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December 24, 2024

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PJM MRC/MC Briefs: Dec. 18, 2024

MARKETS AND RELIABILITY COMMITTEE

Stakeholders Endorse Changes to Accounting of Demand Response in Load Forecasts

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation a quick fix proposal to account for errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast. (See “First Read on Quick Fix for Revising Load Drop Estimate Inputs,” PJM MRC/MC Briefs: Nov. 21, 2024.) 

PJM’s Andrew Gledhill explained that when PJM incorporates hourly load data in the forecast, it produces estimated load drops that intend to determine what load would have been if not for load management deployments. In some instances, however, emergency conditions may be initiated at times when consumers participating in DR programs already have reduced demand. 

He gave the example of the December 2022 Winter Storm Elliott, which saw several blocks of performance assessment intervals (PAIs) declared around Christmas — including during night-time hours — when industrial and commercial DR customers were operating at reduced capacity independent of grid conditions. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

The revisions to Manual 19: Load Forecasting and Analysis, modify two paragraphs to grant PJM flexibility in identifying when the standard load drop estimates may be inaccurate and to apply alternatives. The language also would clarify how the estimates are used in producing the annual forecasts. 

Several stakeholders argued the language was overly broad and more detail would be needed on what methodologies PJM would use and transparency for stakeholders on when they are invoked. Gledhill said there is no one-size-fits-all and PJM prefers to keep its options open-ended. 

Calpine’s David “Scarp” Scarpignato and Gabel’s Rebecca Stadelmeyer offered amendments to the language that would direct PJM to present stakeholders with information should it use the discretion the revisions would offer. Gledhill accepted such an amendment.

Vote on Site Control Requirements Deferred

Stakeholders voted to delay action on revisions to Manual 14H: New Service Requests Cycle Process, which would codify PJM’s interpretation of the site control rules for planned resources in the interconnection queue. Several developers have called PJM’s interpretation overly strict and argued it would require them to retain unnecessary land. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

EDF Renewables Director of Transmission Policy Emma Nix said delaying would allow manual revisions to be informed by a complaint filed by the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United, which argues PJM’s interpretation of the site control rules in the tariff do not conform to its language and would present unnecessary development costs (EL25-22). Nix motioned to have the item removed from the MRC’s consent agenda. 

PJM’s Jason Shoemaker said the application window for Transition Cycle 2 closed Dec. 17 and staff seeks to implement the language quickly to provide developers with clarity on the rules. He added that the vote would not be an end to the RTO’s ongoing conversations with developers on site control requirements. 

“These developers need to have some understanding of how their projects are going to be moved through the process,” he said. “We’d like to see the vote go forward today because it does impact our developers today.” 

The revisions would allow parcels to be removed from a project so long as it continues to meet the minimum acreage and energy output listed in the project application. Land could be added to a project at Decision Point 1 so long as either it is adjacent to the site, or evidence of easements is provided. If the energy output is reduced, the land requirements also correspondingly would go down. 

The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 to specify that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels can be added similarly to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle. 

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement (NSA) to determine permissibility. 

The revisions also would correct Exhibit 10 in the manual, which inadvertently used a diagram from another exhibit when describing how generators interconnect to existing transmission substations.

Discussions on CETL Shifted to ELCC Task Force

The committee endorsed a change to an issue charge to charge the newly formed Effective Load Carrying Capability Senior Task Force (ELCC STF) with addressing a “disconnect” between PJM’s winter-focused accreditation and the use of summer peaks when calculating zonal capacity emergency transfer limits (CETL). (See “Stakeholders Endorse LS Power Issue Charge on CETL,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

Endorsed by the Planning Committee on Nov. 6, the issue charge originally assigned the work to the PC. But ELCC STF Chair Michele Greening said PJM staff found there is a lot of synergy between the CETL discussions and the other two topics the task force is addressing, both on substance and timelines. 

The task force also is in the early phases of working on issue charges addressing the transparency of the ELCC model and how it is used to determine resource accreditation. Both were approved by the MRC during its Oct. 30 meeting. 

The revisions to the CETL issue charge also extended the work timeline to target a FERC filing in May 2025, rather than the first quarter of 2024. 

First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation

PJM’s Chantal Hendrzak presented a first read on proposed changes to PJM’s rules for deactivating resources, extending the notification they must provide PJM before they can go offline, increasing the amount of data that is posted publicly and revamping the compensation for units that enter reliability-must-run (RMR) agreements. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.) 

The tariff revisions would require generation owners to provide 12 months’ notice ahead of their desired deactivation date, in addition to the existing must-offer exception deadlines on units that would not participate in the capacity market. PJM would publish publicly the estimated RMR revenue allocation zonal rate for zones that would be affected by an RMR agreement; postings also would be expanded to include Independent Market Monitor determinations on market power, deactivation response letters and RMR agreement notifications. 

The $2 million cap on project investments that can be included in the deactivation avoidable cost rate (DACR) would be eliminated and the scaling element of the yearly adder on investments would be shifted to a static 10%. A provision that replaces the DACR with the daily deficiency rate if the DACR and multiplier are greater than the deficiency rate also would be removed. 

The proposal is one of three the Deactivation Enhancement Senior Task Force (DESTF) voted on in October, carrying 69% support and winning out over a second PJM-sponsored package with fewer changes to compensation and a proposal from the Monitor that would have limited RMR agreements to five years and required stakeholder notification of agreements at least a year in advance.

Several Manual Revisions Endorsed

PJM’s Ryan Nice presented a slate of revisions to Manual 1: Control Center and Data Exchange Requirements, expanding its backup and emergency communication modes, as well as changes drafted through the document’s periodic review. The committee is set to vote on endorsement at its Jan. 23 meeting.  

He said the AltSCADA communication process allows inter-control center communications (ICCP) links to be transmitted between PJM and transmission owners using simple spreadsheet files in the event that default SCADA software is offline, such as through a cyberattack. The changes also include an expansion of the RTO’s read-only mode that prevents ICCP data from being edited during planned maintenance windows where the risk of incorrect data being submitted is increased. 

The periodic review changes include updating definitions to be clearer and more consistent with other manuals. 

PJM’s Liem Hoang presented a set of revisions to Manual 38: Operations Planning, to include information about the Operational Planning Analysis used in the Day-ahead Market and specify that CEII access is necessary to review the analysis. The language is set to be considered by the Operating Committee on Jan. 9 and the MRC on Jan. 23, with immediate implementation if approved.  

PJM’s Susan Kenney presented a set of revisions to Manuals 27 and 29 to remove outdated references, make grammatical corrections and add a description of how the non-zone network load responsibility is assigned to network customers in Manual 27. The MRC is set to vote on the changes Jan. 23. 

MEMBERS COMMITTEE

Sector Representatives and MC Vice Chair Elected

The Members Committee voted to elect representatives to serve on the Finance Committee for its 2025 term, sector whips and named Steve Kirk of NextEra Energy Marketing to serve as MC vice chair. American Municipal Power’s Lynn Horning will be chair of the committee. 

The new sector representatives on the Finance Committee will be: Susan Bruce, of the PJM Industrial Customers Coalition, representing end use customers; Jeff Whitehead, of Eastern Generation, representing generation owners; Steve Kirk, representing other suppliers; and Laura Yovanovich, of PPL Utilities, representing transmission owners. 

The sector whips for 2025 will be: 

    • John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), for the electric distributor sector. 
    • Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), for the end use customer sector. 
    • David “Scarp” Scarpignato, of Calpine, for the generation owner sector. 
    • Sean Chang, of Shell Energy North America, for the other supplier sector. 
    • Jim Davis, of Virginia Electric & Power Co., for the transmission owner sector. 

PJM Presents Manual Language Detailing Process After FERC Rejection of Stakeholder Packages

PJM presented a first read on a proposal to revise Manual 34: PJM Stakeholder Process to establish a standardized path for PJM to follow when FERC rejects a stakeholder-endorsed proposal. The language is set to be voted on during the committee’s Jan. 23 meeting, with AMP and the Delaware Division of the Public Advocate intending to move and second the motion. 

Acting on its own accord or stakeholder request, PJM could hold a presentation within 90 days of the order on the commission’s rejection and recommend how to proceed. The proceeding discussion would include all possible stakeholder options, such as restarting the stakeholder process, identifying changes that could be made, new proposals or any other decision decided the senior standing committee agrees on. 

Greening said the manual is currently silent on how PJM and stakeholders should proceed after the commission rejects a proposal, leading to instances where there was disagreement on next steps. One such instance followed FERC denying a proposal to implement multi-schedule modeling by using a formula to select energy market offers to be entered into the Market Clearing Engine. The original proposal was rejected by the commission in March, and PJM opted to bring the alternative that received the second-highest vote count for endorsement. (See “Monitor, PJM Present Processes to Enable Multi-schedule Modeling,” PJM MRC/MC Briefs: June 27, 2024.) 

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Feds Sue PacifiCorp over 2020 Oregon Wildfire

The Department of Justice alleges that PacifiCorp’s failure to maintain its power line equipment caused the 2020 Archie Creek Fire that burned over 131,000 acres and resulted in hundreds of millions of dollars in damages to government property, according to a lawsuit filed in the U.S. District Court for Oregon on Dec. 19.

The government claims PacifiCorp did not take proper safety precautions to mitigate wildfire risks in violation of a license granted to the company by FERC, which allows the utility to operate power lines on federal land.

The U.S. Attorney’s Office seeks costs and damages associated with the fire.

The Archie Creek Fire burned for nearly eight weeks between Sept. 8, 2020, and Oct. 31, 2020. The fire consumed approximately 131,000 acres, including over 67,000 acres of federal land. The complaint does not specify how much the fire cost the government but notes costs amounted “to hundreds of millions of dollars,” according to the suit.

“During the approximately six weeks it burned, the Archie Creek Fire caused significant damage to federally owned and managed forest lands, timber, natural resources, wildlife habitat, trails, roads, bridges, campgrounds, and other infrastructure,” the government contends. “The United States incurred substantial suppression costs, reforestation and restoration costs, stabilization costs, and suffered devastating infrastructure and other damages, including without limitation ruined wildlife habitat, natural resource destruction and timber loss.”

PacifiCorp spokesperson Simon Gutierrez told RTO Insider in an email that the utility has cooperated with the government to resolve claims associated with the Archie Creek Fire.

“It is unfortunate the U.S. government decided to file a lawsuit in federal district court, however PacifiCorp will continue to work with the U.S. government to find reasonable resolution of this matter,” Gutierrez wrote.

Specifically, the suit claims PacifiCorp failed to take necessary precautions despite warnings issued by the National Weather Service about elevated fire risk dangers. The Archie Creek Fire ignited after an aluminum Ampact wedge connector melted. The government alleges the same type of connector was behind previous fires along transmission line equipment owned by PacifiCorp.

Shortly after the fire started, PacifiCorp reenergized a distribution line in a rural residential area while a tree was leaning on the line. The tree became engulfed in flames, and the fire quickly spread and merged into the Archie Creek Fire, according to the suit.

The complaint also details allegations from the Oregon Public Utilities Commission and FERC, claiming PacifiCorp “committed upwards of 250 vegetation clearance violations annually” in the years leading up to the Archie Creek Fire.

Similarly, following an investigation launched after a 2012 Utah fire, FERC claimed at least 45% of PacifiCorp’s transmission lines “were so poorly maintained or obsolete that they should not have carried any electrical current,” according to the suit. (See PacifiCorp Faces $42 Million Penalty for Line Misratings.)

The U.S. Attorney’s Office for the District of Oregon declined to comment.

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NY Well Positioned to Push Forward on Climate Goals Under Trump

President-elect Donald Trump has been an outspoken opponent of renewable energy, calling the sector “a scam” on the campaign trail and pledging to halt offshore wind energy projects.

“We are going to make sure that that ends on Day 1,” Trump said in a May speech according to the Associated Press. “I’m going to write it out in an executive order. It’s going to end on Day 1.”

A hostile administration could threaten New York’s clean energy targets under the 2019 Climate Leadership and Community Protection Act, which requires that 70% of the state’s electricity come from renewable sources by 2030. A report published by state agencies in July forecasts that New York will fall short of its goal if steps are not taken. (See NY Expects to Miss 2030 Renewable Energy Target.)

Despite this, renewable energy industry analysts, representatives and environmental advocates say the state is in a better position than many others to make progress on its renewable energy goals.

“When we’re talking about a realistic Trump presidency, the impacts to New York are really minimal,” said Lizzie Bonahoom of Aurora Energy Research.

Bonahoom clarified that “realistic” means Trump himself will not be able to claw back the provisions of the Inflation Reduction Act and repeal federal tax credits for renewables and batteries.

IRA Clawbacks and Tariffs

Amy Turner, director of the Cities Climate Law Initiative at the Columbia University Law School’s Sabin Center, broadly agrees.

The vast majority of IRA funding has already been allocated and contracted out. IRA tax credits cannot be repealed by executive action alone. Congress would need to pass targeted repeals of the law’s provisions, and with such tight partisan margins, it could not afford Republican defectors. Much of the IRA’s funding went directly to Republican-led states and congressional districts.

Even if the administration successfully repealed those tax credits, as the Heritage Foundation’s “Project 2025” has outlined, the impact would still be mitigated by the state’s renewable portfolio.

“Wind and solar are proliferating partially due to tax credits but in bigger part due to capital costs coming down,” Bonahoom said.

She said that while it is unlikely that Trump would find enough congressional support to fully repeal the IRA’s renewable tax credits, he might try to staff the IRS with people who might make the tax credits burdensome to claim by increasing administrative burden on claimants. This could increase capital costs for the sector.

The IRA’s “Buy American” provisions also had the effect of driving U.S. renewable supply chains onshore. While not everything can be produced domestically, the supply chain is a lot less weak than it used to be. Marguerite Wells, president of the Alliance for Clean Energy New York, explained that this shift, in the event of Trump-imposed trade tariffs, would reward members of the renewable industry who had moved their manufacturing back to the U.S. faster.

“If you impose a tariff with the IRA in place … that would shunt people over to the people who had been investing in local industrial capacity,” Wells said, “which was kind of the point of the IRA.”

CLCPA and Local Authority

Wells said that there was widespread sentiment in the industry that New York was still a great place to be in the renewables business.

“The CLCPA still stands, and it’s clear that from the way that state legislators were returned to office after what they’ve been doing and advocating in terms of clean energy, it’s what New Yorkers still want,” Wells said. “I think that still holds. That dictates my general hopefulness for renewables in New York.”

Even after the election, Wells said that there is an attitude of adapting and building as many renewables as possible. She said that Gov. Kathy Hochul’s recent reconsideration of congestion pricing in New York City was a hopeful signal of her willingness to take a stand on climate issues, even if they might be controversial.

“We don’t know if it’s a harbinger for more, but at least it’s a step in the right direction,” Wells said.

State Assemblymember Alex Bores (D), who represents part of Manhattan, said that he was focused on trying to get New York out of its own way when it comes to building renewables.

“A lot of red states have much quicker permitting,” Bores said. “So even if we want to do a lot of projects and get renewables online … it sometimes takes too long, and that’s not the fault of any federal administration.”

Bores said that the state needs to focus on spending the money it already allocated to renewable energy and grid upgrades, expedite permitting and unbind state entities like the New York Power Authority. He pointed to an old law that up until 2023 prevented NYPA from developing more renewable generation.

“We need to keep our own side of the street clean, make sure we are doing everything possible … and make sure we’re also not getting in our own way,” Bores said. “Because I don’t think we’re going to have the help we need from the federal government, to put it mildly.”

A large part of why New York is in a good position to continue pushing on renewables is because of the CLCPA, which was passed during the first Trump administration, said Chris Casey, an attorney for the Natural Resources Defense Council. “The strategy around decarbonizing New York’s economy is really one that’s based on traditional notions of state authority.”

Casey said states have a disproportionate level of control over the generating resources that come online and their ability to grant permits and create incentives. Those powers are only magnified when you have a single-state ISO.

“FERC has largely been supportive of allowing states to go the directions they want, and we really have opportunities to create synergies between the ISO’s markets and state policy,” Casey said. “The problems aren’t as big or intractable when you have a state with clear energy policies and an RTO with the same footprint.”

He pointed to the state’s Coordinated Grid Planning Process and the execution of Public Policy Transmission Needs as evidence of NYISO and New York working together. That’s enhanced by a cooperative federal government, but it isn’t stopped by an uncooperative one.

Casey pointed out that at the federal level, most of the IRA money had already been contracted out and that New York had not really been dependent on that money for developing most of its renewable energy portfolio.

Some of the IRA funding that has already been contracted to the state for building heat electrification is already pushing it toward some of its targets through the New York State Research and Development Authority’s incentive programs.

“Programs like NYSERDA’s are providing substantial incentives to American families, driving consumer adoption of energy-efficient systems like heat pumps,” said Max Veggeberg, CEO and founder of Tetra, a home energy services company. “This momentum would be difficult to dismantle. In fact, the new administration’s support for nuclear energy could further lower energy costs, ironically making the adoption of heat pumps an even more attractive option for New York homeowners.”

Offshore Wind

Offshore wind is a major element of New York’s energy goals and is uniquely under the purview of federal agencies. Trump has vowed to halt offshore wind development on the campaign trail. But it’s not clear how much the federal government can stop.

“We see business as usual,” said Nick Guariglia, spokesperson for the New York Offshore Wind Alliance. Guariglia explained that two projects, Sunrise Wind and Empire Wind 1, were nearing completion and were unlikely to face stoppage because they are already under construction, which means they have made it through much of the federal permitting process.

Offshore wind projects take a long time with or without a cooperative administration. Empire Wind’s lease was sold to Statoil Wind US in 2016, during the first Trump administration. The final construction plan was not approved until February 2024. Even though many projects are not as far along as having a final construction plan, they do have lease agreements, which give the developments more legal weight.

But beyond that, the offshore wind energy is broadly aligned with Trump’s stated goal of energy development and “energy independence” and “energy dominance.”

“We want to make America energy independent, and the only way to do that is to make energy right here,” Guariglia said.

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CEC Ups Data Center Demand Forecast After PG&E Revisions

The California Energy Commission has updated its energy demand forecast for data centers after receiving revised figures from Pacific Gas and Electric about data center growth.

PG&E submitted data center information to the CEC in September. But an update the utility provided this month “shows substantially more requested capacity since their [September] submission,” according to a Dec. 23 presentation to the CEC’s Demand Analysis Working Group.

Compared to projections discussed by the working group in November, PG&E’s peak data center demand in 2040 has increased by about 600 MW, to roughly 2,300 MW, under a “mid” demand scenario.

The forecast hasn’t been finalized, and the CEC is still accepting comments.

The CEC is wrapping up its 2024 California Energy Demand Forecast, of which data center demand is one component. The commission is expected to adopt the forecast at its Jan. 21 business meeting.

Once completed, the forecast is used in statewide energy planning, such as CAISO’s transmission planning process and the California Public Utilities Commission’s resource adequacy and integrated resource planning.

Heidi Javanbakht, program manager in the CEC’s Demand Analysis Branch, said CEC staff have been talking to leadership at CAISO and the California Public Utilities Commission about implications of data center demand growth.

“Planning for this potential magnitude of load growth … in the Bay Area over the next five to six years is going to require really close coordination between the agencies and the utilities,” Javanbakht said.

She also said “it’s a priority across the agencies and the ISO” to support the data center industry.

Revised Forecast Methods

In addition to incorporating new data from PG&E, the CEC’s updated data center demand forecast uses a different methodology compared with the previous forecast.

Previously, the CEC assumed all proposed data center projects would be completed. The rationale was that if one project fell through, another one would likely come along to replace it.

“However, considering the number of new applications reported by PG&E, we decided to revise the previous methodology and assume that not all projects will be completed,” said Jenny Chen, supervisor in CEC’s sector modeling unit.

Under the new methodology, which applies to PG&E and Southern California Edison (SCE), the likelihood of a data center project being completed is judged based on where it is in the planning process. The likelihood of completion is higher if engineering studies for the project are in progress or completed; lower if there’s an active application but no engineering studies; and even lower in the case of an inquiry without an application.

The change also helps address concerns that data center developers may be contacting more than one utility about a single project, which could lead to double counting.

With the new methodology, PG&E’s projected peak data center demand decreased from 2024 to 2027 compared with the CEC’s projections from November. But from 2028 to 2040, peak demand was up compared with the previous projections in both a “mid” and “high” demand scenario.

For SCE, projected data center peak demand is lower in most years with the new methodology. In 2040, peak demand is projected at just under 500 MW for the “mid” scenario, a drop of about 394 MW compared with the forecast using the previous methodology.

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SPP Briefs: Week of Dec. 16, 2024

DALLAS — SPP’s Resource and Energy Adequacy Leadership (REAL) Team closed out the year by taking two actions related to the long-term planning reserve margin (PRM). 

The team Dec. 18 unanimously approved a long-term policy paper intended as a guide for SPP staff as they continue to develop policy and additional work plans on the subject. The paper outlines the framework for establishing long-term planning horizon PRM requirements to minimize revisions to the requirements with adequate advance notice leading up to the applicable operating season. 

Team members debated whether the paper captures all the risk factors, with some urging a conversation around the possible variances that could occur. 

Natasha Henderson, SPP’s director of system planning, said she received offline feedback that the paper presents a buffer of sorts, to which she responded, “No.” 

“We are really looking at two different types of risks when we move from the long-term planning horizon to the real time in operations,” she said. “What happens if we set something five years out and things change between our assumptions and resource mix and the interaction of the resource mix and load. If something changes that meets the one-day-in-10 [reliability] standard that we were planning to, we may not have actually been planning to that. That’s the nature of risk.” 

She said other comments centered on what the right practice may be, instead of just arbitrarily increasing the PRM. 

“All that the paper is saying is that we need to understand what that risk is,” Henderson said. “The mitigations of that risk would happen later, after a lot of discussion that would include the discussion of affordability.” 

The grid operator recently won FERC approval of a 36% PRM for the winter season, effective 2026/27. It has a 16% margin for the summer season, effective 2026. (See FERC Approves SPP’s Winter RA Requirement.) 

The proposed policy paper includes edits from the Kansas Corporation Commission’s Andrew French, who described another grid operator’s process of setting the PRM as wildly inconsistent. 

“To increase planning certainty, there should be appropriate consideration of risk in setting long-term PRM requirements, so that the need for subsequent adjustments to those established requirements is minimized,” he wrote. “However, all stakeholders should recognize longer-term planning intrinsically involves more uncertainty. SPP can provide best estimates of long-term resource needs, giving [load-responsible entities] more planning information, but LREs share the obligation to plan for the future.”

The REAL Team also endorsed the Supply Adequacy Work Group’s recommendation of 2029 PRM values set at 38% for the summer and 17% for the summer. The SAWG based its recommendations on the 2024 submitted forecasts for the resource and load mix, which used SPP’s 2023 loss-of-load expectations study. 

Changes in proposed load (increased) and the resource mix (thermal increased, wind resources dropped) resulted in different PRMs for the 2029 study year. However, the RTO’s staff said they could support SAWG’s recommendation because it can evaluate 2030 in the 2025 LOLE study and set a 2030 PRM based on the long-term policy paper. 

Nickell Looks Forward as CEO

The REAL meeting came the day after SPP announced Lanny Nickell would become the grid operator’s CEO in April. That gave the team’s lead, South Dakota Public Utilities Commission Chair Kristie Fiegen, an opportunity to invite Nickell to make his first public comments to stakeholders. (See related story, SPP Names COO Nickell to Replace Sugg as CEO.) 

“One of the favorite things about my experience at SPP, and I’ve been here 27 and a half years, has been working with stakeholders. It’s just what I enjoy doing,” he said.  

Nickell added that he cares “deeply” about SPP and its success, lumping employees, members and their customers together. 

“We’ve got a lot of work ahead of us. We’ve got some very real challenges,” he said. “This is the right committee working with the SAWG, working with [state regulators] resolving those challenges, because that’s where the majority of our challenges are. I’m excited to be able to continue to work with you all to figure those things out, and I think we’re going to be successful, and I’m excited about the future.” 

Markets+ Strengthens Participant Engagement

The Interim Markets+ Independent Panel (IMIP), composed of three independent SPP board members, approved two measures Dec. 19 to provide greater cooperation between the IMIP and western state regulators and establish a policy for appeals to the RTO’s board. 

The IMIP signed off on a joint resolution formalizing an agreement with the Markets+ State Committee (MSC) to participate in each other’s meetings, with allocated time on their corresponding agendas, and to host joint in-person and/or virtual meetings to address any issues during the development and operation of Markets+. 

The MSC, a group of regulators from 13 states in the West and the Great Plains, raised the need for ongoing engagement in late 2023. The Markets+ Participant Executive Committee (MPEC) eventually handed it to the Markets+ Interim Governance Task Force (MIGTF). 

“This was kind of dumped in their lap, and they didn’t know what to do with it,” said MSC Chair Nick Myers, with the Arizona Corporation Commission. 

It took a 30-minute conversation between Myers and IMIP Chair Steve Wright to iron out the resolution. 

“This hopefully resolves any concerns that are out there about how we will work together going forward,” Wright said. 

The IMIP also approved a policy brought forward by the MIGTF and MPEC to address interactions between the Markets+ Independent Panel (MIP) and the SPP board. The policy includes a process under which the IMIP and MIP can submit appeals to the board.  

The MIP will replace the IMIP by the time Markets+ is up and running, currently targeted for early 2027. It will be allowed to appeal decisions on the same issue multiple times to the board. 

ACC’s Myers: FERC Order Close

FERC is close to filing its response to SPP’s filing to the commission’s finding that the RTO’s Markets+ tariff submittal is deficient, Myers told the MSC on Dec. 20. 

Myers, part of a recent Western Interstate Energy Board delegation to FERC’s offices in D.C., said that after discussions with staff, he’s hopeful the commission will rule on the tariff in January. SPP submitted its response to FERC’s deficiency finding in September, asking for a response by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

“I impressed upon them that the MSC really didn’t have too much opposition to that tariff, which is the reason why we didn’t necessarily file comments,” Myers said. “They were very receptive of that and thought it was great that the states were in agreement with the tariff overall. I did get … that it’s a top priority and that they’re kind of in the final stages of it.” 

Potential Competitive Upgrades

Two recently approved 345-kV transmission projects potentially meet the requirements for competitive upgrades, SPP said Dec. 16.  

The projects in question — Belfield-Maurine-New Underwood-Laramie River, from the Dakotas into Wyoming, and Elm Creek-Tobias in Nebraska — also include upgrades that don’t qualify as competitive because they interconnect to existing noncompetitive facilities. Those upgrades will receive notifications to construct with conditions (NTC-C). 

The noncompetitive upgrades will require refined cost estimates that will affect the projects’ overall status. Under SPP’s tariff, an entire project could be re-evaluated if the noncompetitive refined cost estimate is out of bandwidth and is not considered fully approved for construction. 

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Texas PUC Shelves PCM Design Over Lack of Benefits

The Texas Public Utility Commission has shelved the market design it once favored, agreeing with staff’s recommendation that the performance credit mechanism (PCM) results in “minimal” additional resource adequacy value.

In a memo filed before the PUC’s Dec. 19 open meeting, commission chair Thomas Gleeson said he concluded the PCM, “as currently designed,” wouldn’t provide “the reliability benefits needed in the ERCOT market.” He said it would be “appropriate” to reconsider the PCM in the future,” but that the commission’s “collective resources are best directed toward implementing other market design initiatives” (55000).

“The outcome is what it is,” Gleeson said during the open meeting after gaining agreement from his fellow commissioners. “But the work was tremendous, the analysis was tremendous, and that got us to the decision that we needed to make.”

“There are variables that are in the PCM, there’s things that we can come back if later needed to learn from … and definitely something that is not thrown away, just put on the shelf,” commissioner Courtney Hjaltman said. “[Let’s] see what other things are in the market, and we can come back and learn from those things.”

The commission in August directed ERCOT and the Independent Market Monitor to complete updated assessments of the PCM’s cost to and its effects on the market. Staff reviewed those assessments before making their recommendation.

The PCM was designed to incent more gas generation by awarding thermal generators credits based on their performance during a determined number of scarcity hours. Those credits would be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

However, ERCOT’s assessment, conducted with the Energy and Environmental Economics (E3) consulting firm, found that the market would hit a $1 billion gross cost cap imposed in 2023 by the Texas Legislature every year and add only about 800 MW of dispatchable generation. It said the cap “significantly limits the effectiveness of the PCM.”

The IMM said the “novel” design would provide a new source of revenue for generators that would increase ERCOT’s capacity margin and the costs to customers but reduce shortage revenues. Eventually, the higher capacity margins would reduce the frequency of shortage pricing, with the net costs falling to $350 million to $725 million annually.

“Good riddance,” energy consultant and former PUC and FERC staffer Alison Silverstein said. She agreed with the PUC’s decision to wait on real-time co-optimization and better battery rules, targeted for implementation in December 2025, and other measures before revisiting the PCM.

The grid operator also is working on a standalone dispatchable reliability reserve service (DRRS), a non-spinning reserve service subtype as a result of a new law, and analyzing ancillary service demand curves.

“If you’re going to mess with the market, the juice should be worth the squeeze,” Silverstein told RTO Insider. “The limits on PCM make it unlikely to be an effective gas plant subsidy, so why bother?”

Doug Lewin, Stoic Energy’s founder and principal, also agreed with the PUC’s decision.

“Capacity market constructs do too little, if anything, for reliability for their massive cost,” he said. “I hope now the commission, ERCOT and stakeholders can focus on more important things and stop wasting time arguing about capacity market design.”

ERCOT spokesperson Christy Penders said in an email that while the PCM didn’t provide enough benefits to move forward for the time being, “We continue to work with stakeholders on market solutions to enhance the reliability of the Texas power grid.”

ERCOT to Pursue Braunig MRAs

ERCOT General Counsel Chad Seely told commissioners that staff expects to execute a reliability must-run agreement with San Antonio’s CPS Energy within weeks for its Braunig Unit 3 gas resource. The grid operator says the capacity is needed to address transmission reliability until several South Texas projects are completed by summer 2027. (See ERCOT Board of Directors Briefs: Dec. 2-3, 2024.)

Seely said staff are continuing discussions with CPS, CenterPoint Energy and Life Cycle Power over moving 15 large generators and their 450 MW of capacity from Houston to distribution sites in the San Antonio area. The generators, which range in size between 27 and 32 MW, would provide a less expensive alternative to the $56 million CPS says it will take to overhaul and continue running Braunig’s other two units.

The San Antonio municipality told ERCOT earlier this year it intended to retire all three 1960-era units in March 2025.

“We think technically, this is a very feasible option and will provide a better, reliable solution than moving forward with an RMR agreement for Units 1 and 2,” Seely said.

In the interest of time, ERCOT issued a request Dec. 20 seeking one or more must-run alternatives to the potential solution being negotiated.

CenterPoint Executive Vice President Jason Ryan told the PUC that if the generators are moved to San Antonio before the summer, its Houston-area customers won’t be charged for the units, and the utility won’t receive any revenue or profit from them.

“This whole time, it’s been our priority to make sure that we can bring to the table a Texas solution … and at the same time [we’re] providing that Texas-based solution, making sure that our customers see a rate reduction as a result.”

CenterPoint leased the generators for $800 million in 2021 following that year’s winter storm that nearly collapsed the ERCOT grid. The large generators turned out to be anything but mobile and when they went unused in Hurricane Beryl’s aftermath, CenterPoint came under fierce political and customer criticism.

ERCOT’s Kristi Hobbs, vice president of system planning and weatherization, said the ISO’s twice-yearly Capacity, Demand and Reserves report’s December release will be delayed into 2025 “to ensure we get it right.” A recent protocol change (NPRR1219) extends the seasonal CDR reporting to all four seasons and adds unavailable switchable generation resource capacity.

In other action, the PUC:

    • Adopted new requirements for utilities in ERCOT that lease and deploy mobile generation facilities. The rule is a result of the 87th Texas Legislature’s House Bill 2483 (53404).
    • Approved staff’s review of ERCOT’s ancillary services (AS) that was conducted with the grid operator’s staff and the Independent Market Monitor. The review found that ERCOT’s current set of AS and the future DRRS are enough to comply with NERC requirements and recommended only minor changes (55845).
    • Again tabled Entergy Texas’ proposed system resiliency plan that would implement six resiliency measures over a three-year period at a cost of $335 million. At issue is Entergy’s request for conditional approval of $198 million of projects that would become part of the plan if the utility receives grants under the Texas Energy Fund’s Outside ERCOT Grant Program (56735).
    • Rejected a joint petition by two retail advocacy groups requesting ECRS be designated as an ancillary service incurring charges beyond a retailers’ control for existing contracts executed on or before June 9, 2023 (55959).
    • Approved the final draft of its biennial agency report to the Texas Legislature. The report must be submitted by Jan. 15 (56335).

Commissioner Lori Cobos adjourned the meeting, her last as a PUC member. Cobos, the last of the three commissioners appointed in 2021 to replace the three previous incumbents following that February’s disastrous winter storm, announced her retirement in November. (See Texas PUC’s Cobos to Leave Commission.)

Cobos battled her emotions as she thanked fellow commissioners, the PUC staff and the state’s political leadership, calling her appointment the “honor of a lifetime.” Her audience included former FERC and PUC chair Pat Wood.

“I am tremendously grateful for this opportunity to have served on the PUC,” Cobos said.

Alluding to Cobos’ focus on building transmission, Hjaltman said, “We’re going to hopefully do you proud with everything and your legacy of transmission and get those projects done for you.”

Gleeson revisited his comments from Jimmy Glotfelty’s departure Dec. 12 and thanked Cobos for “all the work you did on my Permian Basin reliability project.”

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Study Calculates Trillions in Economic Benefits from IRA

A new report on the Inflation Reduction Act — issued as the IRA faces a potentially existential threat — finds that it could boost U.S. GDP by $1.9 trillion over the next decade. 

The study, commissioned by the American Clean Power Association and conducted by consulting firm ICF, said the economic benefits will extend across the energy sector and beyond, to transportation, buildings and manufacturing. 

“Economy-wide Impacts of the Inflation Reduction Act Energy Provisions” estimates that the IRA’s roughly $740 billion in tax credits will: 

    • motivate approximately $2 trillion in capital investment; 
    • spur $3.8 trillion in spending attributable to the IRA; 
    • support 13.7 million job years from 2025 to 2035; 
    • contribute to the clean energy workforce expanding from 3 million in 2022 to 6.5 million in 2032; 
    • increase Americans’ disposable income by nearly $77 billion per year; 
    • eliminate emission of 4.1 billion metric tons of carbon dioxide equivalent; and 
    • yield more than $1 trillion in emissions benefits. 

That is a 4X return on taxpayer investment, the report concludes, with additional consumer savings from lower operating costs for higher-efficiency buildings and vehicles. 

In the 28 months since the IRA was signed into law, “The clean energy tax credits have significantly increased domestic energy production, revitalizing communities across the country and lowering consumer energy bills,” American Clean Power Association CEO Jason Grumet said Dec. 19 in a news release announcing the study.  

“By supporting our nation’s diverse array of energy resources, the IRA is strengthening our national security and enhancing economic competitiveness.” 

That message directly aligns with some of the key stated priorities of President-elect Donald Trump, who has repeatedly attacked climate-protection initiatives including the IRA, a signature achievement of President Biden. 

The IRA passed without a single Republican vote, and Republicans soon will be in a position to derail the remainder of the 10-year plan. But the economic benefits so far have accrued disproportionately to Republican congressional districts, and there is widespread speculation that any attempt at large-scale cancellation or clawback by Republican leadership will encounter resistance from the rank and file. 

This gives some IRA proponents hope that any changes will be made with a scalpel rather than a chainsaw. 

Introducing the study, ICF wrote that it sought to estimate incremental economy-wide impacts from the IRA — effects beyond those attributable to state policies and clean energy activity that would have occurred without the IRA. 

It reviewed all IRA incentives in key areas: power, transportation, buildings, sustainable aviation fuel, hydrogen and manufacturing. Then it projected the incremental impacts of the IRA on each sector. 

The accounting of the models includes not just positive impacts but negative factors such as the cost of funding the IRA, cost of private sector funding and cost of displaced economic activity such as fuels. 

Supporting data include cost-benefit analyses, job creation due to investments made since 2022 and economy-wide employment impacts. 

The U.S. Chamber of Commerce, Edison Electric Institute, National Electrical Manufacturers Association, National Hydropower Association and Nuclear Energy Institute joined with American Clean Power in endorsing the findings of the report. 

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Winter of NYISO Stakeholders’ Discontent over ‘Complete’ Projects

Two initiatives that have bedeviled discussion at NYISO committees in the last few weeks of the year reared their heads again at the final Budget Priorities Working Group meeting of the year Dec. 17.  

The Operating Reserves Performance Penalty and Engaging the Demand Side projects, both of which have been harshly criticized by stakeholders, drew fire yet again. (See Stakeholders Turn down NYISO Reserve Performance Penalties and Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes.) 

The issue? NYISO staff listed these projects as “complete” for the purposes of their year-end corporate incentives, which factor into staff compensation. ISO staff are awarded bonuses for completing projects on time. Stakeholders contend that these projects were not finished. 

Mark Younger of Hudson Energy Economics was particularly incensed by the reserves penalty proposal’s label, as stakeholders had declined to recommend it this month. 

“I agree there was a motion, but to call the pathetic work that the ISO did on this project a ‘completion’ is basically an indictment of the entire process,” he said. “They developed something that was very poorly designed. It got very negative feedback from a wide range of market participants and the [Market Monitoring Unit], which the ISO ignored all the way up to the point that the part they had developed had to be withdrawn.” 

The penalty was intended to address the approximately 10% of generator failures to respond to dispatch. Engaging the Demand Side was intended to be a “highly collaborative project” using stakeholders to identify gaps in demand-side resource programs. 

Kevin Pytel, director of product and project management for the ISO, seemed a little taken aback by the response to the penalty proposal, asking how many stakeholders on the call agreed. The New York Power Authority and Independent Power Producers of New York chimed in. 

“We were one of the big supporters of the Operating Reserve Performance Penalty, and we still support, kind of, what we pushed forward,” NYPA’s Tony Abate said. “But it did fail to garner substance and support from the stakeholders, so ‘completeness’ is the wrong categorization.” 

Pytel promised to take these comments to senior leadership but said that the intent of the presentation was to indicate there was going to be no further additional movement on the project until next year.  

“It is an approved project for next year,” Pytel said. “I know the removal piece and trying to iron out those details, making procedures, that is a priority for NYISO.” 

Discussion then turned to Engaging the Demand Side. 

“With respect to Engaging the Demand Side, it’s true that staff did circulate a market design concept, but it’s also true that all the affected stakeholders have rejected the concept,” one stakeholder said. “It seems like there’s a lot to be designed and discussed before you call the market design complete.” 

“We obviously got a lot of feedback on our proposal that it’s not where the stakeholder community wants it to be,” Pytel said. “My understanding also is that there is not unified agreement across the stakeholder community.” 

Pytel said that there had been movement in response to stakeholders, but several stakeholders argued that most of the proposals had come directly from staff without their input. 

“I think what you’re hearing is similar to the operating reserves” proposal, said another stakeholder who did not identify themselves. “What they are saying is that it’s not a completed product. That’s why you’re getting pushback.” 

“I will take this feedback back to the leadership team,” Pytel said. “I appreciate the comments. I’m not trying to be argumentative; just trying to talk through it so I can understand it better and articulate the concerns to the senior leadership team.” 

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Connecticut Closes the Door on 2024 OSW Procurement

Vineyard Offshore no longer plans to proceed with its bid for the 1,200-MW Vineyard Wind 2 project following Connecticut’s decision not to buy power from the project, the company said Dec. 20.

The news is a setback for Massachusetts’ efforts to scale up an offshore wind industry in the region. The state selected up to 800 MW from the project in its coordinated procurement with Connecticut and Rhode Island and had called on Connecticut or another other state or entity to pick up the remaining 400 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)

Massachusetts and Connecticut had discussed a deal for Massachusetts to buy some of the power from the Millstone Nuclear Power Plant — which is under contract with Connecticut — in exchange for Connecticut buying power from Vineyard Wind 2.

But Massachusetts proved to be unsuccessful at enticing any other bidders to procure power from the Vineyard Wind 2 project. Connecticut announced Dec. 20 its plans to select 518 MW of solar and 200 MW of battery storage from procurements administered in 2024, along with the closure of its offshore wind solicitation.

“With Connecticut’s decision today not to purchase the remaining 400 MW we are unable to contract the project’s full 1,200 MW at this time,” Vineyard Offshore wrote in a statement. “We look forward to advancing this project and participating in future solicitations to meet the region’s growing energy needs while spurring economic investment and creating thousands of American energy jobs.”

The bid cancellation leaves 2,078 MW of capacity still in play from the multistate solicitation; in September, Massachusetts selected 791 MW from Avangrid’s New England Wind 1 project and 1,087 MW from the SouthCoast Wind project, with Rhode Island selecting the remaining 200 MW from SouthCoast.

The states’ electric distribution companies still are negotiating the contracts for the two remaining projects. In November, Massachusetts electric utilities delayed the target date for finalizing the contracts from Nov. 8 to Jan. 15, with the contracts due to be submitted to the Massachusetts Department of Public Utilities by Feb. 25 (DPU 23-42).

The bids for the multistate solicitation likely will feature a major price jump compared to the first wave of offshore wind projects in the Northeast.

The best recent price comparison likely comes from the Sunrise Wind and Empire Wind projects, which agreed to contracts with New York in June with a $150.15/MWh rate. (See Empire, Sunrise Wind Back Under Contract in NY.) The 800-MW Vineyard Wind project, which was selected by Massachusetts in a 2017 solicitation and is under construction, has an average annual cost of $89/MWh (DPU 18-76, et al.).

Vineyard Offshore likely will have the opportunity to rebid Vineyard Wind 2 in 2025; Massachusetts passed a law in November authorizing multistate clean energy procurements through 2025, and state Energy Secretary Rebecca Tepper said at an event in December that her office’s statute “contemplates us doing another procurement in 2025.” (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.)

However, a new procurement alone will not solve the underlying cost issues facing New England’s offshore wind industry.

Beyond Vineyard Wind 1, neither Avangrid’s 1,080-MW New England Wind 2 project nor Ørsted’s 1,184-MW Starboard Wind were selected in the multistate solicitation, despite the authorization for procurements of up to 6,000 MW across the three states.

In shying away from an offshore wind procurement, Connecticut may have found more value in onshore projects. It selected three solar projects and a 200-MW battery project. Two of the solar projects will be located in Maine and one in Connecticut. The storage project will be sited on “an abandoned brownfield” in the state, the Department of Energy and Environmental Protection said.

“Growing and diversifying our energy supply, especially our supply of low-carbon sources of energy, is the key to bringing down the cost of electricity for Connecticut ratepayers,” said Gov. Ned Lamont (D). “These investments will also ensure we have a reliable and green grid that helps us meet demand now and well into the future.”

SouthCoast Wind Gets Federal Approval

Offshore wind advocates did receive some good news Dec. 20, with the Biden administration announcing its approval of SouthCoast Wind, the administration’s 11th offshore wind project approval to date. The administration authorized up to 2.4 GW of generation from the project. (See SouthCoast Wind Nears Federal Approval with FEIS Release.)

“As we mark this achievement, we look forward to the meaningful economic opportunities the SouthCoast Wind Project will bring to this region, both during construction and throughout the project’s lifetime,” said Bureau of Ocean Energy Management Director Elizabeth Klein.

SouthCoast canceled prior contracts with Massachusetts in 2023 due to rising project costs. Its bid for the multistate procurement indicated it would begin construction in 2025 and come online by 2030.

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NYISO MC Approves Dynamic Reserves, Regulation Multiplier Proposals

During its last meeting of the year Dec. 18, the NYISO Management Committee approved two proposals that would institute a new design for the reserve market and alter a calculation used in the regulation service market. 

Stakeholders approved tariff revisions to establish dynamic reserves, as opposed to the current static model, which bases the reserve requirement on the largest single source contingency and assumes the transmission system is fully scheduled. 

Dynamic reserves, however, can be adjusted in real time based on grid conditions. This would allow NYISO to procure the lowest-cost mix of generation to meet current system conditions. The ISO expects this to help as the system depends more on intermittent resources and during extreme weather conditions. 

The proposal has been in development since 2021, with the release of the Reserve Enhancements for Constrained Areas study, which found that the current modeling of reserve regions could not reflect the needs of the grid to respond to system changes in real time. 

Implementation of dynamic reserves is planned for 2027. NYISO is targeting the second quarter of next year to file the final tariff revisions with FERC. 

The MC also approved an update to the Regulation Movement Multiplier, a factor used to schedule regulation service providers. It represents the relationship between the number of megawatts of regulation capacity the ISO has historically sought to maintain each hour and the regulation movement megawatts instructed by automated generation control each hour. 

25th Anniversary

In his monthly address to the committee, NYISO CEO Rich Dewey noted that Dec. 1 was the 25th anniversary of the ISO. 

“There are 28 employees still around who went through that transition, and there are 22 NYISO employees that weren’t even born yet when we did that,” said Dewey, referring to the evolution of the New York Power Pool to the ISO. 

He congratulated stakeholders on their work. “Many of you also participated in the development of our rules and the formation of the ISO. … I’m looking forward to the 50-year anniversary, which is 25 short years away.”