestep the harder questions about the cost or even feasibility of their initiatives.
And so it was Feb. 7, when Harris and other office- or agency-level executives in the state government’s energy and environmental sectors appeared before a joint Senate-Assembly hearing about relevant portions of the budget proposed by their boss, Gov. Kathy Hochul (D).
It is an annual ritual held as the two legislative chambers prepare their own counterproposals, and it often goes beyond budget and policy line items to become a soapbox for issues dear to individual legislators and their core constituencies.
What impact it all has can be hard to determine, as legislative leaders and the governor take their three sets of proposals and hash out a final spending and policy package behind closed doors.
Republicans skeptical of the energy transition or its cost have little power to press their case, as Democrats hold both houses of the Legislature. But the Democrats are split regionally, and do not always present a unified bloc.
Much of the verbiage at the marathon hearing boiled down to the need to protect the planet and disadvantaged communities versus the high cost and uncertain means by which this will be attempted.
Environmental Conservation Commissioner Basil Seggos offered a frequent speaking point — the cost of maintaining the status quo will be greater than the cost of the transition. New York expects to sustain $55 billion in climate-related damage over the next 10 years alone, he said.
Seggos did not indicate whether New York’s energy transition would cost more or less than $55 billion, nor did he indicate what impact it would have in limiting global climate change, or when that benefit would start to manifest itself. New York totals 0.08% of the world’s land mass, is home to 0.25% of its people, and already has the smallest carbon footprint per capita or per unit of economic output of any U.S. state.
Badgered by a Republican senator on who would pay for all the multibillion-dollar clean energy projects she’s attempting to bring to reality, Harris said the cap-and-invest system the state is developing would place some of the cost on polluters rather than utility ratepayers.
She did not speculate on whether those same polluters might recoup those costs by reducing the number of New Yorkers they employ or raising the prices they charge new Yorkers for goods and services.
Looking at the huge increase in electrical use envisioned for the state — Harris said grid load might jump from 150 TWh a year now to 300 TWh by 2050 — one legislator said flatly there is no way intermittent wind and solar could meet that demand, and asked what else the state has in mind.
She avoided mention of hydrogen, nuclear and other forms of energy that are anathema to most climate activists and made only generic reference to the as-yet-unknown technologies the state hopes will be brought to market in time to make a difference, and at an affordable price.
The Next Steps
While Harris was reticent to discuss the current state of New York’s renewable energy buildout, she spoke at length on how much the state is doing to rebound.
The state’s campaign to add solar, wind and storage capacity has been slow to produce results but had generated considerable momentum by the end of 2022 — much of which dissipated amid the industry troubles of 2023.
The Open NY database shows 109 contract cancellations totaling 11.2 GW as of Jan. 30, though it does not indicate when they were canceled. Some predate the mass cancelation of contracts that followed the state’s decision in October to not give developers more money to start construction of projects that had become financially untenable. (See NY Rejects Inflation Adjustment for Renewable Projects.)
(The cancellation total is effectively about 13 GW because the database does not count as canceled two offshore wind contracts totaling 1.74 GW that will be canceled but are still in place, for now.)
Since the October decision by the Public Service Commission to not grant a price increase to existing contracts, NYSERDA has been moving (at lightning speed by the standards of the regulatory world) to counter the expected rush of cancellations. (See New York Scrambles to Maintain Momentum in Energy Transition.)
It awarded provisional contracts to 22 onshore and three offshore renewable projects totaling 6.4 GW from the 2022 solicitations. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) It still is negotiating the final contracts, more than three months later.
And it issued the expedited 2023 onshore solicitation, which drew bids for 57 projects totaling 5 GW, 51 of them rebids.
NYSERDA expects to announce provisional contract awards from the 2023 offshore solicitation later this month and from the 2023 onshore solicitation in April.
Whether New York still has a chance at meeting the 70×30 target mandated by the landmark Climate Leadership and Community Protection Act of 2019 remains to be seen.
“We’ve been talking a lot today about how we’re going to get to 2030,” Harris told the panel. “What we really need to be talking about more often is how we get to 2040 and 2050, given that this is a multidecade transition.”
A Department of Energy official defended the Biden administration’s pause on processing LNG export facilities at a Senate hearing Feb. 8.
Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.) and the committee’s Republicans told Deputy Energy Secretary David Turk the administration should reverse course and start processing applications again.
“Simply put: Politicizing LNG exports is reckless and dangerous, and it could empower and enrich Russia, Qatar and Iran,” Manchin said. “Deputy Secretary Turk, if I’m correct, DOE is just now beginning its new analysis of the economic impacts of our growing export levels. If this is the case, I strongly urge that this pause should be reversed immediately.”
Ranking Member John Barrasso (R-Wyo.) said the pause was all about the upcoming presidential election, with Biden trying to win votes from environmentalists.
“Critics have claimed that American natural gas exports would raise natural gas prices here at home,” Barrasso said. “The data shows otherwise. In the eight years since we began exporting LNG, the domestic spot price of gas is, on average, much lower than the domestic spot price on gas during the eight years before we were able to start exporting LNG.”
Turk said DOE is supposed to approve LNG export facilities to countries without free trade agreements when that is in the public interest, which is made up of economic, market, national security and environmental considerations. The last time the department reviewed how it analyzes new projects’ impacts was 2018, and much has changed since.
“First, the amount of U.S. natural gas that is being exported has dramatically increased, and we need to answer how authorizing exports beyond these unprecedented volumes could impact affordability for U.S. consumers and competitiveness of U.S. manufacturing,” Turk said in written testimony. “Second, our understanding of CO2 and methane’s effect on climate change have only become sharper, and we need to further improve our analytical tools to answer a range of questions about LNG exports’ climate and environmental consequences, both near and longer term.”
The country has 14 Bcfd of export capacity up and running now, with an additional 12 Bcf under construction and expected to be online by 2030. A total of 48 Bcfd has already been approved, which is nearly half of the total domestic production of 104.4 Bcfd.
The pause will not impact the ability to fuel allies, with Turk noting that European demand for LNG is falling, demand has peaked in Japan and South Korea will peak by the end of the decade, Turk said.
While domestic prices have not converged with the higher costs of global LNG’s yet, Turk said the Energy Information Administration has said that will happen eventually as exports grow.
The other side of the aisle of the committee defended DOE’s review, with Sen. Angus King (I-Maine), who caucuses with the Democrats, saying the department is trying to make sure the economic impact of continued growth in export capacity is worth it and to understand the lifecycle emissions of LNG exports.
“I don’t understand how you would take 50% of the production of a commodity and that won’t affect the price,” King said, referencing the total number of facilities that have already been approved.
Australia has ramped up its export capacity, and it has seen prices increase by a factor of five as it reached equilibrium with global markets.
Addressing Turk, King said, “My understanding is all you are trying to do is be sure before we add additional commitments that we know what the effect will be on a manufacturer in Michigan or a family in New England trying to heat their house.”
The analysis hopes to answer those kinds of questions, Turk said, and he expects the department will take “months, not years,” to get it done.
“If we were talking about considering a pause, this is a great, great panel for this,” Manchin said. “You have an executive order doing a pause, that’s the difference. That’s the difference I have with the administration.”
It would have made more sense to do the analysis first and then pause applications if it found additional capacity goes against the public interest, he added.
King pushed back, saying that the department is only doing its job, and it would not make any sense to keep approving projects only to find out “five years from now, it’s a complete disaster.”
“I’m just saying that the pause was ill advised from a political standpoint of sending out to the world right now that we might not be in the market,” Manchin said.
MISO’s Market Subcommittee likely will devote some time this year to discussing either a multiday gas purchase requirement or a multiday gas unit commitment process for use during extreme cold.
The RTO’s Steering Committee tasked the Market Subcommittee with consideration of the topic during a Feb. 6 teleconference. The issue was originally brought to the Steering Committee by member MidAmerican Energy.
In a written request, MidAmerican Energy’s Dennis Kimm said MISO should either introduce a multiday unit commitment process or adopt a requirement that natural gas generators buy fuel when weather is forecast that will send gas and electricity demand soaring. Kimm said the multiday commitments or natural gas procurements should not be used during normal operations.
Kimm said generators “undertake a significant economic risk in executing purchases for fuel and capacity without a guarantee that the generator will be dispatched.” He wrote that uncertainty regarding MISO dispatch “can act to discourage participation in the natural gas marketplace during times of greatest liquidity.”
MISO reported experiencing gas supply challenges, resulting in reduced generator availability, during the mid-January cold front that played out over a holiday weekend.
Kimm said some advance notice from MISO on what it plans to call up would “increase flexibility for natural gas-fired generators to obtain fuel and better situate the electric industry to adequately plan and prepare to deliver reliable service” during extreme cold.
But Executive Director of Market Operations J.T. Smith seemed unconvinced multiday commitments would improve natural gas generators’ performance issues during cold spells. He said a more successful approach would include better offers that reflect true capabilities, take into account lead times and consider temperatures and fuel procurement.
Smith said he understands generation owners want certainty, but there’s a “hesitancy from the membership” to provide true startup times and realistic availability of their generation in the market because it would harm their capacity accreditation values.
Smith said during cold snaps — including the latest widespread mid-January deep freeze — “we don’t get offers from our generators that reflect true availability.”
Smith said the optimization in MISO’s day-ahead market already gives owners and operators the signals to make commitment decisions days ahead of a weather event.
“In my mind, the multiday market already exists,” Smith said, adding he was “not so sure the problem” could be solved through MISO developing a new commitment model or fuel purchase requirement.
“Give me a valid offer of your true availability capabilities first,” he said.
Smith also said the topic likely contains resource adequacy implications that may need to be hashed out at the Resource Adequacy Subcommittee, in addition to the Market Subcommittee.
MISO has waded into the battle over who will build the Iowa portions of its long-range transmission projects two months after a court found the state’s right-of-first-refusal law unconstitutional.
The RTO filed an amicus brief in the case, asking the Polk County District Court to lift an injunction that halted regulatory permitting for long-range transmission plan (LRTP) lines that incumbent developers ITC Midwest, MidAmerican Energy and Cedar Falls Utilities elected to build under the ROFR law (CVCV060840).
The District Court in December struck down Iowa’s ROFR law and prohibited regulatory permitting on Iowa’s portion of five of MISO’s LRTP projects in which incumbent developers had benefited from the law. The ruling cast doubt on $2.6 billion in already approved LRTP projects located at least partly in Iowa. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.)
Since then, competitive developer LS Power has asked the court to reverse MISO’s assignment of the Iowa projects to the incumbent developers after the ROFR was deemed unconstitutional. LS Power challenged the ROFR’s validity in the first place, arguing it was shut out of the bidding process.
MISO said while it doesn’t take a position on the legitimacy of the ROFR, it is asking the court to reconsider the injunction against permitting, given that the planned lines are needed for the sake of grid reliability. The grid operator also argued the District Court’s interference with the line development is improper because FERC is best situated to handle who is allowed to build the lines pursuant to the MISO tariff.
MISO said it has a “strong and substantial interest” in making sure the LRTP projects in Iowa are built by the 2028-2030 time frame. The RTO said while the four- to six-year span seems like a long time, 345-kV line construction is a lengthy process that requires “timely permitting” to achieve targeted in-service dates. It emphasized that benefits stemming from its $10 billion LRTP portfolio will cover costs and save billions more in reliability advantages and access to new generation across the Midwest. MISO added that the LRTP lines’ benefits are premised on the lines operating as a whole.
“The injunction in question in this case, if sustained, would stand as an obstacle to timely completion of much-needed transmission to serve not only Iowa but the region as a whole,” MISO wrote to the court in its Feb. 6 brief. “MISO strongly urges this court to revisit its prior decision regarding the subject injunction in light of these factors and circumstances to avoid potentially ruinous practical public policy consequences.”
MISO said if the injunction is allowed to stand, current and future long-range transmission planning will be put at risk.
‘Impermissibly Intrudes’
The grid operator also said the court’s December injunction “impermissibly intrudes on the FERC’s exclusive authority over the transmission of electric energy in interstate commerce under the Federal Power Act.” It said the court “should not disrupt the timely completion of these projects in pursuit of a remedy that only FERC may grant” and added that only FERC has the authority to interpret the MISO tariff.
MISO said while LS Power can argue that it was deprived of the opportunity to bid on the lines’ construction and suffered economic harm due to the ROFR law, “whatever harm LS Power may potentially suffer is not as severe, concrete and particularized as the harm energy users, energy providers, MISO and its affiliates may suffer.”
FERC, MISO argued, is in the best position to assess competing claims to the lines’ construction, weigh how changes and delays to the lines will impact all parties, and order remedies. The RTO said LS Power already has “an effective federal remedy” through FERC and is free to argue before the commission that MISO’s assignment of the Iowa LRTP projects to the incumbents violated its tariff in light of the unconstitutionality holding.
“The public policy interests at stake, the balance of the harms as between the parties involved (and as to MISO), in the context of the nature and gravity of the vital regional utility grid issues at stake, make this matter ideal for judicial reconsideration as requested,” MISO wrote.
At a Feb. 7 MISO Advisory Committee meeting, Clean Grid Alliance’s Beth Soholt said she believed the Iowa ROFR ruling affects more than just the Iowa line segments in the first LRTP portfolio.
Soholt said the delays and uncertainty could bleed over to impede progress on MISO’s second LRTP portfolio, which is in the works.
“I think it’s very important for MISO to be [as] transparent as possible about the impacts and what that does to the study process of follow-on lines. … It’s a really major thing if we start having cascading timing issues. A lot of states are counting on these transmission buildouts,” Soholt said.
MISO Deputy General Counsel Kristina Tridico said the RTO will contemplate the most appropriate venue to share new information on the status of the Iowa projects with stakeholders.
Tridico said MISO will defer to the court’s decisions on the matter and understands the court’s actions stand to affect the planning and timely completion of LRTP lines. She said the RTO hopes to convey the importance of the LRTP lines in its brief.
FERC on Feb. 6 rejected a PJM proposal to rework the role of performance penalties in its capacity market and how the associated risks can be reflected in seller offers (ER24-98).
The filing was one of two the RTO made in October after the conclusion of the Critical Issue Fast Path (CIFP) process, largely focused on market issues highlighted by December 2022’s Winter Storm Elliott and PJM’s February 2023 “4R’s Report.” The commission approved the second filing last week, greenlighting changes to how PJM measures reliabilities risks, accredits capacity resources and verifies generators’ ability to operate throughout the delivery year (ER24-99). (See FERC Approves 1st PJM Proposal out of CIFP.)
In splitting the changes the Board of Managers sought to make after the CIFP process into two filings, PJM Senior Counsel Chen Lu said staff sought to ensure that components that relied on each other were accepted or rejected as a package and to avoid potentially riskier elements from sinking the entire proposal.
At the heart of the filing was how market sellers can represent the risks they face in taking on a capacity obligation through the Capacity Performance quantified risk (CPQR) component of their capacity offers; how those values are reviewed by the Independent Market Monitor and PJM; and under what circumstances generators can be assigned penalties for underperforming or receive bonuses for overperforming.
During the Market Implementation Committee’s meeting Feb. 7, PJM’s Skyler Marzewski said the RTO does not plan to seek a delay of the 2025/26 Base Residual Auction scheduled to be conducted in June. Both CIFP filings were intended to be effective for the auction, and Marzewksi laid out a timeline for when PJM plans to seek endorsement of several manual changes to implement the proposal approved in ER24-99.
FERC’s Order
FERC said that PJM had not provided enough detail around how it planned to implement the changes and sought to give the RTO guidance on changes that might be beneficial if it sought to refile the proposal.
In rejecting PJM’s plan to largely redefine the market seller offer cap (MSOC) based on CPQR and costs incurred to avoid those risks, FERC said that the proposal failed to define what qualifies as the sort of incremental cost that a generator could include in its offer versus actions that generation owners would have taken in the absence of a capacity commitment.
“PJM does not include in its pleadings or proposed tariff provisions a defining principle to identify and differentiate costs incurred only in the absence of a capacity obligation compared to costs incurred in whole or in part for some other purpose, such as to enhance EAS [energy and ancillary services] revenues,” the commission wrote. “PJM’s proposal seems to require PJM to employ a subjective assessment as to the intentions underlying complex investment decisions of sellers participating in a variety of markets, i.e., the capacity, energy and ancillary services markets, and bilateral transactions.”
The commission also said it saw merit in PJM’s proposal to create a standardized calculation for CPQR that incorporates unit-specific parameters that market sellers could accept or substitute with their own determination. But without FERC, the Independent Market Monitor and stakeholders having access to the proprietary model it sought to utilize, it would not be possible to understand what a valid CPQR value would be, it said.
“Though we have found that PJM has not provided sufficient detail to understand how the model components would be implemented in its proposed standardized CPQR formula, using a probabilistic model with unit-specific data would ensure a CPQR value that is specific to that resource and its risk profile,” FERC said.
PJM sought to provide more certainty of the costs that market participants could include in their CPQR submissions by introducing a third-party review process where sellers could include a review by a qualified, independent party and include that as documentation in support of their submissions. The commission found that the existing tariff language already supports that process and that the proposal would create a requirement that PJM and the Monitor accept the results of that outside review. FERC also raised questions of how PJM would define the qualifications that the third party must possess and how to ensure independence from the market seller whose offer it is reviewing.
“In other words, it would require PJM to automatically accept any third-party consultant justification regardless of reasonableness. We find that such a requirement would not be just and reasonable because it would delegate responsibility that belongs to PJM and the Market Monitor to third parties. The commission has found it is inconsistent with the principles of mitigation to allow sellers with market power to determine their own costs without review.”
FERC rejected PJM’s proposal to allow it to calculate an alternative MSOC using the information submitted by the market seller if the RTO determined that the one submitted after the review process conducted by the Monitor did not conform to the tariff. The tariff only empowers PJM to accept or reject the offer cap submitted by market sellers, which the RTO argued leaves its hands tied when it agrees with parts of an offer, but not the entirety.
The Monitor argued that granting PJM the ability to calculate its own offer cap would impinge on its prerogative in reviewing offers for market power, a position the commission cited in denying the filing. FERC pointed to Order 719 in finding that external monitors have the expertise and means to identify and mitigate market power and provides them with the sole authority to make market power determinations.
“We share commenters’ concerns that under PJM’s proposal, the Market Monitor would not be able to provide meaningful feedback because PJM would replace the Market Monitor’s role in calculating offer caps, which could undermine the Market Monitor’s duty to ensure competitive markets,” it said.
The proposal also would have created a new exception generation owners could claim to avoid being assigned Capacity Performance (CP) penalties by exempting generators not dispatched during a performance assessment interval (PAI) on a market-based offer that exceeded their cost-based offer. PJM argued that resources following dispatch instructions should not be penalized, but the commission sided with protests arguing that the change would allow generators to avoid being subject to CP by submitting offers that are unlikely to be committed.
“We agree with the Market Monitor that, with respect to nonperformance charges, there is no meaningful difference between resources that choose to submit market-based offers using relatively less flexible parameters than their cost-based offer or market-based parameter-limited offer, and those that choose to submit market-based offers using relatively higher economic parameters than their cost-based offers. Both strategies would constitute a capacity resource failing to meet its obligation to perform during an emergency and, therefore, require appropriate penalties,” the commission wrote.
FERC also rejected PJM’s proposal to limit eligibility for CP bonus payments, which are paid out from the pool of penalties collected following PAIs, to committed capacity resources. It pointed to comments from the PJM Industrial Customer Coalition, which said that about 40% of the overperformance seen during Winter Storm Elliott came from market sellers lacking a capacity commitment. Making such resources ineligible would remove an incentive for all resources to be prepared to operate during emergencies and limit the solutions available to maintain reliability during stressed system conditions.
Clements Partially Dissents
In a partial dissent, Commissioner Allison Clements said she agreed with the bulk of the order but disputed the majority’s reading of Order 719 in relation to PJM’s proposal.
Rather than making market power determinations, she said that the changes would have given PJM flexibility in considering whether an offer complies with the tariff, arguing that the “Monitor plays an important but circumscribed and advisory role under PJM’s offer cap rules.”
Clements also disagreed with the majority in rejecting PJM’s request to eliminate the physical replacement option for fixed resource requirement (FRR) entities that underperform. Instead of incurring financial penalties, such entities can choose to procure additional capacity for one year. PJM argued the option lacks the teeth of immediate financial penalties by deferring the costs and results in a smaller economic impact.
Clements wrote that PJM’s difficulty incentivizing resources to perform during extreme weather makes it reasonable to create FRR penalties that are more in line with those used in the Reliability Pricing Model.
Legislators in five states in PJM have filed similar bills that would require regulated utilities to submit all of their stakeholder votes publicly with state regulators.
Illinois, Maryland, Pennsylvania, Virginia and West Virginia have all introduced bills in the effort, which is supported by the National Caucus of Environmental Legislators (NCEL) and the Citizens Utility Board (CUB) of Illinois.
“My colleagues and I, across the PJM region, know that decisions made at PJM affect our ratepayers, the reliability of our electric grid and our transition to clean energy,” Charkoudian said. “These are all issues we are working on at the state level, and PJM’s rules have the ability to either support or hamper our ability to address these issues. This bill will go a long way to establishing transparency to support our ability to engage with PJM on these crucial issues.”
While PJM’s meetings are open to the public, so many are held that state regulators and consumer groups cannot track all of them, Clara Summers, manager of CUB’s Consumers for a Better Grid campaign, said in an interview.
“When utilities vote at PJM, the outcome of those votes impact our clean energy transition; they impact our reliability and the cost of electricity,” Summers said. “So, these bills are about introducing better transparency and better accountability for how those utilities are voting on these issues that affect our electric markets and transmission.”
With hundreds of meetings a year that can last hours and do not always produce records of how individual firms voted, making sure utilities are open about how they are voting will ensure states that their policies are being respected, she added.
PJM itself did not weigh in on the substance of the bills, but it said its stakeholder process is transparent.
“The PJM stakeholder process and the various stakeholder meetings, approximately 450 meetings, are open to the media and the public, with agendas and minutes posted on our website,” the RTO said in a statement.
Unlike the major committees — the Markets and Reliability Committee and the Members Committee — the lower committees allow firms’ individual affiliates to vote. Some firms, like American Electric Power and FirstEnergy, have so many affiliates that on their own, their votes can outweigh the combined votes of the participating consumer advocates, Summers said. “That increases their potential for impacting which proposals get voted on to advance.”
To win approval, rule changes need a majority in the lower committees and a two-thirds sector-weighted majority at the MRC and MC. PJM provides summaries of votes by sector at the major committees and details how individual members voted at the Members Committee.
Both Summers and Ava Gallo, NCEL’s climate and energy manager, said one reason states have become more interested in the PJM process is the drama around the now-defunct extended minimum offer price rule (MOPR-Ex). During the Trump administration in 2018, FERC controversially ordered the RTO to expand its bidding floor in the capacity market to all new state-subsidized resources; the rule had previously only applied to new gas-fired resources. (See FERC Extends PJM MOPR to State Subsidies.)
Politics among the PJM states is diverse, but Gallo said that while West Virginia and Illinois might differ sharply on energy policy, they both value transparency.
“NCEL is proud to help organize these state legislators across the PJM region,” Gallo said. “We know that legislators work tirelessly to ensure their constituents have affordable, reliable and clean electricity. States are stronger together, and this legislation can help ensure that utilities across the region are also working towards these same goals.”
The West Virginia legislation comes almost a year after its Public Service Commission filed a complaint at FERC alleging it had been improperly blocked from the PJM Liaison Committee, whose meetings are limited to members and the RTO’s Board of Managers. (See W.Va. PSC Files Complaint over PJM Meeting Policy.)
In the still-pending complaint proceeding (EL23-45), PJM responded that the committee was created so stakeholders could have direct communication with its board outside of the normal stakeholder process and that the board has closed-door meetings with state regulators under a deal it signed with the Organization of PJM States Inc.
“In West Virginia, people’s electric rates have gone up faster than any other state,” state Del. Evan Hansen (D) said. “We need our electric utilities to explain how their secret votes at PJM are in the public interest.”
Participants in NERC’s Member Representatives Committee suggested improvements to the onboarding process for new entrants and greater engagement with industry organizations in their responses to Board Chair Ken DeFontes’ call for stakeholder input, published Feb. 6.
DeFontes asked for the MRC’s input last month ahead of the Board of Trustees and MRC meetings to be held next week. In addition to seeking feedback on the board’s planned agenda items, the chair requested responses to three specific questions:
How can NERC facilitate engagement by new industry participants?
How can NERC encourage incumbent players to continue engaging in the ERO stakeholder process and ensure their contributions are effective?
How can NERC promote improved alignment between subject matter experts, trade associations, industry leadership, the MRC and NERC?
Multiple respondents brought up issues with NERC’s onboarding process. Electricity Canada, a trade group representing Canadian electric utilities, cited the ERO Enterprise’s “complexity” as “a barrier to onboarding new entrants,” despite acknowledging NERC’s efforts to provide documentation for its resources. The group suggested the ERO create a dedicated section on its website for bringing newcomers up to speed, in addition to offering “introductory courses on NERC fundamentals” that can be tailored to more specific topics.
The Edison Electric Institute echoed Electricity Canada’s thoughts but advised that any introductory courses should include in-person learning sessions rather than being limited to prerecorded webinars and slide decks. EEI explained that webinars “lack dialogue and opportunities for interaction,” and new participants would benefit from discussions with their more experienced colleagues.
A group of federal utilities and power marketing administrations said NERC should “learn more about the new entrants,” including their corporate goals and the regulatory structures under which they operate. The ISO/RTO Council (IRC) added that NERC’s onboarding materials should address each responsible entity’s “role and responsibilities within the broader NERC community.”
Regarding the ERO’s engagement with existing participants, several entities raised concerns about the volume of projects underway at NERC. A collective letter from members of the cooperative sector noted that “there continues to be significant requests for industry comments on reliability standards, guidelines, and data requests.”
The cooperative members said the high level of activity can “become burdensome” for industry and warned that projects may be “pushed through the approval process to satisfy a FERC rulemaking.” They asked for “more robust” communications from NERC to help industry grasp the benefits and impacts of proposed standards, with outreach tailored to specific sectors.
Representatives of the merchant electricity generator sector said NERC’s practice of allowing entities to register in multiple segments, and therefore cast multiple votes, gives too much power to members that can qualify in multiple segments. For example, the writers observed that segment 5 — electric generators — “allows participation by merchant generators; renewable resources; municipalities, cooperatives and vertically integrated utilities that hold generation.”
“There was a recent vote where the merchant generators and renewable developers overwhelmingly opposed a proposed standard, yet a majority of the segment representatives voted for the standard,” the merchants said. “Presumably these multisegment entities coordinated voting across segments.” The writers suggested that this potential power imbalance might discourage entities from participating.
Reliability, Transparency
Members urged NERC to focus on its leading role in the community of electric reliability, with members from the electricity marketer sector suggesting the ERO improve industry alignment by prioritizing “targeted areas with the greatest impact for improving reliability.”
The IRC pointed out that the power grid’s generation mix is changing rapidly, and not all new resources will be subject to NERC’s reliability standards. Their response suggested that NERC “engage with applicable regulatory entities” to promote awareness of these resources’ potential reliability impacts.
Representatives of the North American Generator Forum repeated these calls for communication, recommending that NERC reach out to trade associations and other industry participants frequently and “facilitate calls and/or virtual meetings” to promote the exchange of information. EEI also emphasized the importance of transparency, noting that “the ability to develop robust solutions in a timely manner is impaired when industry and NERC do not have the same understanding of the underlying problem.”
“It is critical that the problem statement for risks that need to be addressed through standards projects or other activities is clear and well understood by the industry,” EEI said. “Investing more time up front explaining and soliciting broad stakeholder feedback on an issue, and subsequently on the proposed solution, should result in better alignment, less rework and a more efficient process.”
