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November 14, 2024

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FERC Again Questions MISO Reliability Payments to Wisconsin Coal Plant

FERC once again has determined that the continuing payments MISO is making to a Wisconsin coal plant to stay online to sustain system reliability might be too steep.  

The commission in a Jan. 31 order said Manitowoc Public Utilities’ proposed $1.16 million monthly compensation to continue operating its Lakefront 9 coal unit as a MISO System Support Resource (SSR) may be unreasonable (ER24-525). It set the matter for hearing, settlement and refund procedures. The new payments took effect Feb. 1.  

It’s the second time FERC has indicated that Manitowoc Public Utilities is charging too much to maintain grid reliability. FERC in mid-January approved a settlement lowering Lakefront 9’s monthly payment to $880,000 instead of the utility’s originally requested $1.03 million for the past year. (See FERC Approves Settlement in MISO Reliability Payments to Wisconsin Coal Plant.) MISO’s SSR agreements must be re-evaluated and extended annually if necessary. 

The Wisconsin Public Service Corp. and WPPI Energy protested the amount, voicing concerns over Manitowoc’s estimates for labor and maintenance costs, taxes and insurance, legal and consulting expenses, depreciation costs, carrying charges and capital project expenses.  

Lakefront 9 began operating as an SSR in February 2023 after MISO discovered that thermal overloading and voltage issues could occur on several nearby constraints if the plant was permitted to suspend operations as scheduled. The utility intended to idle Lakefront 9 until 2026, when it could be converted to a renewable fuel source. 

MISO has said its members’ planned transmission upgrades for the area that will improve system performance and allow it to lift the SSR agreement won’t be ready until mid-2028. 

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FERC Gets Dueling Competition Studies in Transmission NOPR Docket

With FERC potentially issuing a final rule on transmission planning this year, the issue of whether it should curtail competition is the subject of dueling reports filed in the Notice of Proposed Rulemaking’s docket (RM21-17).

The Electricity Transmission Competition Coalition (ETCC) filed supplemental comments Feb. 1 with a report extolling transmission competition’s benefits in response to a report filed in December from a group called Developers Advocating Transmission Advancement (DATA) arguing the opposite.

DATA is made up of transmission owners Ameren Services, Eversource Energy, Exelon, ITC Holdings, National Grid USA, Public Service Electric and Gas, and Xcel Energy.

“Contrary to their plea to revisit the commission’s prior determinations supporting competitive solicitations under Order No. 1000, the incumbent TOs fail to demonstrate that cost-of-service regulation is as effective as competition in establishing just and reasonable transmission rates,” ETCC said.

Competition disciplines cost, but regulated utilities with monopolistic rights and guarantees projects will have an incentive to press for the highest returns possible, it said.

“In a regulated cost-of-service model, the utility has an inherent incentive to spend more because the utility can then earn more through a return of and on its investment,” ETCC said. “Through competition, a developer has an inherent incentive to find an innovative and efficient solution, while an incumbent with monopolistic, exclusive rights has no such incentive.”

DATA’s report argued that those promised cost savings have not appeared in the decade plus since Order 1000, highlighting the costs of projects that were subject to competition. While the docket had 774 filings as of press time Feb. 1, DATA argued that its report includes information FERC had not seen yet.

ETCC called the DATA report “an unverified, authorless and self-serving white paper/pamphlet,” which, it continued, lacks credibility and was filed in the docket at the last minute — 15 months after the reply comment deadline.

“The resulting analysis shows that, rather than Order No. 1000-mandated competition leading to cost savings, final costs for projects selected through competitive solicitations tend to exceed cost baselines by at least 6%,” DATA said. “Furthermore, with certain reasoned adjustments, average baseline exceedances are calculated in the 12 to 19% range.”

Winning bids for projects from competitive processes do not represent final project costs because what is actually recovered tends to exceed those considerably, DATA argued. And competitive proposals often include cost caps, but DATA said those do not appear to offer meaningful cost-containment protections for customers, with final project costs exceeding them.

DATA’s report was in response to a report the Brattle Group prepared for LS Power in 2019 that found that competitive forces saved 20 to 30% compared to monopoly projects, which has been widely quoted by supporters of competition. That report suffered from a lack of finalized projects, DATA argued, so Brattle had to use cost estimates.

Brattle’s report includes 22 competitively bid projects, but just nine of those were completed in a way that allows for apples-to-apples comparison, DATA said. Some of the projects did lead to cost savings, but they were outweighed by ones that came in above cost, and DATA found they led to 6% higher costs compared to their baselines.

ETCC noted that the Brattle report already drew a response the year it was released from Concentric Energy Advisors, to which Brattle then responded. The California Public Utilities Commission and competitive transmission developers had discussed those two 2019 reports in the NOPR docket.

“The incumbent TOs cherry-pick data from select competitive projects, misleadingly describe those projects and advance anecdotes that do not represent the spectrum of the competitive transmission experience,” ETCC said.

Some of the missing projects are successful competitive projects that led to cost savings and thus go against the TOs’ narrative, it added.

“Critically, the incumbent TO white paper rests on the flawed premise that costs exceeding a competitive developer’s initial winning bid will be recovered from consumers,” ETCC said. “Unlike the incumbent utilities, which can generally flow their project cost overruns into rates, most competitive developers cannot pass through cost overruns to consumers because binding cost caps and cost-containment commitments are necessary for a competitive developer to win a solicitation and be awarded a project.”

Projects that go over a hard cap need to get approval from FERC to actually recover those costs, but even those that allow for adjustments because of inflation, or recovery of some cost overruns, are better than monopolistic projects without any cost containment, ETCC said. Only one of the nine projects DATA covered sought cost recovery above its cap.

ETCC also argued that DATA’s paper cut out most of the 22 projects Brattle studied to get the results it wanted. DATA also ignored the issue of inflation, which has affected projects built by incumbent utilities as well, it said.

Xcel’s Minnesota Energy Connection has more than doubled from the company’s initial estimate to $1.14 billion, and Ameren’s 345-kV Pana-Mt. Zion-Kansas-Sugar Creek line saw its costs grow by 44% from its initial development, ETCC said.

“Critically, because these projects were not competitively awarded and were instead developed without any cost containment, customers absorb these project cost overruns through formula transmission rates,” ETCC said. “Cost overruns are common among incumbent utility projects.”

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CEC-Stanford Energy Summit Calls for Equity in Energy Transition

PALO ALTO, Calif. — Communities historically excluded from decisions around energy use must be given a much greater role in the transition to a cleaner energy system, according to academics, researchers and power industry officials at the California Energy Commission-Stanford Energy Innovation Summit held Jan. 29-30.  

Summit panels centered on the kickoff of a CEC-led initiative, in collaboration with Stanford University and other research partners, called the Equitable, Affordable and Resilient Nationwide Energy System Transition — or EARNEST. The new university consortium is funded by the U.S. Department of Energy and designed to link university researchers with local and federal efforts to decarbonize the grid over the next five years.  

While panels covered a variety of topics, including state regulatory challenges, university and government partnerships, and solutions for remote grids, there was consensus among participating researchers and industry officials on the need for a more equitable transition drawing on the knowledge and perspectives of traditionally underrepresented communities in the U.S., such as tribes and other communities of color.  

“The people who will define what happens in the next half-decade are the communities that are the bellwethers and the guides for their partner institutions, funded through the Department of Energy’s consortium, to try to look for the pathways to an equitable and affordable, resilient, nationwide energy system transition,” said Holmes Hummel, managing director of Energy Equity and Just Transitions at Stanford’s Precourt Institute for Energy.  

Wind Power in Rural Alaska

One such community was represented by Chad Nordlum, energy project manager for the Native Village of Kotzebue, a remote city in Alaska’s Northwest Arctic Borough, who spoke during a panel titled “Co-creation of Knowledge of Traditionally Underrepresented Communities.”  

Kotzebue has spearheaded renewable energy development for the last 25 years, installing some of the first utility-scale wind turbines in 1997. Tribal communities in Alaska and throughout the nation often rely on diesel generation for power, and wind energy in Kotzebue displaces between 250,000 and 300,000 gallons of diesel fuel each year — around 20% of the city’s annual power needs.  

In 2020, the Kotzebue Electric Association (KEA) installed 532 kW of solar power, adding to its goal of producing 50% of the community’s energy from renewable sources over the following five years. KEA is planning for another 500-650 kW of solar and is seeking $2 million to fund the project. To meet its goal, KEA needs to upgrade and expand its system, but tribal nations and other underrepresented communities often lack access to the resources needed to do so, according to Nordlum.  

“I don’t think the rollout of renewable energy has been done in an equitable way so far. It’s all based on competitive grants [and] organizations like my tribe … have few capacities to hire grant writers, to hire engineers,” he said. “I think it could be done in a much more equitable way than it’s been done so far.”  

Holmes added that the difference in resource capacity between research institutions like Stanford and the communities they seek to partner with represents a stark inequity.  

Michael Wara, director of the Climate and Energy Policy Program at Stanford’s Woods Institute for the Environment, agreed, saying it’s important for research institutions to “show up” with resources that allow desired partners to participate.  

“Our philosophy has been to try to bring resources to the organizations that we really want to partner with, and that’s a value I would really recommend,” Wara said. “Think creatively about how to bring more to the table than you ask for.”  

Inequity in Energy Access

A 2022 report by the Building Energy, Equity and Power Coalition, a group of California-based nonprofits and environmental justice organizations, highlighted that low-income communities of color are often excluded from policy and decision-making around decarbonization. They typically lack information on major projects and developments, have low representation in the workforce and face major cost barriers.  

EARNEST is in many ways a listening project designed to engage the communities facing those barriers by seeking to meet people where they are.  

“In the electric utility industry, the culture of innovation and inclusion could use more help,” said Gene Rodrigues, assistant secretary for electricity at DOE’s Office of Electricity. “It’s not really all about policies, programs, technology and operations; it’s about people.”  

Even as the energy sector attempts to reduce reliance on fossil fuels, some renewable resources still depend on a culture of extraction that most often impacts the low-income communities of color that have made disproportionately lower contributions to the climate crisis, said Mari Rose Taruc, energy justice director with the California Environmental Justice Alliance.  

“An extractive economy or approach comes in many ways,” she said. “Are you trying to extract our time and energy to be partners with you? Are you extracting our labor to install these energy systems? Are you extracting from the earth? And what are you giving back?”  

As an example, Taruc pointed to a lawsuit recently filed by the nonprofit Comite Civico del Valle to overturn approval of the Salton Sea lithium mining project, claiming it lacked proper environmental review and consideration of potential harm to nearby residents who suffer elevated rates of asthma and heart disease.  

If impacted communities aren’t properly engaged, she said, projects will likely run into these types of delays.  

Alice Reynolds, president of the California Public Utilities Commission, also noted the cost barrier to accessing renewable energy — and energy at all, for that matter.  

“We’re at a point where rates are unsustainable for people. We have about 30% of our customers within the territories of the utilities that we regulate who are on low-income programs,” she said. “We need to think about providing services to everyone.”  

Moving Forward

Despite the ever-growing need to rapidly decarbonize and electrify the grid, local communities can’t be “run over” in the process, Wara said.  

“If we’re going to actually solve the climate crisis, we need to build a bunch of stuff, and we can’t build it in the way we built it in the 1960s on the back of structural racism,” he said. “The questions that the communities have is the essential start for good work to be done.”

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Algonquin, Residents Make Final Arguments in Weymouth Hearing

The attorneys representing the Massachusetts Department of Environmental Protection, Enbridge subsidiary Algonquin Gas Transmission and a group of 10 residents presented their final arguments in a department adjudicatory proceeding Jan. 31 over the waterways license of the company’s embattled natural gas compressor station in the city of Weymouth.

The hearing is the latest in the ongoing saga over the Weymouth compressor station. Algonquin submitted its application for the at-issue waterways license in 2015. It was approved in 2019 but was later sent back to MassDEP following a court appeal.

The compressor station was constructed as part of Enbridge’s Atlantic Bridge Project, aimed at increasing the south-to-north capacity of the Algonquin and Maritimes & Northeast pipeline systems. FERC gave the facility final approval in 2020 (CP16-9), and it began operations in 2021.

While state officials and lawmakers frequently speak of the importance of environmental justice, the residents opposing the compressor station have cast the ongoing proceedings as a key litmus test for Gov. Maura Healey’s administration. It was sited close to industrial facilities, including fuel storage tanks, two gas plants, a chemical manufacturing facility and the largest hazardous waste disposal site in New England; residents of the surrounding area have long argued that their community already hosts more than its fair share of polluting infrastructure.

The focus of the Jan. 31 hearing was whether the station meets the definition of an “ancillary facility” to a section of the Algonquin system known as the “HubLine” and therefore requires an adjacent location. The HubLine runs beneath the Fore River, Boston Harbor and Massachusetts Bay to connect with the Maritimes & Northeast system, which heads north to Nova Scotia.

Attorneys for Algonquin and MassDEP argued that the station requires an adjacent location and was therefore correctly sited at its existing location, while the attorney representing residents argued against the need for an adjacent location.

Nicholas Cramb, the attorney representing Algonquin, said siting the station at its existing location limited the waterways impacts compared to all alternative locations, which would have required suction and discharge pipes with additional waterways impacts.

Cramb’s position was supported by David Bragg, senior counsel for MassDEP, who said the department “determined that the location at the site — already in industrial use, already part of the infrastructure crossing facility, without the need to disturb a square foot of jurisdictional tidelands in another area — … was the appropriate location, and that it was required to be there.”

Michael Hayden, the attorney representing the residents, made the case that the compressor station did not require an adjacent location to the HubLine because the line simply does not need it to operate. He emphasized that the HubLine operated without the station for more than a decade.

“The gas is not being pushed through the compressor station for local distribution. This is going to Canada; it’s going to Maine,” Hayden said, adding that the station provides “no discernible benefit to our Massachusetts residents.”

Final oral arguments for the waterways remand proceeding | MassDEP

Cramb responded that the petitioner’s argument that the line can send gas north to south without the station is “irrelevant.”

Without the compressor, the relevant portion of the gas system cannot move enough gas “to satisfy the purposes of the Atlantic Bridge Project and Algonquin’s contracts,” Cramb said. He called the assertion that the station provides no benefits to Massachusetts residents “absolutely a false statement,” noting that one of Algonquin’s customers is a power plant in Salem.

Hayden also made the case that, because the station remains under review by MassDEP, it should be subject to the environmental justice provisions of the state’s 2021 “Next Generation Roadmap” law on climate policy.

The law requires an environmental impact report (EIR) for projects likely to cause environmental damage located in or near state-designated environmental justice communities. Hayden argued that the law dictates that the EIR could be triggered “at any stage of the review process.”

Hayden also noted that the station is located within 1 mile of multiple environmental justice communities. A 2019 state health assessment found that nearby residents face higher risks of health conditions linked to air pollution, including lung cancer, heart attacks, heart disease and pediatric asthma. Hayden has argued that gas released from the compressor poses an added threat to the community.

Hayden requested that the MassDEP Office of Appeals and Dispute Resolution (OADR) “remand this entire application and project back to the department to complete the environmental justice review that’s required under the 2021 climate act.”

Cramb and Bragg both argued that the EIR requirement does not apply to the station because the 2021 law was intended to apply only to new projects, whereas the waterways application was filed in 2015.

In its pre-filed closing brief, Algonquin added that “it is clear that [the law] does not require that Algonquin file an EIR for the compressor station because the compressor station is not subject to [Massachusetts Environmental Policy Act] review.”

Following the conclusion of the final arguments on Jan. 31, Chief Presiding Officer Salvatore Giorlandino of the MassDEP OADR will make a recommended final decision to DEP Commissioner Bonnie Heiple.

Heiple, who was appointed by Healey in March, will then be tasked with making the final decision on the proceeding.

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Western Market Seams Issues to Differ from East, Study Finds

A new study finds that the seams dividing CAISO’s Extended Day-Ahead Market (EDAM) from SPP’s Markets+ in the West would pose a different set of problems than challenges seen at the boundaries of full RTOs in other parts of the U.S. 

The Seams Evaluation study was commissioned by the Western Power Trading Forum (WPTF) and Public Generating Pool (PGP) and prepared by Energy Strategies and Gridwell Consulting.  

The study seeks “to provide a framework for understanding the key seams areas and seams issues that may exist between the two proposed day-ahead markets in the West,” while not taking a position on whether the region should have one or two day-ahead markets. 

The authors also said they did not intend “to propose specific solutions to seams issues” or provide a comprehensive assessment of all potential issues. 

The study lays out how the two day-ahead markets proposed for the West are “fundamentally different” from RTOs in the East.  

Those differences include the fact that, unlike the day-ahead markets, the RTOs feature the consolidation of balancing authorities and full participation of entities within the BAs; fully coordinated resource adequacy; and consolidation of transmission planning and generator interconnection to the grid. 

The day-ahead markets also would lack full co-optimization of energy deliveries and ancillary services and would require consolidation of open-access transmission tariffs to completely optimize use of transmission.  

Seams Within Seams

A key challenge Western day-ahead markets likely would share with Eastern RTOs is the issue of “economic” seams, which arise when boundaries between markets hinder the most cost-effective dispatch of energy across the grid and prevent operators from managing transmission congestion to the greatest extent possible. 

To mitigate the impact of economic seams, neighboring RTOs use interface pricing to help facilitate energy flows between them in both the day-ahead and real-time market. The study points out that RTOs also address their boundaries with additional tools, such as interchange scheduling, day-ahead firm flow entitlement exchange, coordinated transaction scheduling and market-to-market coordination. 

“While the West should be able to build on these concepts, these tools are currently untested under the non-RTO day-ahead market frameworks and may not translate directly given the seams within the day-ahead markets,” the study says. 

The authors note that the mechanisms RTOs use to manage economic seams are the result of negotiations, agreements and joint design efforts among stakeholders from both markets. 

“Additionally, given the nature of day-ahead markets, we expect that there will be more parties and/or more seams agreements required (including between BAs and Market Operators) than is seen in the context of Eastern RTOs,” the study says. 

The study also delves into the challenges likely presented by seams within Western day-ahead markets as well as between them. Key among them is that both EDAM and Markets+ lack mechanisms for co-optimizing awards for ancillary services with day-ahead energy, although the study acknowledges that could change in the future.  

Another internal seam stems from the fact that both day-ahead markets as proposed will allow their BAs to continue to use existing constraints to ensure that market participation doesn’t compromise their reliability obligations, effectively allowing for voluntary participation in the markets. 

“This may affect the extent to which BAs rely on the market for imports and commit units within their own footprint, which can reduce overall benefits through lack of full optimization of the fleet,” the study finds. 

Another key internal barrier will be the lack of a common resource adequacy framework. Participants in both EDAM and Markets+ will have the option of either joining the Western Power Pool’s Western Resource Adequacy Program or not committing to any RA program at all, while California utilities will continue to be subject to that state’s RA requirements. 

“Given the lack of a consistent RA and full [must-offer obligation], other mechanisms must be designed to address sufficiency of resources by individual market participants or BAs in a day-ahead market,” the study says. 

Western Challenges

The study also explores potential seams issues specific to day-ahead markets in the West, including increased barriers to contracting for resources, with the boundary between the markets possibly introducing new complexities to contracts, raising costs and increasing risks around deliveries. 

Greenhouse gas accounting and dispatch inefficiencies would represent another key barrier between the two markets, according to the study. These would “result from the absence of a single day-ahead market to produce coordinated GHG pricing signals and establishment of similar treatment to all imports into GHG-regulated areas, even under linked carbon pricing programs,” the study says. California and Washington currently operate under separate GHG cap-and-trade programs, but efforts are underway to link them within the next couple of years. 

Different approaches to market power mitigation could create yet another type of seam between Western markets, the study finds. The authors point to the increased potential for “higher instances of uncompetitive conditions due to optimizing over two smaller footprints as opposed to one larger footprint.”  

They also caution that Markets+ is in the process of developing a balancing authority area-level mitigation system that could differ from what CAISO already has in place for the Western Energy Imbalance Market. 

“Creation of two ways to address system/BAA-level market power mitigation will naturally result in areas being exposed to differing levels of over- and/or undermitigation,” the study said, noting that the differences could result in differing levels of contracting for resource among the markets. 

The WPTF/PGP study should contribute to discussions about day-ahead market seams already taking shape in the West. At a recent meeting of the Markets+ Participants Executive Committee, supporters of both markets spoke about the need to begin addressing the reality of a divided region. (See SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)  

WPTF and PGP will host a webinar to discuss the seams study Feb. 6.  

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ERCOT Technical Advisory Committee Briefs: Jan. 24, 2024

ERCOT stakeholders last month moved closer to taking action on a tabled rule change that would address the reliability concerns with inverter-based resources (IBRs).

Staff told the Technical Advisory Committee during its Jan. 24 meeting that the prevalence of IBRs on the system has increased the likelihood of potential instability issues, such as the recent Odessa disturbances. They said the issues are only going to increase along with the continued growth of solar and wind resources. (See NERC Repeats IBR Warnings After Second Odessa Event.)

ERCOT says the Nodal Operating Guide revision request (NOGRR245) would improve the clarity and specificity of IBRs’ voltage ride-through requirements. The NOGRR would align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid.

FERC also recently issued Order 901, directing NERC to address same risks NOGRR245 takes on.

ERCOT has recommended that TAC approve the change with recent comments it filed. It said a recommended proposal by the committee’s Reliability and Operations Subcommittee is not acceptable, as it does not address the current “significant reliability risk.”

Staff have made several changes to the proposed NOGRR to allow for additional exceptions for documented technical limits. IBRs must:

    • meet existing requirements and “substantially” meet new requirements, with each plant’s documented technical limit level becoming the requirement for that plant;
    • maximize capability through software upgrades and minor hardware upgrade kits;
    • accurately represent technical limits in all provided models; and
    • meet the latest requirements upon repowering, retrofitting or reinvestment.

They also cannot create any instability, uncontrolled separation or cascading outages for the ERCOT grid.

TAC agreed to resume discussion of the NOGRR at its next meeting, which it rescheduled from Feb. 27 to Feb. 14. The virtual meeting is designed to give stakeholders an opportunity to endorse a recommendation for the Board of Directors’ Feb. 26-27 meetings.

RUC Use Down Sharply

ERCOT saw a “significant” decrease in reliability unit commitments (RUCs) last year compared to the previous two years, staff told stakeholders.

The grid operator had 2,726 instructed resource-hours resulting in 2,500.6 effective hours. In 2022, ERCOT saw 8,244.8 instructed resource-hours and 7,910.5 effective hours; in 2021, effective resource-hours came in at 3,853.1. (See “RUCs Continue to Increase,” ERCOT Technical Advisory Committee Briefs: Jan. 24, 2023.)

ERCOT bought back 509.5 effective resource-hours, a 20.4% rate that matched 2022’s buy-back.

Ryan King, manager of market design, said changes in resource owners’ real-time price expectations and higher demand were among the factors contributing to RUCs’ reduction. While reluctant to identify specific causes for the decrease, he admitted the deployment of ERCOT contingency reserve service in June and higher ancillary service requirements since the 2021 winter storm may have played a role.

“Some of these factors might have been present all the time, and all of these might have been present some of the time, but I’m not sure that we have a really definitive cause and effect,” King told TAC.

He said ERCOT will continue to monitor and report on factors contributing to commitment changes.

The grid operator incurred $3.67 million in RUC make-whole payments, almost exclusively covered through capacity-short charges, last year, along with $3.45 million in claw-back charges.

ADERs now up to 9

Dave Maggio, ERCOT’s market design and analytics principal, said seven aggregated distributed energy resources (ADERs) have been approved to go through the qualification and validation process of commercial operations.

They will join two ADERs that have already qualified to participate in the wholesale electric market; they are providing 9.4 MW of energy and 3.1 MW of non-spinning reserve service since their participation following the first phase of a virtual power plant (VPP) pilot project. (See “2 VPPs Qualified for Market Participation After Pilot Project’s 1st Year,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

The ADERs will participate in the second phase of the VPP pilot. They will be limited to an 80-MW cap for energy and 40 MW for non-spin.

Data related to the ADERs’ market participation have been “somewhat limited,” Maggio said, but it has still been enough to propose incremental changes for the second phase. Staff plan to present a Phase 1 report and a draft of the Phase 2 governing document to the board and its Reliability and Markets Committee this month.

Jupiter’s Smith Elected TAC Chair

TAC members elected Jupiter Power’s Caitlin Smith as its chair for the next two years, elevating her from vice chair, the position she’s held the past two years. They also elected Oncor’s Collin Martin as vice chair. There were no other candidates.

Caitlin Smith, Jupiter Power | ERCOT

Members also confirmed the leadership of its subcommittees and sub-groups after elections were held within the stakeholder groups last year:

    • Protocol Revision Subcommittee: Diana Coleman, CPS Energy, chair; Andy Nguyen, Constellation Energy Generation, vice chair.
    • Retail Market Subcommittee: John Schatz, Luminant, chair; Debbie McKeever, Oncor, vice chair.
    • Reliability and Operations Subcommittee (ROS): Alexandra Miller, EDF Renewables North America, vice chair.
    • Wholesale Market Subcommittee: Eric Blakey, Pedernales Electric Cooperative, chair; Jim Lee, CenterPoint Energy, vice chair.
    • Credit Finance Sub-group: Brenden Sager, Austin Energy, chair; Loretto Martin, Reliant Energy Retail Services, vice chair.

Katie Rich was elected as the ROS chair when she was with Golden Spread Electric Cooperative, but she has since changed jobs. A new election will be held at the subcommittee’s next meeting.

Tier 1 Project Endorsed

TAC’s unanimously approved combination ballot included a Tier 1 transmission project that will go to the board for approval. ERCOT labels projects costing more than $100 million and requiring the directors’ approval as Tier 1.

Texas-New Mexico Power submitted the Pecos County Improvement Project last year to ERCOT’s Regional Planning Group for its review. The RPG studied nine options before settling on its recommendation to address the reliability need under maintenance outage conditions near Fort Stockton in the Far West weather zone.

The project consists of about 55 miles of new and rebuilt 138-kV transmission lines and a new substation. It has a capital cost of $114.8 million, with the upgrades expected to be completed by August 2026.

The combo ballot included seven nodal protocol revision requests (NPRRs), single changes to the Planning (PGRR) and Retail Market (RMGRR) guides, and a system change request (SCR) that, if approved by the board and the PUC, would:

    • NPRR1170: define when a qualified scheduling entity (QSE) representing a resource that relies on natural gas as its primary fuel source should notify ERCOT about gas supply disruptions.
    • NPRR1179: ensure that QSEs representing resources with an executed and enforceable transportation contract procure fuel economically and file a settlement dispute to recover their actual fuel costs incurred when instructed to operate because of an RUC. This change would also adjust the RUC guarantee to reflect the cost difference between the actual fuel consumed during the RUC-committed intervals and the fuel burn calculated based on verifiable cost parameters and would clarify that fuel costs may also include penalties for fuel delivery outside of RUC-committed intervals.
    • NPRR1195: assign ERCOT-polled settlement metering facilities’ maintenance and repair responsibilities to the facilities’ owner if it is not a transmission and/or distribution service provider (TDSP).
    • NPRR1206: clarify the QSEs required to have a hotline and a 24/7 control or operations center, and reconcile the deadline by which QSEs representing resource entities that own or control resources must provide notice that they are terminating their representation and the deadline that resource entities owning or controlling resources to change QSEs with a 45-day timeline.
    • NPRR1207: permit the incidental disclosure of protected information and ERCOT critical energy infrastructure information (ECEII) during a tour or overlook viewing of the ERCOT control room provided to eligible persons who have signed nondisclosure agreements and complied with screening and other requirements before accessing the control room.
    • NPRR1208: create a new daily ERCOT invoice report listing invoices issued for the current day and day prior at a counter-party level.
    • NPRR1211: incorporate the other binding document “Methodology for Setting Maximum Shadow Prices for Network and Power Balance Constraints” into the protocols.
    • PGRR109: require interconnecting entities associated with IBRs to undergo a dynamic model review process before the commissioning date and mandate that resource entities owning or controlling operational IBRs undergo a review process before changing settings or equipment that could affect electrical performance and necessitate dynamic model updates.
    • RMGRR179: add a communication method so TDSPs can use Texas standard electronic transactions to inform retail electric providers of record which electric service identifiers are affected by a TDSP’s mobile generation or temporary emergency electric energy facility deployment.
    • SCR825: modify ERCOT’s current control room voice communication configuration(s) to give QSEs and their subordinate QSEs greater flexibility when assigning agent(s), including allowing sub QSEs to assign agents different from those used by the parent QSE.
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Deflated New York OSW Portfolio Positioned to Start Regrowth

The few details released on New York’s potential next wave of offshore wind projects indicate continued efforts to expand the human and industrial infrastructure critical to offshore development. 

They also indicate a 28% shrinkage: Contracts for all four projects that previously were contracted by the state have been or will be cancelled. They had a combined 4,230 MW of capacity, but the three proposals submitted by the Jan. 25 deadline would be a maximum of 3,034 MW. 

Three gigawatts is a respectable figure, given the struggles the offshore wind industry experiences as it establishes itself in the United States. (Four other Northeast states have seen contract cancellations in the past year.) 

And New York is in advanced negotiations for three other projects it awarded provisional contracts in October 2023 — their total capacity is 4,032 MW. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) Final contract execution may come as soon as this quarter. 

If they all come to pass, these six projects would total 7 GW, and get the state most of the way to its 2035 goal of 9 GW.  

Beyond that, developers cancelled New York contracts for two other projects totaling 2,470 MW. But they did not cancel the projects themselves — they could be rebid into a future solicitation, though not necessarily New York’s. 

The three proposals submitted to the New York State Energy Research and Development Authority on Jan. 25 were Community Offshore Wind 2, Empire Wind 1 and Sunrise Wind.  

The names are familiar: Empire and Sunrise hold contracts that still officially are in effect but will be cancelled regardless of whether the projects win new contracts. And Community Offshore Wind 1 was one of the provisional contract awardees in October. 

Equinor and Ørsted both are moving to terminate their joint ventures and proceed solo on Empire and Sunrise, respectively. (See Offshore Wind Reset Complete in New York.) 

Both are mature plans with many regulatory and logistical hurdles already cleared, giving them a yearslong head start over newer proposals in a region of the state predicted to be at growing risk of capacity shortfalls as soon as 2025.  

The proposals submitted Jan. 25 illustrate the long timelines at play: Community’s projected commercial operations date is not until 2031. Sunrise projects commercial operations in 2030 if it is built to be ready for a meshed offshore transmission system, or 2026 if it is not meshed-ready. Empire also projects power generation starting in 2026. 

Most other details are redacted in the public versions of their supporting documentation. 

Equinor and Ørsted have continued actively moving the projects forward since declaring in June 2023 that the existing contracts were untenable without more money from the state, and since the state in October 2023 said no more money would be forthcoming. (See OSW Developers Seeking More Money from New York and New York Rejects Inflation Adjustment for Renewable Projects.) 

The latest update: On Feb. 1, Equinor announced New York City had approved its design for an offshore wind operations and maintenance building at the South Brooklyn Marine Terminal, a 73-acre facility the company envisions as an onshore hub for offshore construction and operations — both for itself and other developers. 

Ørsted, meanwhile, continues preparatory work for the onshore electrical infrastructure upgrades Sunrise would need. It plans to set up an operations and maintenance hub on the north shore of Long Island as part of the Sunrise project and open it in the third quarter of 2024. 

Community Offshore Wind is a collaboration by RWE and National Grid Ventures. In the summary of their proposal, they said they have made allowances for the economic risks and supply chain uncertainties that have bedeviled offshore wind developers since late 2022. The Community projects are designed with the flexibility needed to overcome these challenges, they added. 

Additionally, Community proposes nearly $50 million in workforce and supply chain investments; Equinor has been funding the Offshore Wind Innovation Hub; and Ørsted has funded the National Offshore Wind Training Center. 

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FERC Orders Change to MISO Order 2222 Compliance Plan

FERC ordered an after-the-fact addendum to MISO’s Order 2222 compliance plan this week after being alerted to an inconsistency by WPPI Energy.

The commission said MISO must revise its plan by May 10 to require aggregators of distributed energy resources to retain performance data of individual DERs and provide it to RTOs upon request for auditing purposes (ER22-1640).

FERC agreed with WPPI Energy that it overlooked MISO’s missing data requirement — which is required by Order 2222 — when it first issued an order on MISO’s plan in October. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

The commission said while a section in MISO’s tariff states it has the right to audit data provided by the aggregator, including information related to the metering of individual DERs, MISO did not include a requirement that aggregators retain individual DER meter data.

WPPI Energy argued that FERC erred when accepting MISO’s compliance filing because it didn’t explicitly spell out the data preservation requirement.

MISO, meanwhile, continues to work with its stakeholders on other Order 2222 directives FERC ordered in October. Those include deciding whether the grid operator can handle aggregations that span multiple pricing nodes; coming up with a go-live date that’s sooner than 2030; setting up a dispute resolution process; and establishing cybersecurity and customer data privacy protections for meter data management. (See Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP.)

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ICC Staff Demurs on Decision over Ameren’s MISO Membership

Illinois Commerce Commission staff have passed on recommending that Ameren and two smaller Zone 4 utilities depart MISO for PJM. 

ICC staff issued a final report Jan. 25 on the notice of inquiry they opened last year after the ICC directed Ameren to study the cost-benefits of leaving MISO and joining PJM. Ameren commissioned Charles River Associates, which found it would cost southern Illinois customers about $3.4 billion from 2025 to 2034 for Ameren to disentangle itself from MISO and join PJM. The study considered energy trade benefits, transmission expansion to tap into PJM, RTO costs and exit and entry fees to switch grid operators.

In comments on the study last year, ICC staff said PJM’s true capacity market style could be a better match for Ameren than MISO’s residual capacity auctions. They also said that a continued home in MISO could be fraught with resource adequacy risks when compared to PJM because MISO is poised to add more solar power and energy storage. (See ICC Staff: More to Consider in Possible Ameren Illinois Exit from MISO.) 

Ultimately, ICC staff said that although they combed through comments on how the study methodology and inputs could be tweaked to show greater future benefits of PJM membership, “it is not clear that implementing such changes would change the conclusion from the Ameren report that Zone 4 joining PJM would result in incremental net costs for [Ameren], ComEd and the State of Illinois overall.”

Staff said they weren’t recommending the commission “take any specific action” to change Ameren’s — and possibly by extension, City Water Light and Power and Southern Illinois Power Cooperative’s — RTO membership.

However, staff added it might be worthwhile for the commission to re-evaluate Ameren’s status as a MISO member in the future. 

“ICC staff notes that the information submitted in this proceeding suggests that assessing the net benefits of [Ameren’s] MISO membership is not a static assessment and will change over time. As a consequence, ICC staff further recommends the commission leave open the possibility of further analyses should future circumstances warrant them,” they wrote.

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FERC Approves 1st PJM Proposal out of CIFP

FERC on Jan. 30 approved a PJM proposal to rework several areas of its capacity market centered around aligning how resources’ capacity contributions match up to system risk analysis (ER24-99). 

The order greenlights PJM’s proposal to accredit all resources, except energy efficiency, using a marginal effective load-carrying capability (ELCC) framework and use the hourly probabilistic modeling at the heart of ELCC to calculate the RTO’s capacity needs through the Reserve Requirement Study (RRS). It also adds additional generation capability testing requirements to assess whether generators can meet their capacity performance obligations and whether resources that have not started for a month are able to properly synchronize to the grid and operate according to their parameters. (See PJM Files Capacity Market Revamp with FERC.) 

The proposal is one of two that the RTO filed following last year’s Critical Issue Fast Path (CIFP) process. The other (ER24-98) carries a Feb. 6 deadline for action on proposed changes to PJM’s market seller offer cap. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.) 

FERC said that the new approach would allow PJM to capture how resources may perform during a wider range of system conditions, namely the sort of correlated outages experienced during extreme winter weather and the diminishing reliability benefit of “highly correlated resources such as solar and short-duration storage.” 

“PJM’s marginal ELCC capacity accreditation framework reasonably values resources’ capacity based on their expected incremental contribution to resource adequacy across reasonably anticipated load, weather and resource availability scenarios given the expected resource mix,” the commission said. “We find that PJM’s proposal will allow its markets to better value the ability of individual resources to address tight system conditions and emergencies, as well as resource adequacy challenges associated with correlated resource outages and an evolving resource mix.” 

While several protests took issue with the marginal ELCC approach, arguing that it relies on an assumed resource mix before generators have cleared the auction, the commission stated that such ex ante analysis has always been part of the Reliability Pricing Model, and the improvements to the accuracy of accreditation values under ELCC outweighs any disparities between the estimated and actual resource mix. 

Vistra, American Municipal Power and Ørsted argued that PJM’s explanation of how ELCC values would be calculated was vague and that additional information is needed in the tariff revisions, rather than future manual revisions.  

CIFP

PJM Board of Managers Chair Mark Takahashi | © RTO Insider LLC

The Independent Market Monitor and several generators protested PJM’s proposal to add a dual-fuel resource ELCC class, arguing that its qualification requirements are vague and unsupported, and that recognizing the reliability benefit of resources with backup fuel without also creating a new generation class for gas-fired generation with firm fuel contracts is discriminatory. 

Calpine commented that the changes were not overly complex, though it also argued that complexity should not be a reason to reject a market design. It compared the use of loss-of-load probability models to how market participants estimate future hourly energy prices. 

FERC determined that PJM’s proposal to remove generators that fail to provide dual-fuel capability after attesting that they meet the qualifications from the ELCC class, as well as the potential for referral to FERC enforcement, was adequate to address concerns that generators could claim capabilities that they could not deliver. The commission also stated that PJM had demonstrated that it could measure the reliability benefit of resources that maintain an on-site alternative fuel that can allow them to operate for two consecutive 16-hour periods, whereas the definition and benefit of a firm fuel contract remains ambiguous. 

The proposal also effectively lowers the maximum penalty generators can be assigned in a year for failing to meet their performance obligations during performance assessment intervals (PAIs). The current annual stop-loss limit is based on the net cost of new entry (CONE), which PJM stated current results in a $135,000/MW-year stop-loss limit it believes is disproportionate to the revenues a generator can receive through the capacity market. Based on the $18,250/MW-year clearing price, PJM said the stop-loss limit is 7.5 times higher than annual market revenues. 

The change to the stop-loss calculation swaps the 1.5 times net CONE component with 150% of the Base Residual Auction (BRA) clearing price. PJM said that the swap would continue to result in a maximum penalty larger than annual revenues without being overly punitive. 

The commission rejected arguments from Vistra and Constellation Energy that tying the stop-loss limit to future auction outcomes makes it difficult for market sellers to calculate the Capacity Performance quantified risk (CPQR) component of their market offers, as they would have to estimate the final clearing price in advance. It noted that market sellers already forecast several values ahead of the auction, including energy and ancillary service revenues, expected unit performance and the number of PAIs expected in the delivery year. 

PJM’s proposal also revised the deficiency charges that fixed resource requirement (FRR) entities are assessed if they fail to procure adequate capacity prior to the BRA. The RTO argued that low capacity prices have created an incentive for FRR entities to pay the deficiency charges, which are based on clearing prices, rather than meet their own reliability needs. It also implements a four-year transition period to provide additional time for FRR entities to adjust to the new ELCC accreditation and a longer lead time for capacity planning. 

Commissioner Allison Clements released a partial concurrence and dissent, stating the proposal would address growing reliability risk that does not correspond with meeting peak loads. But she argued that the commission erred in rejecting a protest from the Advanced Energy Management Alliance and clean energy associations that the changes to accreditation and the RRS render the demand response performance window unjust and unreasonable.  

Clements wrote that the commission should initiate a show-cause order to examine the “clear mismatch between PJM’s existing demand resource availability window and its new understanding of system risk. PJM should be required to either adjust the availability window to reflect its new understanding of risk, or else demonstrate why its proposed changes have not rendered the current availability window unjust and unreasonable or unduly discriminatory.”