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November 7, 2024

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MISO Tries to Win over Stakeholders on New LMR Capacity Accreditation

INDIANAPOLIS — Stakeholders appear wary of MISO’s proposed, availability-based accreditation method that it plans to file with FERC by the end of the year for the RTO’s approximately 12 GW of load-modifying resources (LMRs). 

MISO wants to accredit LMRs based on past performance levels by the 2028/29 planning year. It would split them into two categories — those that can respond in 30 minutes or less and those that can’t — and accredit them accordingly. (See MISO Proposes to Split LMR Participation, Accreditation into Fast/Slow Groups.) 

The LMR Type II category would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step 2 events. An LMR Type I class would carry a maximum response time of six hours and be called up earlier, when MISO declares a maximum generation alert. The RTO has long said it needs to be able to access LMRs outside of actual emergency declarations. 

MISO plans to use a similar accreditation to its proposed, availability-based method for its more traditional generation resources. However, to measure demand response, MISO said it would use backward-looking meter data from hours when capacity advisory declarations are in place to accredit resources. The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year and will give more weight in accreditation to performance during hours when capacity advisories escalate into maximum generation events, alerts or warnings. 

The RTO would cap accreditation at an LMR’s maximum stated capability during registration and reduce accreditation when LMR owners submit inaccurate availability information. Currently, MISO does not tie the accuracy of LMR availability data to accreditation values. 

During a Sept. 23 stakeholder workshop, WPPI Energy’s Steve Leovy said he was concerned that the sample size of hours during which capacity advisories are in effect is too small to be a good indicator of LMR performance. He said MISO’s capacity advisories seem too infrequent to use as a basis for accreditation.  

Other stakeholders said one year’s worth of data might not be adequate to create a stable, year-to-year accreditation. They pointed out that a particularly heat wave-laden or mild summer could skew the numbers, especially for those LMRs tied to air conditioning loads.  

MISO said it will turn to other previous years as needed if the past season doesn’t have the requisite 65 hours. Joshua Schabla, an economist in MISO’s market design group, also said the RTO intends to account for temperature-based adjustments in the accreditation. 

MISO said it needs the split classification because its long-lead-time LMRs are incapable of deploying in the time it takes for emergencies to materialize. The RTO experiences maximum generation alerts most frequently, with 20 occurring between 2020 and 2023, compared to 10 warnings, four maximum generation emergency step 1 events and five maximum generation emergency step 2 events in the same time frame. 

“Resources that deploy earlier can be used effectively, even if the event escalates quickly,” Schabla said. “In practice, we need these long-lead resources to be called up during maximum generation alerts.”  

MidAmerican Energy’s Dennis Kimm asked for more nuance beyond the two capability classes. He said MidAmerican has several LMRs that can respond within two hours but none that are ready within 30 minutes. Leovy advocated for the 30-minute requirement to be bumped up to a two-hour response time. 

Schabla said LMRs are more highly accredited than any other in its resource stack, yet the LMRs are less available than any other in its resource stack. “There’s a fundamental disconnect here.” 

Though MISO officially has about 12 GW of LMRs, staff have said MISO receives only about 7 GW to 8 GW worth of movement during emergencies. 

Schabla said the gap does not necessarily mean LMR owners are doing anything wrong or gaming the system. He said it likely represents a “misalignment between what is accredited and what is available.” 

In August, Reliability Subcommittee Chair Ray McCausland called the LMR response rate “eye-opening” and “a huge concern.” 

The RTO currently has an “inability to access many of the megawatts available in a useful time frame,” Executive Director of Market and Grid Strategy Zak Joundi said at MISO Board Week this month. The inability is magnified by the fact that MISO currently must declare an emergency before gaining access to load adjustments, he said.  

“We want to make sure [that] if someone is clearing the Planning Resource Auction, we can access those resources and they can deliver,” Joundi said. 

Joundi acknowledged to board members that stakeholders were dissatisfied with MISO’s timeline.  

“Ultimately, we want to make sure the rules we file at FERC are effective,” Joundi said. “Our goal is not necessarily to discourage the megawatts that are important. We want to make sure there are megawatts that we can leverage under the circumstances that we do.” 

MISO will again discuss LMR accreditation with stakeholders at its Oct. 9 Resource Adequacy Subcommittee meeting. 

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California GHG Emissions Decreased 2.4% in 2022

California’s greenhouse gas emissions fell by 2.4% in 2022 compared with the prior year, with the largest decrease seen in the transportation sector, according to a report released Sept. 20 by the California Air Resources Board.

The state’s total GHG emissions were 371 million metric tons (MMT) of CO2 equivalent in 2022, a figure that includes emissions from imported electricity. The decrease from 380 MMT in 2021 resumes the generally declining trend of GHG emissions that the state has seen since 2004.

The year 2021 was an exception to that trend, when GHG emissions grew by about 3%. The emissions increase in 2021 was viewed as rebound from the COVID-19 pandemic, which sent GHG emissions plummeting in 2020.

According to the CARB report, the transportation economic sector accounted for 39% of California’s GHG emissions in 2022, followed by the industrial sector at 23%. The electricity sector contributed 16% of the state’s GHG emissions: 11% from in-state generation and 5% from imports.

Transportation sector emissions fell by 5.2 MMT in 2022, a 3.6% decrease. Emission decreases were seen for passenger vehicles as well as heavy-duty vehicles. CARB attributed the drop to the increased use of renewable fuels and growth in the zero-emission vehicle market.

Emissions from electricity generation fell by 2.6 MMT, or 4.1%, in 2022 due to increases in in-state solar power and hydropower and an increase in imported wind power, according to the report.

GHG emissions dropped in five out of seven sectors that CARB tracked. Emissions were up by 1.7% in the residential and commercial sector, which CARB attributed to an increase in commercial activity following the pandemic. On the residential side, emissions fell slightly in 2022.

California’s agricultural sector accounted for 8.0% of statewide GHG emissions in 2022. Livestock emissions, which are responsible for 70% of the sector’s emissions, fell in 2022 due to the use of methane digesters funded by the California Climate Investments and incentivized by the Low Carbon Fuel Standard, CARB said.

Assembly Bill 32 of 2006 set a state limit of 431 MMT of GHG emissions in 2020. California emissions dropped below that limit in 2014, six years ahead of schedule. Now the state is working to reduce GHG emissions to 260 MMT by 2030, a limit set by Senate Bill 32 of 2016.

The state has set a target of net-zero emissions by 2045.

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DOE Awards $3B to Tackle Gaps, Challenges in US Battery Supply Chain

The Smackover Formation in southwest Arkansas has one of the highest lithium brine concentrations in the U.S., which is why the Department of Energy is planning to invest $225 million in federal funds to help stand up an environmentally sustainable lithium extraction and purification project being developed by SWA Lithium. 

A partnership between Standard Lithium and Equinor, SWA is one of 25 battery supply chain projects DOE has selected to receive $3 billion in grants from the Infrastructure Investment and Jobs Act, according to a Sept. 20 announcement. 

“The selected projects will retrofit, expand and build new domestic facilities for battery-grade processed critical minerals, batter components, battery manufacturing and recycling,” the announcement said, as well as create 8,000 construction and 4,000 permanent operating jobs.  

Located in 14 states, the awardees represent the “most essential building blocks of the battery supply chain,” as well as a diverse range of companies, according to DOE. For example, Dow Chemical is set to receive $100 million to turn waste carbon dioxide into battery-grade electrolytes, while Silicon Valley startup Mitra Chem is up for a $100 million award to manufacture next-gen lithium iron phosphate battery components in Muskegon, Mich. 

“This award selection represents a pivotal moment for the entire U.S. battery industry,” said Vivas Kumar, CEO of Mitra Chem. “By bringing advanced battery production to American soil, we’re securing our energy future and positioning the U.S. at the forefront of the global electric vehicle revolution.” 

The company’s DOE grant is being topped up with a $25 million grant from Michigan, according to a Mitra Chem announcement.

Awardees must be able to match the IIJA funds dollar for dollar at least as part of the negotiations that will now begin to finalize contracts for the awards. The DOE announcement also noted that nearly 90% of the projects will be located in or adjacent to disadvantaged communities, and more than half have already signed or committed to signing project agreements with labor groups. 

The SWA project, for example, has committed to ensuring that 40% of workers and 20% of apprentices on the project will be local hires. 

“Taking action on climate change and rebuilding our domestic manufacturing capacity are mutually reinforcing goals,” said Ali Zaidi, White House national climate adviser. 

The “game-changing” awards announced Sept. 20 will “support the technologies that we need in the market today, the components that we will need in the future and the innovative technologies we need to advance our vision for a circular domestic battery supply chain,” Zaidi said. 

Breaking Chinese Dominance

With batteries a core technology for decarbonizing the grid and electrifying transportation, building out a domestic supply chain ― and breaking China’s dominance in critical mineral processing and battery manufacturing ― has been a political flashpoint and a high priority for the Biden administration.  

The success of these projects could also have a critical impact on EV adoption rates in the U.S., as half of the Inflation Reduction Act’s tax credits for EVs require that their batteries meet specific domestic content requirements. (See Will Final Rules on EV Tax Credits Help or Hurt US Market Growth?) 

Released in May, the Treasury Department’s final rules on the tax credits give automakers a two-year phase-in period for some of the domestic content provisions — for example, graphite — but also puts DOE’s awardees on relatively short lead times. 

Mitra Chem, for example, expects its plant in Muskegon to be online and ready to double the U.S. output of lithium iron phosphate by 2027. 

The current awards are the second round of grants for battery materials processing, manufacturing and recycling, following $2.8 billion in awards to 20 companies announced in October 2022.  

At the time of the first awards, DOE had set ambitious targets for companies building out U.S. supply chains, such as developing enough battery-grade lithium to manufacture 2 million EVs annually. Scale is still a factor in the second round, but DOE is also focusing on some of the main challenges facing the EV industry: from ongoing consumer anxiety about EVs’ range and charging times to the environmental impacts of lithium mining. (See DOE Awards $2.8 Billion to ‘Supercharge’ Battery Production.) 

With a $67 million grant, Albemarle US plans to retrofit a manufacturing facility in Charlotte, N.C., where it will produce advanced lithium anodes that will increase EV battery density and range, cut charging times and improving safety. Target output is 50 metric tons per annum. 

Forge Battery intends to use its $100 million grant for a first-of-its-kind facility, also in North Carolina, to manufacture high-performance lithium-ion battery cells for “underserved, specialized domestic markets,” including heavy-duty trucks, off-road vehicles, and aerospace and national defense applications. Production will begin in 2026 and reach full capacity — 3 GWh per year — by 2029. 

And the SWA project aims to be a model for sustainable lithium mining through its use of direct extraction technology, which draws lithium brine from aquifers, filters out the lithium and then reinjects it into the ground to create a closed-loop process. The first phase of the project could produce up to 22,500 MT of lithium carbonate per year, the company says. 

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Northeast Utility Commissioners Talk Costs of Grid Modernization

BOSTON — Increasing electricity prices must be met with a greater effort to reduce peak loads and protect low- and moderate-income ratepayers, several Northeast utility regulators said at Raab Associates’ New England Electricity Restructuring Roundtable on Sept. 20.

“There is no question that affordability is being strained today,” said Ron Gerwatowski, chair of the Rhode Island Public Utilities Commission, adding that electricity costs are likely to remain high for the foreseeable future.

U.S. Bureau of Labor Statistics data shows the Northeast has some of the highest electricity prices in the country, rivaled only by parts of the West Coast. The costs associated with transmission and distribution system upgrades and grid decarbonization could push rates even higher.

While investments in grid infrastructure and renewable generation may benefit ratepayers in the long-term, Gerwatowski stressed that many customers are “not worried about whether electricity rates will stabilize in the long-term, they’re worried about paying their electricity bills today.”

However, Gerwatowski also emphasized it is “oversimplistic, and not reasonable, to blame the strain on affordability solely upon the costs associated with any one individual initiative, especially our initiatives that are designed to advance renewable energy deployment in order to address carbon emissions.”

He said the region’s rates are being pushed up by inflation, the increasing need to replace aging grid infrastructure, high winter gas costs, utility biases toward capital expenditures and the decreasing availability of easy energy efficiency improvements.

Massachusetts Department of Public Utilities Commissioner Staci Rubin said LNG volatility and reliance on the Everett LNG import terminal also contributes to high rates, along with predatory third-party competitive suppliers.

Rubin said the ratepayer benefits of long-term renewable energy contracts often are not apparent to customers, noting that “things like price suppression do not actually show up on your bill.”

At the same time, “the entire clean energy transition cannot be funded entirely through electricity bills — we need to look for outside sources of funding,” Rubin said, emphasizing the importance of seeking and using all available federal funding.

Maine PUC Commissioner Carolyn Gilbert added that electricity bills are a “somewhat regressive means” to fund the clean energy transition. She said states must push to unlock cost and emissions savings from time-varying rates, echoing similar comments made by Gerwatowski.

“Any time there’s a potential to save money I think we have to go after it,” Gilbert said.

Lisa Wieland of National Grid, which owns electric and gas utilities in Massachusetts, said the company this fall is beginning a multiyear process of deploying advanced metering infrastructure (AMI) in the state. The company expects to bring AMI to between 750 and 1,000 of its approximately 1.3 million customers in the state by the end of the year and plans to roll out time-varying rates once it has completed most of its AMI deployment.

Gas Decarbonization

Reducing the region’s reliance on natural gas is essential to keeping energy costs manageable in the region, said Bradley Campbell, president of the Conservation Law Foundation.

“The energy transition can drive affordability,” Campbell said, adding that “the message that the clean energy transition is antithetical to affordability” is “a false narrative being pushed heavily by the fossil fuel industry.”

While the Massachusetts DPU has ruled the state will need to chart a course off gas to meet its climate goals (DPU 20-80), natural gas consumption in the region for buildings and electricity generation has ticked up in recent years, according to state’s most recent emissions inventory update and data from ISO-NE.

Gas prices remain a key driver of the region’s energy costs, with pipeline constraints driving up gas prices in the winter and leading to expensive out-of-market contracts for LNG. Enbridge, which owns the major natural gas pipeline into the region, has proposed a major project to expand its gas transmission capacity into the region, to the staunch opposition of climate activists.

grid

From left: Dan Berwick, New Leaf Energy; Lisa Wieland, National Grid New England; Claire Coleman, Connecticut Office of Consumer Counsel; and Janet Gail Besser, moderator | © RTO Insider LLC

“In a region where ratepayer misery is driven by gas price volatility, the message that we should double down on natural gas dependency in New England is not only unsound, it’s immoral,” Campbell said.

Disagreements between the Massachusetts Senate and the House over how aggressively the state should move away from gas have derailed progress on a wide range of other climate and energy issues, including a widely agreed-upon proposal to reform the permitting and siting processes for clean energy infrastructure. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.)

“Massachusetts siting reform failed to pass, despite broad consensus, because gas utilities would not agree to take the first steps needed to implement the DPU’s order on the future of gas,” Campbell said. He criticized both the administration of Massachusetts Gov. Maura Healey (D) and the utility industry for not moving more quickly to prepare for the transition away from gas.

At the same time, he expressed optimism about the administration’s newly created Office of Energy Transformation, which he said could “could provide the venue to forge consensus among stakeholders on how to speed the energy transition while advancing affordability.”

Solar Stagnation

Dan Berwick, CEO of New Leaf Energy, expressed concern about the stagnation of solar development in the state, noting that 2023 was “the lowest year for solar deployments in over a decade” in the state, with 2024 tracking to be even lower.

While large-scale solar projects are the cheapest form of solar in the state, “we’ve all but stopped doing big solar projects in Massachusetts,” Berwick said. He attributed the slowdown to interconnection delays and constraints on where solar projects can be sited to receive support from state programs.

“We have a much more restrictive land use framework for our clean energy developments than we do for other types of developments,” Berwick said, also expressing hope that “there’s an outcome that we ought to be able to find alignment on.”

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NJ Committee Backs Bill to Require Fast-charger Tariffs

The New Jersey Assembly Transportation and Independent Authorities Committee on Sept. 19 advanced legislation that would require utilities to submit tariffs for commercial direct current fast chargers (DCFCs) and limit their ability to set their rates based on peak demand. 

The committee voted 7-5 along party lines to advance A4624, which would require utilities to “utilize alternatives to both traditional demand-based rate structures and capacity demand charges” and “establish cost equity between commercial electric vehicle tariffs and residential tariffs.” Tariffs would be due to the Board of Public Utilities for approval within 180 days after the bill became law.  

As in other states, the limited availability of chargers in New Jersey is considered a key stumbling block to EV uptake. The state in June had 185,000 EVs on the road, which are served by 2,421 Level 2 ports and 1,249 DCFC ports, according to Atlas Public Policy, which provides information to the New Jersey Department of Environmental Protection. That’s about one DCFC port per 148 vehicles. 

Committee Chair Clinton Calabrese, the bill’s sponsor, said A4624 is needed to stimulate investment in DCFCs. Developers have shied away from investing in high-speed chargers in the state because the elevated rate levels stemming from the use of peak demand calculation methods make the infrastructure economically unviable, he said. 

“This bill is necessary and vital [to] advancing New Jersey’s electric vehicle infrastructure by ensuring a fair and supportive rate structure for charging stations,” Calabrese said. “The bill is essential to overcoming a significant financial hurdle — which is known as demand charges — that has been a barrier to investment in fast-charging infrastructure across the state.” 

Demand charges were created to address the needs of “large industrial customers who use substantial amounts of electricity consistently, and they are intended to help utilities recover those costs of maintaining the grid’s capacity to meet spikes in demand,” Calabrese said. But while DCFCs may have brief, high demand peaks, “they don’t use as much energy overall during the billing cycle,” he said. 

Calabrese added that he had amended the bill to add a “phased approach” that would give businesses “certainty and stability” by initially setting rates low and introducing demand-based rates over time as EV charging around the state increased. 

The bill would also require any new rate-setting system to be “non-volumetric,” and it explicitly requires utilities’ tariffs to “accelerate third-party investment in electric vehicle charging infrastructure” and “promote electric vehicle adoption in the state.”

Among the groups that opposed the bill were the Environmental Defense Fund and Clean Water Action, as well as business groups including the New Jersey Business & Industry Association (NJBIA), the New Jersey Chamber of Commerce and the New Jersey Utilities Association. 

Testifying before the committee, Doug O’Malley, director of Environment New Jersey, said the “bill’s intent is exactly right” in its effort to put more chargers in communities. But it also is “essentially short-circuiting a process that is already ongoing” through the BPU. One of the group’s concerns is that it does not resolve the question of who would pay for the discounted rates if the commercial customers paid less, he said. 

Rhiannon Davis, director of government affairs at Electrify America, which has 4,200 chargers across the U.S., said in support of the bill that “demand charges can account for over 90% of electricity costs for DC fast charging and lead to operating costs that far exceed the revenue these chargers can receive from customer payments.” 

She said a typical Electrify America DCFC station has four to six chargers that serve customers at a year-round rate that is calculated at a peak of “just a few hours of charging over the summer.” 

Eric DeGesero, a lobbyist representing the New Jersey Motor Truck Association, said he initially supported the bill but was not sure of the organization’s position after the amendments were added. 

He said that in general, demand charges add to the hurdles blocking electric truck adoption, which include a price tag that is about three times that of a diesel truck and a reduction in the amount of cargo that can be carried because the battery takes up so much space and weight. 

DeGesero added that truck charging costs are driven up dramatically by the amount of electricity needed, which requires the installation of new interstate transmission lines and new substations. 

While some Republican committee members said they were swayed to vote against the bill, Democratic legislators backed it. 

“I know that there’s going to be additional discussion about this and potential changes down the road,” Assemblymember David Bailey Jr. (D) said. “I am going to vote ‘yes’ for now.” 

EV Parking Dilemma

With a 7-4 vote, the committee also advanced A3035, which would prohibit gas-fueled vehicles from parking in a space with an EV charger in place. Violation of the law could incur a $55 fine for the first offense and $100 for the second offense. 

Opponents of the bill argued that the issue would be better handled at the local level. 

But O’Malley called it a “no-brainer,” adding that a regular car parking in front of an EV charger is the equivalent of someone parking in front of a gas pump. 

“EV drivers that need to have that spot need to know that when you look on an app … and it says that a spot is open,” that the space is available, he said. If “you pull in and the spot’s blocked, that’s a huge problem.” 

Chair Calabrese, who also sponsored the bill, said a statewide law is far simpler than local regulation, the latter of which “would mean every municipality would have to pass an ordinance for this.” 

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Dominion CEO Says Virginia Well Poised to Meet Growing Demand

MCLEAN, Va. — A growing economy driven by new data centers has demand surging in Dominion Energy’s utility territory, CEO Robert Blue said in a speech Sept. 20. 

“Demand for electricity is growing at levels not seen since the years following World War II,” Blue said. “We hit new summer demand peaks in each of the past four years. This year, we’ve had not just one peak, but a whole series of them. In fact, seven out of the 10 highest system peaks that Dominion Energy has ever seen took place in a single two-week period this summer.” 

That was in line with Dominion’s forecast, and there is no sign of it stopping anytime soon, Blue said at a luncheon hosted by bipartisan business group Virginia FREE. 

PJM expects demand in Dominion’s territory to rise by 85% over the next 15 years, which is far more than it had to deal with in the previous 15, Blue said. That is going to have impacts on reliability, affordability and the transition to cleaner energy, he said. 

The utility needs to maintain resource adequacy not just for its residential customers, but for large government and business customers in the D.C. area. 

“Some of the entities we serve include the Pentagon, the CIA, the NSA and seven FBI field offices,” Blue said. “As many of you know, around two-thirds of the world’s internet traffic passes through Northern Virginia, so it’s no exaggeration to say [that] if we don’t execute on our mission, people around the country and even around the globe can’t execute on theirs.” 

Blue said Virginia’s policies have prepared the firm to handle continued growth by allowing it to build several new natural gas plants around the state in recent years, but given how much demand is growing, it will need more supply. 

“We’re going to have to add more generation and more transmission, and we won’t be able to match rising customer needs with renewable generation alone,” Blue said. “Now understand, we’re adding renewable resources at a rapid pace … but we’re also going to need other forms of generation to step in when the weather doesn’t cooperate, as well as during periods of high demand, such as cold snaps and heat waves.” 

That includes building more natural gas plants, preserving Dominion’s existing nuclear capacity and perhaps building new nuclear resources as well. (See Dominion Issues RFP for Small Modular Reactor at North Anna.) 

The Virginia Clean Economy Act requires carbon neutrality by 2045; Blue said Dominion has already cut its emissions in half since the early 2000s, as it has replaced coal plants with natural gas. The former’s share of the company’s generation mix has plummeted from over half in 2005 to about 10%. 

“That’s had a substantial impact on our emissions profile,” Blue said. “It’s also given us the confidence to layer in more renewables, knowing that when the weather isn’t cooperating, gas-fired generation can step in and support our customers.” 

A decade ago, Dominion had no solar; now it has one of the largest portfolios of any utility. And the Coastal Virginia Offshore Wind Project is moving ahead on budget with construction on schedule, even as offshore wind in the Northeast has run into many issues. 

“One big reason we’ve succeeded where others haven’t is Virginia’s regulated utility model, which requires us to demonstrate prudency before we can move forward with the project,” Blue said. “Indeed, I would say ‘prudency’ is the defining characteristic of Virginia’s regulatory compact, and that distinguishes our state from others that have recklessly deregulated their electricity markets.” 

Blue said utility rates are higher in deregulated states, and unscrupulous retailers use deceptive and high-pressure marketing techniques on vulnerable consumers. The winter storm of February 2021 wreaked havoc in Texas — a state often held up as the model for restructuring retail power markets, he added. 

Virginia is not the only traditionally regulated state in PJM, but it is part of a minority, as states like Pennsylvania, New Jersey and Maryland have all opened up their retail markets to competition and given up some authority over generation in the process. 

In 2020, Virginia imported 18% of its power from other states in PJM, but with the surge in demand, that figure is up to 37% so far this year, Virginia Department of Energy Director Glenn Davis said in remarks later during the event. 

Davis said Virginia Gov. Glenn Youngkin (R) has endorsed an “all-of-the-above” energy policy that includes all traditional forms of energy, as well as new, cleaner ones. One of the administration’s goals is to ensure Virginia has enough power that it does not need to rely on imports from other states, he said. 

Imported power “has helped us meet our short-term demand because of our growing economy; it also gives us some serious long-term concerns,” Davis said. “Relying on imported power from PJM means that decisions made by states outside of Virginia — by the other 12 PJM states — have a direct impact on the reliability and cost of the energy supply.” 

Dominion gets several benefits from being in PJM, especially with its long-term, cost-effective regional transmission planning that helps it meet load growth, spokesperson Aaron Ruby said. PJM’s wholesale power markets also ensure the lowest-cost power is available for its customers every day. 

“With that said, we agree we don’t want to be over reliant on out-of-state power, which is why we believe in the regulated model,” Ruby said. “It gives Virginia utilities and our customers more control over our own power supply, which is the best way to ensure our power remains reliable, affordable and increasingly clean.” 

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ERCOT Technical Advisory Committee Briefs: Sept. 19, 2024

Members Endorse Ancillary Services Methodology for 2025

ERCOT stakeholders have endorsed changes to the grid operator’s ancillary services methodology as part of the annual process to determine the minimum amount of products that will be procured in 2025.

Staff’s proposed modifications, presented to the Technical Advisory Committee during its regular monthly meeting Sept. 19, include three revisions to ERCOT contingency reserve service (ECRS). ERCOT introduced ECRS last year, but it drew opposition from the Independent Market Monitor, which said the service produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)

The Monitor is working with ERCOT and Texas Public Utility Commission staffs on a report for the Texas Legislature that is due by October. The IMM’s director, Jeff McDonald, said there were “limited opportunities” to add lessons learned from the study to the AS methodology process but that he was happy with staff’s recommendations.

“I think we’ve learned some things about procurement targets and some potential recommendations for how the procurement process can be adjusted to result in a lower cost without compromising reliability,” McDonald told TAC. “We do note that that we’re seeing a more targeted procurement through this process, resulting in a reduction in both the ECRS and [non-spinning reserve service] levels procured. We’re happy to see that. … We will have some recommendations that come out of the AS study that we feel will be very important to be taken up and discussed in the 2026 methodology process.”

Staff proposals for ECRS include removing the adjustment for risk coverage during sunset hours to at least the 90th percentile; adjusting the frequency recovery portion to cover 70% of historic net load and inertia conditions; and computing the minimum ECRS requirements as the larger of the capacity needed to recover frequency and capacity needed to support net load forecast.

Since ECRS first was deployed in June 2023, staff said there have been “very few situations” when ECRS had to be released for net load forecast issues and frequency recovery needs. The changes will result in setting ECRS quantities based on needs of the dominant operational risk in every hour, they said.

Staff also proposed minor changes to non-spin, regulation service and responsive reserve service (RRS):

    • Non-spin would be revised so the methodology computing its quantities between 10 p.m. and 6 a.m. uses a four-hour-ahead net load forecast error.
    • Regulation quantities would be computed using the historic error in security-constrained economic dispatch’s forecasted net load.
    • The minimum RRS-primary frequency response (PFR) limit would change to 1,365 MW.

NRG Energy’s Bill Barnes, who represents Reliant Energy Retail Services, asked whether the transition to real-time co-optimization (RTC) next year will affect the math used to calculate “some amount” of AS to be procured throughout the year. ERCOT has set a December 2025 go-live date for RTC, which will procure energy and AS every five minutes. (See ERCOT Sets Go-live Date for RTC, ESR Project.)

“We implement RTC and that all goes away, right?” he asked. “Because how much ancillary services you actually procure is all dependent on price. At that point, the quantities will vary significantly. So I’m wondering, how do we bridge that gap, right?”

“From our perspective, RTC does not change the quantity of ancillary services that we need because the quantities are based on the fundamental operational risks,” said Jeff Billo, ERCOT’s director of operations planning. “So it’s how much RRS do you need to arrest the frequency? How much ECRS do you need to recover frequency? But those fundamentally are physics-based questions that RTC is not changing.”

Billo said ERCOT will propose a methodology similar to the current one as the grid operator goes into 2026. He said he took note of stakeholder feedback from a recent AS workshop about procuring the services closer to real time or the operating day, as opposed to calculating it annually.

“I think that could change the quantities, but we think that doing that at the same time as RTC may not be preferable, and so we want to kind of put that off to 2027,” he said.

The measure cleared TAC, 26-1, with a couple of abstentions. Calpine’s Bryan Sams cast the lone dissenting vote against the changes, saying his organization believes there’s additional risk with the reduction of regulation in the morning and during the winter.

“The second reason is we still believe that ECRS sends, or has sent, an investment signal for new generation development and the reductions in ECRS, I think, are harming that signal,” Sams said.

ERCOT’s protocols require staff to provide at least annually the methodology for determining the procured quantity of each AS needed for reliability. The grid operator’s Board of Directors and the Texas PUC will review the recommendations before making their decisions.

Members Discuss Stakeholder Process

TAC devoted the first two hours of the meeting to a discussion with staff of the stakeholder process and communications. Two hours and 25 minutes later, the membership agreed to reserve time at the next meeting to pick up the conversation.

Members discussed how decisions are made at TAC, how the decision-making process is presented to the board and how the reasoning behind opposing votes is shared with the board.

The discussion was prompted after the PUC’s chair, Thomas Gleeson, said the interaction between the board and TAC “did not work” for him during a July open meeting. (See Texas Commission Rejects ECRS Rule Change.)

The PUC’s Barksdale English, a TAC member when he was with Austin Energy, said commission staff are working on a rulemaking related to the appeal of board decisions to the PUC and “should be coming soon.”

“We talked a lot about what your role is here and how Barksdale English would love for TAC members to view your responsibility here,” English said. “I guess it almost seems like there’s another conversation that needs to be had around how do you codify TAC’s role in receiving recommendations from your subcommittees and how do you codify what you’re communicating up to the board. At the end of the day, it will be the board members’ decisions on how to receive those requests.”

‘Cookies and Laughter’

After committee Chair Caitlin Smith, of Jupiter Power, said during TAC’s August meeting that she was open to lightening the atmosphere for members following comments that “unlike SPP, we don’t have ‘cookies and laughter,’” stakeholders were greeted with a virtual cornucopia of tasty treats. (See “Lightening the Mood,” ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024.)

A large chocolate chip cookie that seemed to have been sent from SPP’s Markets and Operations Policy Committee included a greeting that read, “SPP Cookie Power: From our stakeholder group to yours, we heard y’all need some cookies.” Another container of cookies were iced with “SPP.”

“I had an oatmeal raisin. It was delicious,” one member said.

Two other boxes of cookies were decorated with images of ERCOT CEO Pablo Vegas, a laughing emoji and the words “TAC IS FUN.”

The levity was provided by CIM View Consulting’s Steve Reedy, who reminded TAC that it was “Talk Like a Pirate Day.”

“How many letters does the pirate alphabet have?” he asked, before providing the answer. “I, I, R and the seven Cs.”

Change to CLRs Dispatch

TAC unanimously endorsed a Nodal Protocol revision request and its accompanying Other Binding Document request (NPRR1188, OBDR046) after late comments were filed.

The protocol change would modify the dispatch and pricing of controllable load resources (CLRs) in response to the PUC’s directive to increase the “utilization of load resources for grid reliability.” It revises the market-participation model of CLRs that are not aggregate load resources so that they are dispatched at a nodal shift factor and settled for their energy consumption at a nodal price.

The committee also endorsed a combo ballot that included three NPRRs, one revision to the Nodal Operating Guide (NOGRR) and the annual under-frequency load shedding survey of transmission owners, which found they met requirements for all five thresholds.

The protocol and guide changes, if approved by the ERCOT board, will:

    • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the dpth percentile difference.
    • NPRR1237: document the scenarios in which market participants are required to successfully complete retail qualification testing, regardless of whether the market participant previously received a qualification letter from ERCOT from prior retail flight testing.
    • NPRR1244: align eligibility provisions for CLRs not providing PFR to provide ECRS. It would also include in physical responsive capability’s calculation only the capacity of CLRs when they are qualified to provide regulation service and/or RRS that requires the CLR to be capable of providing PFR.
    • NOGRR263: clarify that a CLR is only required to provide PFR when it is providing an AS that requires that resource to be able to provide PFR.
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CAISO, Stakeholders Consider GHG Attribution for Non-priced States

CAISO is recommending it implement a Western Power Trading Forum (WPTF) proposal that could help the Extended Day-Ahead Market track and account for greenhouse gas emissions in a way that considers the variety of carbon pricing programs across the West.  

Central to the proposal, first presented by WPTF in March, is use of residual market supply — energy not committed to market participants or attributed to GHG regulation areas.  

The proposal assumes that if the market can ensure entities are able to claim and procure their own resources to meet load, what is left is a relatively small increment of energy, which is the residual supply, Clare Breidenich, WPTF assistant executive director, explained at a March meeting of the ISO’s Greenhouse Gas Coordination Working Group.  

The residual supply helps determine a residual emissions rate, which represents a dispatch-weighted average emission rate of the market supply. Under this framework, leftover energy in the market would go into the residual supply. (See CAISO, Stakeholders Consider 2 GHG Mechanisms for EDAM.) 

“This conversation around a residual rate is going to be robust in terms of how we calculate that,” Anja Gilbert, a lead policy developer at CAISO, said in a Sept. 19 meeting of the GHG group. “There’s questions on how we think about a residual rate for price-based states, for states with climate policies not based on a price, and then for states that do not have climate policies.”  

Portland General Electric Weighs in

Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), weighed in on how states like Oregon that don’t price carbon but do have climate policies could incorporate the proposal.  

While Oregon doesn’t put a price on GHGs, the state requires utilities such as PGE to reduce emissions every year until the utility is “under the 2030 hard cap for emissions that is based on an 80% reduction from a reference level.”  

“While that doesn’t necessarily entail a price on those emissions, we do see it as a hard limit, which can indicate that we have a significant willingness to pay for those emissions,” Sporborg said. “While we really like the structure and framework in this proposal, we want to open up some questions around how we can also ensure that capped states are having an equitable allocation or equitable access to the excess emissions framework consistent with or alongside of the GHG pricing zone states.”

Connie Horng, PGE’s principal greenhouse gas policy analyst, presented an alteration to the proposal, suggesting that if an LSE inside the GHG pricing area has excess designated energy, those megawatt hours and associated GHGs would be assigned to another LSE inside the pricing zone before being allocated to the residual market supply. Within this framework, PGE proposed looking beyond just a GHG pricing zone adjustment and incorporating a methodology that would be able to reflect all GHG regulated zones — including non-priced ones.  

“How do we expand from just the pricing zones that impact Washington and California to include the regulation that applies to Oregon and potentially other states who have these strong caps and a compliance framework associated with GHG?” Horng said. “Our goal here is to allow all of the GHG-regulated states with the clean energy portfolio requirements that we are bringing to the market to solve for each other’s excesses and shortfalls first, before we get that residual market calculation.”  

Gilbert questioned how the ISO might modify the approach to account for PGE’s suggestion.  

“Are we looking to modify the WPTF approach for price-based regions to include states like Oregon? Or is a separate residual rate for Oregon that is applied to Oregon LSEs or BAAs required?”  

Sporborg said PGE was open to both solutions, but thinks they need to be explored more thoroughly.  

“Our goal is to really maximize the diversity benefits from the states,” Sporborg said. “Even though we don’t have the pricing component to our regulation, we will still be making investments in a diverse portfolio of clean energy supply to meet our 2030 goal. … If we can find an opportunity that allows us to participate in the broadest regional diversity and to also benefit from the greening of the portfolios that will create this residual excess, I think that is the solution that we would want to get to optimally.”  

The ISO is seeing feedback on PGEs proposal in written comments and will continue to discuss it in later working groups.  

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Texas RE Endorses ERO Enterprise Strategy

The Texas Reliability Entity’s Board of Directors has unanimously endorsed the ERO Enterprise’s long-term strategic plan that will guide NERC and its regional entities in their collective priorities and activities. 

The strategic plan identifies focus areas to help guide the ERO Enterprise over a longer-term planning horizon and annual work plan priorities that identify performance goals and key accomplishments. It has not been updated since it was created in 2019. NERC hopes to present it to its Board of Trustees in October for approval. 

“[NERC is] looking for each region to indicate their support for this approach, so that all six regions have expressed this is a framework that we can collectively operate under,” Texas RE COO Joseph Younger said during the board’s Sept. 18 meeting. He said at least three other REs have endorsed the plan. 

The plan’s four focus areas are: 

    • using data, tools and approaches to help stakeholders and policymakers address existing risks to the bulk power system and proactively identifying and preparing for emerging and unknown risks. 
    • maintaining cyber and physical security programs that are risk-based, efficient and coordinated and that effectively advance the industry’s security posture. 
    • ensuring that stakeholders and policymakers find value in engagements with the ERO Enterprise and seek its expertise. 
    • performing as an effective and efficient team acting in coordination and ensuring its programs and efforts deliver value for stakeholders and policymakers. 

“It’s a broad umbrella. Honestly, things are changing all the time, but those four categories kind of encompass … all the things that we’re working on,” Younger said. “We hope that it can stand the test of time for a few years.” 

In other actions, the board’s Nominating Committee said it has nominated Milton Lee for a third and final three-year term, effective Jan. 1, 2025. 

“I’m getting so old I wonder if I can actually get up in the morning,” Lee said. “I didn’t think I would make it this far, but I plan to be here for the next three years.” 

Texas RE staff said it had 630 registrants and 495 attendees for its Cyber and Physical Security Workshop, held Aug. 28 in San Antonio. Panels focused on critical infrastructure, threat assessments, current and future grid technologies, and security posture.

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WestTEC Seeks to Close $2.1M Funding Gap Despite DOE Boost

The Western Transmission Expansion Coalition’s (WestTEC) transmission planning study is getting a boost from a $1.75 million Department of Energy grant even as the cost of the project has grown to $6.1 million. 

When the grant application was submitted in January, the preliminary project cost was $4.8 million. DOE is funding 37% of that, or $1.75 million. Western Power Pool (WPP), which is facilitating WestTEC, is expected to provide about $3 million in matching funds. 

Additional funding of $2.2 million is coming from WECC, which is partnering with WPP on the project. 

With the new cost estimate of $6.1 million, WPP is working to close a funding gap of about $2.1 million. Funds will come from sources including WPP members, WestTEC participants and other regional partners that support WestTEC, WPP CEO Sarah Edmonds said in an email. 

During the WECC Board of Directors meeting Sept. 17, CEO Melanie Frye said a three-party contract for the WestTEC project has been drafted among WPP, WECC and Energy Strategies, an energy consulting firm that will do most of the analytical work. 

Frye said WECC is making sure the project qualifies as reliability work under Section 215 of the Energy Policy Act. 

“As of yet, we’ve not expended any funds,” Frye said. “We are wanting to make sure that we have the contract in place and that we’re very clear on what it’s funding so that it’s not falling outside the bounds of the Section 215.” 

The WestTEC study will address long-term interregional transmission needs across the Western Interconnection. The WestTEC Steering Committee recently unanimously approved the project’s study plan. (See WestTEC Committee OKs Plan for ‘Actionable’ Tx Study.) 

The study is expected to take place over the next two years. The goal is to produce transmission portfolios for 10- and 20-year planning horizons. In addition to enhancing Western reliability, the portfolios will also factor in economic efficiencies and state policy goals. 

The grant funding for the study is from the Wholesale Electricity Market Studies and Engagement Program in the DOE’s Grid Deployment Office. The program provides funding to states and regions related to developing, expanding or improving wholesale electricity markets. 

When U.S. wholesale markets were designed three decades ago, the nation’s electric grid “looked much different,” GDO Director Maria Robinson said in a statement regarding the grant program. 

“With the widespread deployment of new clean energy resources and advanced grid and transmission technologies, creating effective wholesale electricity markets is critical,” Robinson said.