Search
April 10, 2025

Posted on

Texas Loan Program Loses 2 More Gas Projects

Texas’ loan program for gas generation has lost two more projects, marking the third and fourth companies to withdraw projects from the due diligence review process. 

Constellation and WattBridge became the latest to pull projects from the Public Utility Commission’s In-ERCOT Generation Loan Program, part of its Texas Energy Program. The companies took out four projects totaling 1,410 MW.  

The 16 remaining applications total 8,346 MW of capacity and $4.46 billion in requested loan amounts. The TEF is a $5 billion, low-interest program designed by lawmakers to quickly add new natural gas plants. 

PUC spokesperson Ellie Breed said staff intend to advance additional applications to the due diligence phase at a future open meeting. 

Constellation was seeking financing for 300 MW of gas-fired generation at its Wolf Hollow III facility. It told the PUC in March it was unable to determine “with certainty” the project’s overall costs because of the “uncertain timing” in receiving an air permit from the Texas Commission on Environmental Quality. That would prevent Constellation from signing a binding loan document. 

Wattbridge withdrew three projects totaling 1,110 MW of capacity. It said the TEF’s financing terms “introduce risk and costs that result in lower than anticipated returns with elevated risks.” 

The company also said it was withdrawing a 510-MW project in the Houston region from the pool of remaining applicants.

Two other companies pulled their projects from the TEF earlier in 2025. They cited supply chain issues as delaying the projects and keeping them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.) 

More than 4,650 MW of capacity has been withdrawn or denied from the original submitted applications. Nearly a third (3,903 MW of 12,249 MW) of the projects that advanced to due diligence now have been withdrawn or denied. 

“Texas will get new gas resources … but gas plants take time,” noted Stoic Energy principal Doug Lewin in his newsletter. “They can’t be developed fast enough to ensure reliability or allow for economic growth in the next three or four years, and possibly longer than that.” 

Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told board members April 7 that all 16 Texas Energy Fund projects recommended for due diligence by the PUC have submitted full interconnection study (FIS) applications with the ISO and are in various phases of the generation-interconnection process. Seven applicants have completed the full study processes. 

“Moving forward, a lot of progress on those,” Hobbs told the board. 

The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state. 

The fund is composed of four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and Texas Backup Power Package. 

Posted on

NEPOOL Markets Committee Briefs: April 8-9, 2025

The NEPOOL Markets Committee (MC) held a two-day meeting focused on ISO-NE’s capacity auction reform (CAR) project. (For more coverage of the meeting, see ISO-NE Outlines Market Power Mitigation Measures for CAR Project.)

Ambient Temperature Derates

In other business, Hannah Johlas of ISO-NE presented an analysis of how ambient temperatures affect the performance of non-nuclear thermal resources, which the RTO developed in response to stakeholder requests. The analysis included an evaluation of third-party studies, capacity audit data and historical operational data.

All three components of the study showed a significant decline in the capacity of thermal resources as temperatures increased, equal to about a 3-4% decline in performance between 90 and 100 degrees Fahrenheit. The analysis did not evaluate the effects of ambient temperatures on fuel availability or resource outages.

While ISO-NE plans to calculate resource capacity accreditation at 90 F in the summer and 20 F in the winter, some stakeholders express concern that temperatures beyond this range could affect reliability.

ISO-NE does not plan to include modeling of ambient temperature effects in the CAR project due to the limited impacts and challenges of incorporating the additional modeling into the project. Johlas said it’s uncommon for the entire resource fleet to face temperatures above 90 F, even as climate change increases temperatures.

Some stakeholders pushed back on this conclusion, making the case that extreme heat often coincides with stress on the grid, and that a 3-4% reduction in the capacity of a 22,000-MW thermal fleet could cause a capacity reduction of up to 880 MW.

Demand Response Distributed Energy Resource Aggregations

Also at the MC, Dennis Cakert of ISO-NE presented conforming changes for FERC Order 2222, focused on demand response distributed energy resource aggregations (DRDERAs), which are aggregations of DERs that can reduce demand and inject energy into the grid.

Order 2222 requires transmission operators to eliminate barriers for distributed energy resource aggregations to participate in wholesale markets.

ISO-NE proposes to make DRDERAs eligible to participate in the day-ahead ancillary services market and to receive net commitment period compensation (NCPC). Including DRDERAs in NCPC would prevent “economic incentives to not offer true costs or follow dispatch instructions” in the energy market, Cakert said.

ISO-NE also proposes to reduce the minimum size requirement for resources participating in the regulation market from 5 MW to 100 kW “to align with the approved Order No. 2222 design.”

The changes would take effect in November 2026. ISO-NE will continue discussions on the conforming changes at the MC in May, targeting a vote on the proposal in June.

Tie Benefits

Matthew Ide, representing the Interconnection Rights Holders Management Committee, presented on the value of tie benefits and pushed back on the New England Power Generators Association’s (NEPGA’s) arguments in March that including tie benefits in the installed capacity requirement (ICR) creates reliability risks. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The ICR determines the amount of capacity ISO-NE must procure in the capacity market, while tie benefits refer to the emergency support New England can expect to receive from neighboring regions during a capacity shortage.

At the MC in March, Bruce Anderson of NEPGA said the “current market design ‘assumes away’ approximately 2,000 MW of capacity demand based on the belief that system energy from neighboring control areas is equivalent to ‘firm capacity,’” creating risks of under-procurement and price suppression.

At the April MC meeting, Ide emphasized that tie benefits are not a market product, and instead are “the reasonably assumed reliability benefits that come from transmission infrastructure that enables emergency assistance between regions.”

Tie benefits “are a reasonable and appropriate input into the ICR calculation,” he added.

Ide said tie benefits are supported by contracts ensuring ISO-NE will receive tie benefits from neighboring regions if this support does not jeopardize reliability in the neighboring region. Even if weather conditions are similar across regions, it’s highly unlikely for regions to experience resource outages threatening reliability at the same time, he said.

“Network load customers pay for all the tie benefits that come from the [pool transmission facility] ties through regional transmission rates. In return, load receives the benefit of a lower ICR and less need to procure capacity to meet the ICR,” he added.

He noted that FERC has found including tie benefits in the ICR to be just and reasonable, and that a recent ISO-NE analysis found the “underlying methodology is robust and thorough in the capacity quantification of tie benefits.”

ICR in a Prompt Auction

Manasa Kotha of ISO-NE discussed how the transition to a prompt market will affect the RTO’s methodology for establishing the ICR. He said ISO-NE will begin the ICR process about a year prior to each capacity commitment period.

“The primary conforming change for the ICR setting process is mainly the timeframe,” Kotha said, adding that reducing this timing from four years to one year will allow ISO-NE top use more up-to-date data, load assumptions and interface limits.

“Under CAR-Prompt, the data will all be provided closer in time to the commitment period, which is expected to enhance the accuracy of the ICR-related values,” Kotha said.

Posted on

ISO-NE Outlines Market Power Mitigation Measures for CAR Project

ISO-NE discussed its plans for preventing and mitigating market power as it overhauls its capacity market and resource retirement processes at the NEPOOL Markets Committee’s meeting April 8.

The RTO’s Capacity Auction Reform (CAR) project proposes to reduce the time between auctions and capacity commitment periods, transitioning the region from a forward market to a prompt construct. ISO-NE also plans to decouple resource retirements from the capacity offer process because the timing of the prompt market would not give the RTO enough time to address reliability issues created by retirements.

Under the new format, ISO-NE would require retiring resources to submit deactivation notices two years prior to their retirement from the market. As proposed, retirement notices would be binding and trigger an ISO-NE review process of potential reliability and market power issues. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The market power analysis would include a conduct test to evaluate whether the resource is expected to be economic and a net portfolio benefits test to study whether a market participant’s overall portfolio would benefit from the resource retirement.

If a resource fails both tests, ISO-NE would issue a penalty equal to 1.5 times the participant’s expected portfolio-wide revenue increase from the retirement. These charges would be credited as a refund to all market participants.

“The market power charge is expected to be used infrequently,” said Kevin Coopey, principal analyst at ISO-NE. “Ideally, the risk of being charged deters the exercise of market power.”

The tests and charges would be based on expected market outcomes prior to the forward auction, instead of the actual market results.

“By evaluating market power at the notification deadline, we consider the perspective of the participant at the time of the deactivation notification,” Coopey said.

Coopey said basing market power charges on the actual auction results would create a nearly two-year delay for participants to learn the actual charge amount, creating significant uncertainty associated with unexpected events distorting market results and risks of excessively large charges.

Some stakeholders expressed concern about reconciling differences between the market expectations of participants and the ISO-NE Internal Market Monitor.

“The IMM acknowledges that different assumptions may be reasonable when the market participant holds different market information or beliefs,” Coopey said. “The IMM will accept different assumptions when they are reasonably justified.”

Responding to stakeholder requests for ISO-NE to allow participants to withdraw retirement requests, Coopey said the RTO is “considering the feedback,” adding that “the increased optionality of having withdrawable notifications must be balanced against the risk of increasing the likelihood of reliability retentions.”

ISO-NE has expressed concern that participants could fish for out-of-market resource retentions if they are allowed to withdraw a retirement request when a resource is not retained.

Responses to the proposal for a market power charge have been mixed, with some stakeholders arguing the proposal may not be punitive enough to prevent exercising market power, while others made the case it would be too punitive and could create reliability issues by preventing deteriorating resources from retiring.

Ben Griffiths of LS Power advocated for more flexibility on the timing of retirement submissions, proposing that resources not needed for reliability should be allowed to retire with less than two years of advance notice.

“Without commenting on the merits of the two-year notice proposal, allowing for accelerated exit of resources determined nonessential for reliability would reduce market inefficiencies and resource owner concerns about forced market participation,” Griffiths said.

“Optional, expeditious deactivation for non-reliability resources lets the region split the difference on notification: Longer notice period lets the region proactively explore reliability implications of each deactivating resource, while accelerated exit allows it to avoid a lengthy exit period when they aren’t needed,” he added.

Also at the MC meeting, ISO-NE presented its plans for mitigating market power concerns on offers within the capacity market. Andrew Copland of ISO-NE said that “in the ISO’s current design, most key components of seller-side market power mitigation framework will remain substantively unchanged.”

He said ISO-NE will run a conduct test and a pivotal-supplier test to evaluate market power, and it plans to impose a “binding offer ceiling at the IMM’s estimated competitive offer price” for resources that fail both tests. Copland said ISO-NE will publish a capacity cost review threshold; all offers that surpass the threshold will be subject to cost review by the IMM.

Copland also noted that ISO-NE is updating its auction participation rules for the prompt market and will require “all commercial resources capable of providing capacity … to offer it into the auction.”

He said resources that hold unused capacity interconnection rights pose a barrier for other resources looking to enter the market and could cause these resources to incur significant interconnection costs. He noted that participants can include multiple cost levels within a capacity offer from a single resource to account for the potential added costs of offering a resource’s full capacity.

Posted on

Texas Groups Ask FERC to Reject Puerto Rican Company Petition for Regulation

ERCOT, Oncor and the Texas Public Utility Commission have asked FERC to deny a petition from Puerto Rican company Pluvia to bring the territory under the commission’s Federal Power Act jurisdiction (EL25-57). 

Pluvia seeks a finding from FERC that its proposal to transmit power to Puerto Rico via batteries on cargo ships could make it subject to the commission’s regulations. (See Petition Asks FERC to Potentially Claim Jurisdiction over Puerto Rico.) 

The parties all filed similar motions, but none of them were aware of the petition, filed in early February, until after the due dates for comments, they said. 

If the commission granted Pluvia’s petition, the precedent would threaten ERCOT’s jurisdictional status, in which its few connections to the rest of North America’s grid do not give FERC jurisdiction over its markets, the Texas grid operator said April 8. 

“ERCOT recognizes the immense challenges the people of Puerto Rico have endured since Hurricane Maria and supports efforts to rebuild and modernize the island’s electric grid,” it told FERC. “Yet, as explained below, Pluvia’s petition is not the right path to achieve these crucial goals.” 

Granting the petition would require an unprecedented reinterpretation and expansion of FERC’s licensing jurisdiction under FPA Part I, which authorizes the commission to license non-federal hydroelectric projects on federal reservations or affecting navigable waters of the U.S., and under another section that gives FERC power to grant preliminary permits for such projects. 

But using storage to transmit power is not a hydro project; the proposed sites in Puerto Rico are not considered federal reservations; and the transportation of cargo from the mainland to the territory would not involve crossing navigable waters of the U.S., ERCOT argued. 

“Such a radical change could have serious implications for the jurisdictional independence of Texas’s intrastate ERCOT grid,” said the PUC, which oversees ERCOT’s markets in the same way FERC regulates others in the U.S. All the transmission between it and other states is provided pursuant to FERC orders under sections 210 and 211 of the FPA. 

“Because Pluvia’s proposal does not involve any physical flow of electric energy between states, Pluvia presents no valid basis for the requested declaration,” the PUC said. “What Pluvia requests would be a radical redefinition, contrary to precedent, of the meaning of ‘electric energy’ under the FPA to include stored potential energy that would later be converted into electric energy. And it would redefine ‘transmission’ under the FPA to include the shipment of charged storage devices that does not involve the flow or comingling of electric energy in interstate commerce. … 

“This ‘clarification’” — as Pluvia said in its request — “is contrary to law and totally unjustified: It would require the commission to ignore the plain text of the FPA and depart from well-established precedent analyzing the same issues in the context of the ERCOT market.” 

Oncor had filed to intervene in late March, making similar arguments, and Pluvia had asked FERC to deny the late intervention. 

Oncor responded that while it was late, Pluvia’s project is in early stages and FERC actually weighing the merits of its earlier filing would not burden it. FERC has been liberal in allowing late interventions in cases involving its jurisdiction, Oncor said. 

“Even if Oncor had not moved to intervene in this proceeding, the commission still would need to assure itself that it has statutory authority to grant the relief Pluvia seeks,” the utility said. “As such, Oncor intervening to raise jurisdictional arguments does not unduly prejudice or burden Pluvia.” 

Posted on

Northwest’s Only Nuclear Plant Could Get Uprate

Operators of the Columbia Generating Station (CGS) are seeking an extended power uprate for the facility, which is the Northwest’s only commercial nuclear power plant and a supplier of electricity to the Bonneville Power Administration.

Energy Northwest’s extended power uprate and efficiency improvement project for CGS would increase the power plant’s electric generating capacity from the current 1,207 MW to 1,393 MW in 2031.

Energy Northwest, a consortium of utilities from across Washington state, owns and operates the plant near Richland, Wash. BPA markets the energy produced and pays all costs, which are included in the revenue requirements of its power services rate structure.

BPA and Energy Northwest hosted a meeting April 8 on the proposed uprate. Energy Northwest said it would seek BPA Finance Committee approval next month. The uprate also requires Nuclear Regulatory Commission (NRC) approval.

Energy Northwest also is considering seeking a 20-year license renewal for CGS, which would extend operations through 2063.

Synergizing Projects

The uprate would coincide with so-called lifecycle management projects at the power plant, in which work on certain components already is scheduled. For example, replacement of the high-pressure turbine would cost the same with or without the power uprate, said Tammi Oldham with Energy Northwest.

In addition, the project potentially could take advantage of tax credits: either the production tax credit, an annual credit based on incremental generation, or the one-time investment tax credit.

“We see there is a growing demand for power, and we think an extended power uprate is a very [easy], cost-effective way to meet that growing need,” said Energy Northwest’s Jeff Windham.

“Overnight” direct costs, which don’t include interest expenses, are projected at $465 million for the lifecycle management projects and an additional $670 million for the extended power uprate, for a total of $1.135 billion, according to an Energy Northwest presentation. Indirect costs are estimated at $30 million.

Work related to the uprate would occur during refueling and maintenance outages scheduled for 2027, 2029 and 2031, Energy Northwest said.

Although the lifecycle cost and benefits of the extended power uprate are expected to reduce rates, Energy Northwest noted that rate pressure would increase during construction until the project starts generating energy.

BPA’s resource program includes the CGS extended power uprate in the least-cost portfolio for meeting future customer needs, a Bonneville representative said during the meeting. The uprate would reduce the amount of new solar and wind capacity BPA otherwise would need to acquire.

Uprates on the Rise

Nuclear power plants across the U.S. have been turning to power uprates to meet soaring electricity demand. In one recent example, Georgia Power has proposed uprates to four of its nuclear reactors in its 2025 Integrated Resource Plan. (See Georgia Power Proposes Nuclear Uprate, Delay in Fossil Retirement.)

Since the 1970s, the NRC has approved 171 uprates totaling 8,030 MW of electric power, roughly equivalent to eight new reactors. Nuclear plants typically increase their output by using slightly more enriched uranium fuel or a higher percentage of new fuel, Energy Northwest said.

Power uprates fall into different categories based on the percentage by which power will be increased, according to the NRC. Stretch power uprates fall within the design capacity of the plant and generally are up to a 7% increase.

In contrast, extended power uprates require “significant modifications” to a plant’s major equipment. Power increases in extended uprates may be as high as 20%.

The NRC said it’s preparing for more uprate requests.

“We’re already looking at our past reviews to see how we can process these requests as efficiently as possible while maintaining safety,” the agency said on its website.

Posted on

NYISO Reaffirms Need for NYC Peakers in Summer

NYISO continues to find a reliability need for New York City this summer and two peaker plants in the city should be allowed to continue operations into 2027 if necessary, according to sensitivity results for the first-quarter Short Term Assessment of Reliability (STAR), presented April 7 to the Transmission Planning Advisory Subcommittee. 

Ross Altman, NYISO senior manager of reliability planning, said the city would be deficient by 281 MW for five hours on a hypothetical summer peak day during normal weather conditions if the Gowanus and Narrows peaker units are offline. Both barge-borne floating plants were built in the early 1970s and are owned by AlphaGen. 

The ISO said it continues to believe the plants should be allowed to operate beyond their planned retirement in May, until May 2027 or a “permanent solution” is in place. 

But NYISO also is concerned about unplanned outages at aging plants; the accelerated retirement of other, smaller New York Power Authority gas plants; the impact of heat waves; and delays on the Champlain Hudson Power Express transmission project.  

The status of the fossil fuel fleet and NYISO’s assumptions about their retirements occupied much of the discussion. Altman said the ISO was not forecasting retirements; rather, the intent of the analysis was to understand how many old plants were at risk of failure. 

“What we’re showing with aging fossil fuel [power plants] isn’t purely economic or policy driven,” Altman said. “As complicated, spinning heavy machines age, they are more likely to fail.” 

Chris Casey with the Natural Resources Defense Council asked NYISO to make it clear in the final Q1 STAR report, due to be released by April 14, that it wasn’t talking about normal retirements. He said the language of the presentation made it confusing as to whether the “deactivations” were a normal process or from catastrophic failure.  

Doreen Saia, chair of the energy law practice at Greenberg Traurig, asked whether the ISO was implying with this analysis that it was worried that if a fossil fuel generator went offline, it would not get it back.  

“If that’s part of your analysis, it needs to be said someplace because I think it’s an absolutely fair assumption,” Saia said. “I don’t know why you would think you could get them back in this environment where gas turbines aren’t favored and the owner could very well sell or repurpose their very attractive real estate.”  

NYISO also presented its 2025 preliminary baseline forecast for the next 10 years of load growth for both the winter and summer capability periods.  

The ISO projects roughly 3,700 GWh of large load growth in 2025, mostly concentrated in the North Country and Buffalo. In 2026, roughly 7,800 GWh of large load is forecast to be on the grid.  

These large loads constitute the greatest driver of growth in New York. In the near term, they dwarf both electric vehicle and building electrification forecasts. Economy-driven demand growth is projected to remain relatively low through 2035 because of poor economic forecasts.  

Without the large loads, New York likely would see declines in overall energy consumption because of outmigration and slowing economic growth through 2031. The forecasts did not consider the Trump administration’s tariffs.  

The ISO also expects energy efficiency gains to mitigate load growth, with strong support from behind-the-meter solar and energy storage.  

Casey said he agreed with several skeptical stakeholders that some of the sensitivity scenarios did not present credible possibilities. He went further, saying that given the tariffs from the Trump administration, the baseline forecast could be “way above” reality. 

“There is a realistic possibility that things will stay as they are,” Casey said. “A lot of economic development and large loads that we anticipate coming are not going to come, or are not going to come when they are expected.” 

Posted on

BPA Flooded with Comments on Draft Day-ahead Market Decision

The Bonneville Power Administration elicited nearly 150 comments in response to the March 6 draft policy outlining its decision to join SPP’s Markets+ rather than CAISO’s Extended Day-Ahead Market.

BPA’s tentative decision in favor of Markets+ offered little surprise to Western electricity sector stakeholders involved in the development of day-ahead markets in the West.

Still, the draft’s release ended nearly two years of speculation about a potential surprise — or whether the agency might succumb to political pressure and delay its choice to let developments play out around the West-Wide Governance Pathways Initiative’s efforts to bring more independent governance to CAISO’s markets. (See BPA Selects SPP Markets+ in Draft Policy.)

The torrent of comments (so far) have offered few surprises as well, with supporters of each market staking out many of the same positions they’ve voiced since BPA kicked off its day-ahead market participation stakeholder process in July 2023.

RTO Insider’s round-up of the comments is by no means a comprehensive one, but we have sought to include many from key players in the industry and important constituencies. More comments were being posted to the BPA site throughout the day, and we will continue to review them for inclusion in future articles.

BPA officials have said they will respond to the comments and expect the agency to issue its final record of decision in early May.

‘Compelling’ Choice

Unsurprisingly, the consumer-owned utilities (COUs) that make up BPA’s base of “preference” customers largely supported the draft policy and urged the agency to finalize its decision without delay.

A common thread among the COUs backing the draft policy was the market governance issue, with some contending the Markets+ framework provides an independent governance structure that EDAM lacks.

For example, Gary Huhta, general manager at Cowlitz County Public Utility District, urged BPA “to proceed without delay” instead of waiting for the Pathways Initiative to wrap up “development of a partial independent governance structure.”

Pathways is developing a “regional organization” (RO) that will assume governance over EDAM and CAISO Western Energy Imbalance Market.

“BPA’s choice of Markets+ over CAISO’s EDAM is compelling, as its superior independent governance, uniform resource adequacy requirements, [greenhouse gas] design and a congestion revenue mechanism that promotes transmission investments,” Huhta wrote.

Snohomish County PUD shared Huhta’s sentiment. Snohomish noted that for Pathways to succeed, the California Legislature would have to support the initiative. And even if lawmakers back the proposal, Pathways “would not achieve full independence due to the remaining significant intertwining of CAISO and the new regional organization, including shared staffing and a shared tariff.”

“Under the proposal, CAISO would retain the dual roles of a participating balancing authority for one part of the footprint and the market operator for the full footprint that could result in a conflict of interest,” Snohomish contended. “Given the magnitude of trade likely to occur within day-ahead markets, and the potential influence of market rules and market operations over the allocation of costs and benefits of market participation, Snohomish has a strong preference for the fully independent governance structure of Markets+.”

Snohomish also is one of the signatories to the so-called “issue alerts” published recently to highlight the purported advantages of Markets+ over EDAM. (See 7th ‘Issue Alert’ Highlights Markets+ Footprint.)

The Western Public Agencies Group (WPAG), which consists of 27 COUs in Oregon and Washington, supported the draft policy. The organization noted the policy comes as utilities prepare to sign new long-term provider-of-choice contracts slated to go into effect in 2028 and set the conditions under which BPA sells federal power to customers.

“BPA’s proposal to participate in a day-ahead market is the type of strategic progression needed to meet the moment and to secure the region’s long-term future,” WPAG wrote. “What is more, based on BPA’s extensive analysis, Markets+ appears to be the market for the job.”

Vancouver, British Columbia -based energy trader Powerex, a key Markets+ backer, said it “strongly supports” BPA’s draft policy, writing that it “reflects thorough analysis, extensive stakeholder input and a clear understanding of the long-term structural, operational and economic implications of organized day-ahead market participation.”

The company also said it agrees with BPA’s conclusion that the SPP market is the best option “to protect the value” of the federal hydroelectric system and “uphold its statutory obligations, and promote a durable, fair and transparent market platform for Bonneville, its customers and the region.”

‘Ignores the Facts’

But the region’s two largest consumer-owned utilities by number of customers — Seattle City Light and Eugene Water and Electric Board (EWEB) — stood out among COUs in opposing BPA’s draft decision.

“BPA’s decision to join Markets+ does not comply with the agency’s statutory obligation to provide ‘the lowest possible rates to consumers consistent with sound business principles.’ Rather, BPA’s premature decision ignores the facts presented by its own record and analysis,” City Light wrote in comments that extended to 114 pages.

City Light reiterated the key concerns it expressed in a letter to BPA Administrator John Hairston last November after the agency played down the value of the results of a study it had commissioned to compare the potential economic benefits of participating in either market. (See Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.)

“BPA’s own economic analysis indicates that joining the California Independent System Operator’s Extended Day Ahead Market offers the largest benefits to its customers, followed by choosing to not join any day-ahead market,” the Seattle utility said.

City Light said Markets+ “is worse for BPA customers than EDAM by $165 million to $221 million annually — and these losses persist indefinitely into the future,” while continued participation in the WEIM would provide only $79 million to $130 million in greater benefits than joining the SPP market.

The utility also contended “all available analysis” indicates Markets+ will not provide the “well connected and integrated market footprint of diverse loads and resources” needed to deliver the maximum benefits for BPA customers.

“BPA’s decision eschews objective analysis and chooses which factors it elevates based on whether they support its preferred outcome. This is not consistent with sound business principles,” City Light said.

Oregon-based EWEB said it agreed with BPA about the need for independent market governance but contended that issue should not be the “sole factor” in the agency’s decision and “must be carefully weighed alongside the critical elements of transmission connectivity and market footprint.”

EWEB expressed concern about what it said are “the inefficiencies associated with a smaller, disconnected market like SPP’s Markets+.”

Like City Light, EWEB encouraged BPA to continue participating in the WEIM over joining Markets+, giving the agency time “to observe the ongoing evolution of EDAM and its progress toward independent governance.”

“By waiting, BPA can make a more informed, strategic decision that not only aligns with its operational goals but also strengthens regional collaboration. This measured approach ensures that BPA chooses the best long-term market option for both its stakeholders and the broader region,” EWEB wrote.

‘Narrow Set of Interests’

The draft policy also found little support among environmental organizations, with many urging BPA to pause or withdraw its draft decision.

In a joint letter, Earthjustice, the Northwest Energy Coalition and Idaho Conservation League said the proposed decision violates the National Environmental Policy Act and the Pacific Northwest Electric Power Planning and Conservation Act.

The trio argued BPA failed to consider the environmental impacts of its choice in violation of NEPA, noting the agency has committed “up to $40,000,000 as part of the collateral for a bank loan to support the development of Markets+. The promise to pay these funds is irrevocable, and they will be forfeited if BPA withdraws from Markets+. This commitment of resources prior to any environmental review is contrary to NEPA.”

The groups argued BPA violated the latter act by ignoring the “substantial cost savings of a decision to join EDAM” and instead prioritizing Markets+’s governance design. They pointed to two production cost studies showing that EDAM could provide significant savings for BPA customers under certain scenarios. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)

In urging BPA to withdraw its draft policy, the groups wrote that the agency’s “response to public input has been minimal, and its decision-making process has been opaque and appears more focused on catering to a narrow set of interests rather than the broader public good. BPA, however, has a legal duty to serve the best interests of the entire Pacific Northwest, including, among others, the region’s energy, environmental and economic interests.”

Other environmental groups similarly opposed the draft decision. Save Our Wild Salmon Coalition, Sierra Club, Oregon Clean Grid Collaborative and Renewable Northwest all opposed the draft decision in separate letters.

The Washington BlueGreen Alliance, a coalition of labor unions and environmental groups, said BPA did not “fully consider” how its decision would affect not just preference customers, but the Northwest region at large.

“We are concerned that the BPA draft decision to join Markets+ is based on an inadequate analysis of each day-ahead market’s governance structure and economic costs to the region, which will have significant consequences for our region’s climate policies and workers,” the group said.

They also argued the “fragmented nature” of the Markets+ footprint is likely to result in a less reliable system or require customers to pay more to ensure uninterrupted delivery.

“Substantial increases in BPA’s costs have a direct effect on industrial manufacturing growth and job creation in our states. These costs will likely be passed on to ratepayers, and the impact will be felt most acutely by large energy users, such as industrial and commercial ratepayers,” the group wrote.

Tribal Perspectives

Many of the region’s tribes had their own reason to oppose BPA’s decision and urge postponement, saying they were unable to provide informed — and legally required — consent because of the agency’s lack of “government-to-government consultation” with tribal representatives.

“The federal government’s trust responsibility obligates BPA to ensure that tribes are full partners in managing the lands and resources that are our ancestral inheritance,” the Snoqualmie Tribe in Washington wrote, adding that “tribal values, priorities and rights must be integrated into the” day-ahead market.

Washington’s Yakama Nation urged BPA to delay until it “has engaged in full in meaningful consultation” with the tribe to ensure that participation in a day-ahead market does not “negatively impact” the Yakama’s treaty-reserved resources and rights.

The Confederated Tribes of the Umatilla Indian Reservation expressed similar concerns, pointing to potential risks to its members’ fishing rights on the Columbia River from changes in BPA’s operations.

The Alliance for Tribal Clean Energy echoed those concerns, while also contending BPA’s decision was “rushed.”

“BPA’s accelerated timeline precludes the thorough evaluation of alternative market options that might better align with tribal interests and environmental considerations,” the alliance wrote.

Tech Views

Tech companies and data center developers, including Google, Amazon, Microsoft and Rivian, signed a letter by the Clean Energy Buyers Association asking BPA to postpone its decision.

The companies contended more analysis is needed to consider studies that show a “wide range of potential outcomes, especially the potential for increased systems costs, creates confusion and significant uncertainty for ratepayers.”

“Retail customers in Bonneville’s service territory deserve greater assurance that participation in a [day-ahead market] will not drive undue costs, ultimately borne by ratepayers,” the companies wrote.

They also wrote BPA should wait until the outcome of Pathways, while noting that staffing issues at BPA pose challenges. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)

Amazon, which has invested billions of dollars toward the development of data centers in Oregon, issued a separate letter. The company said BPA’s justification for its draft policy “is not sufficient to meet the important threshold of ratepayer protection, particularly in light of other market options available, some of which have been reported by Bonneville studies to save customers hundreds of millions compared to the Southwest Power Pool’s Markets+.”

The company said BPA should hold off on joining a day-ahead market and remain in CAISO’s WEIM while it evaluates its options.

‘Seamless’ Market

CAISO weighed in as well, noting the estimated $97 million in benefits BPA has earned since joining the WEIM in 2022 and pointing to that market’s contribution to increasingly coordinated transmission flows across the Northwest, which it said has resulted in $1.5 billion in estimated benefits for the entire region.

“The seamless real-time operational market created between the Pacific Northwest and other WEIM balancing areas in the West has also become an invaluable tool in supporting system reliability, especially during stressed system conditions, which have increased in frequency and intensity in recent years,” CAISO wrote.

CAISO also questioned BPA’s treatment of the governance issue in its draft, saying the document does “not fully present and consider the enhancements to the ISO’s market governance that will take effect upon implementation” of the Pathways Initiative’s “Step 1” changes to that governance.

The ISO said BPA’s draft also neglected to discuss “limitations” SPP has placed on the governance authority of the Markets+ Independent Panel, an issue important for “comparative governance analysis.”

“While the [Markets+] tariff contemplates that the SPP board will give significant deference to the MIP’s decisions, the SPP board nonetheless retains broad authority to overturn such decisions,” CAISO wrote.

Posted on

Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies

President Donald Trump signed a series of executive orders April 8 that seek to keep existing coal-fired power plants running, ease regulations and permitting for coal mining, and remove “unlawful and burdensome” state laws that impede the industry. 

The president also issued a proclamation that coal plants be exempt from the latest iteration of the Mercury and Air Toxics Standard, which the White House said will ensure they are not prematurely closed. 

“For four long years, Joe Biden and congressional Democrats tried to abolish the American coal industry,” Trump said at a White House ceremony flanked by coal miners. “They did everything in their power — while he was awake, which wasn’t much — shutting down dozens of coal plants, upending coal leases on federal lands, and putting thousands and thousands of coal miners out of work.” 

Trump ordered the secretary of energy to use Federal Power Act Section 202(c), which is meant to be used as a backstop to keep plants running for reliability even if that violates environmental rules, in a much broader way than previously used. 

The president also called on the Department of Justice to go after “unconstitutional” state laws that limit the use of domestic energy resources, including coal and other fossil fuels. 

The final order is titled “Reinvigorating America’s Beautiful Clean Coal Industry” and includes measures to open more federal land to coal mining. 

The White House’s fact sheets tied to the announcements cite the recent return to demand growth from the expansion of data centers, which are expected to drive up overall demand by 16% in the next five years. They also call coal “essential” to the power grid, making up 16% of total generation, which is down from 52.8% in 1990, according to the Energy Information Administration. 

Coal generation has been on a steady decline since 2007 when it produced 2,016 billion kWh, falling to just 675 billion kWh in 2023, according to EIA. 

“It is highly unlikely, in fact, probably zero probability, that anyone will ever build a new coal plant,” energy consultant Alison Silverstein said in an interview. 

Coal generation is more expensive to build than natural gas, which is facing stiff competition on its own from renewables in the markets. The best any policies can do would be to keep coal plants running longer, and that means going against decades of efforts to clean up the grid, Silverstein said. 

Silverstein wrote a report for the Department of Energy in Trump’s first term when then-Energy Secretary Rick Perry submitted a Notice of Proposed Rulemaking with FERC that would have had grid operators pay coal plants their full operating costs. Her report said that was not needed, and FERC voted the proposal down unanimously 5-0 after several of Trump’s appointees had taken office. 

FERC is not the focus of the current efforts, though some of the executive orders indicate the cabinet secretaries could consult with the agency as the policies are implemented. 

The executive order on “Strengthening the Reliability and Security of the United States Electric Grid” directs Energy Secretary Chris Wright to “streamline, systemize and expedite” the Department of Energy’s process for issuing orders under Section 202(c). It gives the secretary 30 days to review and analyze forecasted reserve margins for all regions of the bulk power system regulated by FERC to identify those with margins “below acceptable thresholds as identified by the secretary.” 

DOE will have to release that analysis in 90 days and then use it to identify at-risk plants of 50 MW or above. It then will use its 202(c) authority to prevent them from leaving the grid, or from converting fuel sources if that leads to a net reduction in generating capacity. 

Recent uses of Section 202(c) have focused on maintaining reliability in extreme weather, and in many cases it was in effect only for days, according to DOE. A famous case from 20 years ago kept a plant in Alexandria, Va., open to avoid blackouts in D.C., including the White House (EL05-145). 

One issue that will have to be addressed is what compensation coal plants required to stay online are due. Most of the existing coal fleet already is uncompetitive and most are inefficient, Silverstein said. 

“Keeping them running is costing the local utility ratepayers money because it is more expensive to buy coal production and to keep the coal plants running than it is to buy in the market from renewables or gas,” Silverstein said. “So, the thing that they are doing is essentially keeping these plants going by raising everybody’s costs.” 

“Protecting American Energy from State Overreach” directs the Department of Energy to go after state policies that “target or discriminate against out-of-state energy producers.” The order specifically calls out climate policies enacted by California, New York and Vermont. 

“These laws and policies also undermine federalism by projecting the regulatory preferences of a few states into all states,” the order says. “Americans must be permitted to heat their homes, fuel their cars and have peace of mind — free from policies that make energy more expensive and inevitably degrade quality of life.” 

The order calls on Attorney General Pam Bondi to identify all such state laws and to prioritize challenges to laws purporting to address climate change, environmental justice, carbon or greenhouse gas emissions, and funds to collect carbon penalties and taxes. “The attorney general shall expeditiously take all appropriate action to stop the enforcement” of such state laws and file a report in 60 days on those efforts, which will include recommendations for additional executive actions or legislative measures.” 

Reactions to the executive orders were mixed, with some saying they will help maintain reliability and others saying they are bad for the environment and consumers. 

National Rural Electric Cooperative Association CEO Jim Matheson and co-op executives from around the country were at the White House in support of Trump’s actions. NRECA members own at least part of 79 coal units with 21 GW of capacity, and 11 of them, totaling 3 GW, are scheduled to retire between now and 2030. 

“At a time when electricity demand is skyrocketing, we need to be adding more always-available energy to the grid, not shutting down power plants that have useful life left,” Matheson said in a statement. “Electric co-ops provide reliable power to communities across the country. Today’s announcements help drive home smart energy policies that will support efforts to keep the lights on at a price families and businesses can afford. We thank the administration for recognizing the continued importance of always-available resources in the nation’s energy mix.” 

Rep. Julie Fedorchak (R-N.D.), who was president of the National Association of Regulatory Utility Commissioners before assuming office this year, also praised the action, having introduced a resolution warning about growing demand and retiring plants April 7. 

“At a time when reliable baseload power is being shut down without adequate replacement, his executive orders are exactly what we need,” Fedorchak said. “With electricity demand from AI and data centers surging, the U.S. urgently needs always-available power — and that’s what coal provides, especially the mine-mouth coal power we produce in North Dakota.” 

Environmental Defense Fund Director Ted Kelly blasted the orders, saying that they could not overcome the market realities faced by coal. He also took issue with the use of FPA Section 202(c) and vowed to oppose the White House’s efforts. 

“That law is designed for, and limited to, sudden emergencies creating an immediate risk of blackouts or other grid instability, such as storms, wildfires or sudden major infrastructure failures,” Kelly said. “It is time-limited for the same reason, and it further limits any power generation that conflicts with environmental laws or regulations to the minimum hours needed to address the emergency. Changes to the power system over time, like load growth driven by data centers or power plant retirements driven by economics, are properly addressed by planning and action by utilities and their regulators — not by irrational and unlawful emergency actions.” 

Based on the market realities and likely challenges from EDF or Democratic state attorneys general, Silverstein predicted this second-term effort to bail out coal would wind up much like the failed NOPR from Trump’s first term. 

“This particular effort, I think, is going to have more grandstanding impact than actual impact,” Silverstein said. “I think it will affect a few coal plants and a few coal-mining and coal-plant communities, and it’s going to raise costs for everybody. But it’s hard to imagine any data center wanting to sign a contract with a 60- to 80-year-old coal plant.” 

Posted on

Texas RE Offers Compliance Help for New Registrants

With new registrants entering the Texas Reliability Entity’s system at an ever-increasing rate, staff from the regional entity stressed the importance of adhering to NERC’s reliability standards at an April 8 webinar.

Speaking to attendees of the webinar, part of the regular Talk with Texas RE series, Cybersecurity Principal William Sanders said the organization has noted a significant increase in the number of new registrants over the past few years, from 31 in 2022 to 53 in 2024. Most of the new additions were generator owners, he continued, reflecting the “large amount of generation being built” in the Texas Interconnection.

Texas’ recent generation additions have come at “an incredibly rapid pace,” ERCOT CEO Pablo Vegas told the grid operator’s Board of Directors in December. Solar resources and battery storage accounted for 83% of the 1,775 active interconnection requests at the time. (See ERCOT Faces Uphill Battle to Meet Large Loads.)

Sanders said the accelerating pace of registration prompted Texas RE to reach out to these incoming entities. Whether they are builders of new generation resources or purchasers of existing assets, many of them may be responsible for following NERC’s standards for the first time, he said. Noting that “Texas RE’s violation data is different from the rest of the interconnections, just because of how many new entities we have,” Sanders said the RE wanted “to make sure that [new registrants] have everything in place they need to be successful.”

To best serve their target audience of prospective generation builders or purchasers, Sanders and his co-presenter Alex Petak, enforcement attorney at Texas RE, focused their presentation on standards violations most often recorded within 31 days, one year, or two years of registration. Sanders covered NERC’s Critical Infrastructure Protection (CIP) standards, while Petak handled the suite of standards grouped under the Operations and Planning (O&P) label. Both discussed the most-violated requirements and best practices to prevent infringements.

Among the CIP standards, Sanders said the most-recorded violation is of requirement R2 of the CIP-003 family, the currently enforceable version of which is CIP-003-8 (Cybersecurity — security management controls). This requirement mandates that entities “with at least one asset … containing low impact [grid] cyber systems shall implement one or more documented cybersecurity plan(s)” for those systems.

Sanders reviewed the mandatory components of such cybersecurity plans, which comprise:

    • Cybersecurity awareness: Staff must be trained on cybersecurity best practices at least every 15 months.
    • Physical security controls: Any physical barriers, such as fences, locks and security cameras, between intruders and cyber assets.
    • Electronic access controls: Firewalls and other obstacles to online intruders.
    • Cybersecurity incident response plans: Plans must be tested at least once every 36 months.
    • Transient cyber asset and removable media: Safety protocols for USB drives and other physical media that can be added to or removed from a computer.

Other CIP violations frequently recorded within the first two years of registration include requirements R1 and R2 of CIP-002 (Cybersecurity — BES cyber system categorization). These require GOs to identify assets that contain low-impact grid cyber systems and review and update those identifications every 15 months.

“If your organization only has one generation facility, this may seem fairly straightforward. You obviously know about the generation asset [around] which your entire company is built,” Sanders said. “However, that documentation does need to exist, and for entities who are purchasing generation assets, you might have multiple generation facilities under a single [registration], [and] we need to have surety that you are aware of each of those facilities.”

In his O&P presentation, Petak noted that “facility ratings come up a lot in the early days,” with violations of NERC’s FAC family of standards comprising more than 20% of noncompliances that begin within 31 days of registration.

He reminded attendees that requirements R1 and R2 of FAC-008 (Facility ratings) mandate that GOs maintain documented methodologies for determining facility ratings, while R6 requires how those ratings are to be implemented and maintained. All three requirements are among the most frequent violations within the first month of registration, with R6 topping the list.

However, after the first 31 days, the biggest share of infringements shifts to NERC’s modeling (MOD) requirements, particularly MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/var control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions).

Noncompliance with these standards usually is associated with requirement R2 of each one, which require GOs to have models in place for the applicable system functions. Petak noted that a common complaint among GOs is that “the deadline sneaks up on them in some way, or they were not tracking the deadline well enough,” and they or their third-party contractors lacked time to complete the verification.

“Having some sort of tracking software can definitely help out” with meeting the deadlines, Petak said. “In fact, most of the mitigating activities that we see when we’re processing these noncompliances involve the entity initiating some sort of software into their compliance program. So doing it before the noncompliance comes up would be ideal.”

Posted on

ERCOT: 60 GW in Additional Demand by 2031

ERCOT unveiled a long-term load forecast for 2031 on April 8 that adjusts projections provided by transmission providers and accounts for the uncertain nature of data centers and other large users. 

The numbers still are staggering. Even reducing the amount of utilities’ projected loads based on historical data, the study forecasts demand to reach 145 GW in 2031. That is less than transmission providers’ projections of 218 GW in 2031. 

The grid operator’s current peak demand is 85.5 GW, set in August 2023.  

“Several people are looking forward to [this], with bated breath,” Bill Flores, chair of ERCOT’s Board of Directors, told COO Woody Rickerson before he presented the adjusted methodology to the directors. 

The new treatment of load projections is a result of state legislation passed in 2023 (House Bill 5066) that updated regional transmission planning rules and required ERCOT to consider prospective loads identified by transmission providers. Previously, state laws prohibited the grid operator from factoring in load that was not financially committed or signed. 

The legislation also directs ERCOT to file an annual report quantifying the capability of existing and planned generation and load resources. Staff plan to meet that requirement by using their semiannual Capacity, Demand and Reserves (CDR) report, as they did in December 2024 by using the TSPs’ load forecast. 

ERCOT COO Woody Rickerson | ERCOT

However, that CDR revealed negative planning reserve margins as early as 2026. (See ERCOT’s Revised CDR Report Met with Doubts.) 

“We’re going to pivot away from using that forecast in this year’s May CDR,” Rickerson told the board. He noted the legislation’s “most impactful difference” was ERCOT accepting transmission providers’ officer-attested letters, which he attributes to much of the future data center load growth. 

The adjusted load forecast is based on three adjustments:  

    • delaying the in-service date by 180 days for all new large loads;
    • reducing new data center demand to 49.8% of the requested forecasts;
    • reducing officer-attestation loads to 54.55% of forecasts.

Rickerson said the reductions represent a “measured percentage of power being used” versus the forecasts. 

“An important part to keep in mind here is that this is a forecast based on the most recent data we have, and we’ll continue to update that as we move forward,” he said. “Those numbers were derived from loads that had been forecasted that we can now see and measure. Those numbers, as we move forward, can change as forecasts become more accurate.” 

The problem, Rickerson said, is how to count the large loads (75 MW or more) that data centers, hyper-scalers and crypto miners are planning.  

The board questioned Rickerson on the accuracy of data provided by transmission providers.  

“Data centers are not something that we were forecasting or looking at four, five years ago, so this is new information. How fast it builds out is something we’re all going to learn together,” he said. 

Rickerson said the quality of data needs to be adjusted “based on just the leading edge of historic numbers.” As ERCOT gets more of those numbers, he said, the grid operator’s adjusted load forecast and the transmission providers’ aggregate projections likely will merge into one. 

ERCOT CEO Pablo Vegas said Senate Bill 6, an omnibus energy bill being considered in the 2025 Legislature, includes provisions addressing the inputs into transmission providers’ forecasts. 

The ISO will begin incorporating the adjusted load forecast in transmission planning, resource adequacy and outage coordination analyses. Rickerson said a good-cause exception may be required from the Public Utility Commission. 

There could be some good news in the future over the escalating demand ERCOT faces. 

Pia Orrenius, a senior economist with the Federal Reserve Bank of Dallas, followed Rickerson’s presentation by saying the Texas economy is “likely slowing.” 

“[Business] outlooks have recently turned pessimistic,” she told the board, noting surveys of Texas businesses are “flashing some warning signs.” 

“Growth is likely to slow further … and will probably slow further than we’re currently forecasting,” she said. “The main reason is tariffs. They’re going to lead to higher prices. Consumption and investment will slow and possibly decline.”