Search
December 6, 2025

Posted on

Nebraska AG Sues Largest Utility to Block Coal Retirement

Nebraska’s attorney general is suing the state’s largest electric utility in an attempt to block partial retirement of an aging coal- and gas-fired power plant. 

Attorney General Mike Hilgers (R) said the plan would increase cost and decrease system reliability. 

The Omaha Public Power District converted three of the five generating units at the North Omaha Station from coal to gas in 2016. It is preparing to retire those units, which date to the 1950s, and perform a coal-to-gas conversion on the other two units, which date to the 1960s. 

Hilgers sued OPPD in Douglas County Court on Oct. 9, saying the move would reduce output of the plant by 40% at a time when demand is rising and would boost prices for ratepayers who now enjoy some of the least expensive electricity in the nation. 

Maintaining the status quo at the North Omaha Station would save OPPD and its ratepayers more than $40 million over the next five years and nearly $440 million over the next 15 years, Hilgers said in a news release. 

The plan therefore directly conflicts with the legislative vision for public power in Nebraska, Hilgers said. 

“Public power providers should not achieve their self-imposed environmental goals by raising prices for Nebraska consumers,” he said. “The proposed changes at North Omaha Station do not align with the fundamental objectives outlined by the Legislature, undermining the promise of public power.” 

OPPD did not respond to a request for comment for this story. 

Nebraska’s Largest

With 413,000 retail customers and annual sales of 17.1 million MWh, OPPD is the largest of 166 utilities in the only state served entirely by publicly owned utilities, serving approximately 45% of Nebraska’s residents. The 563-MW North Omaha Station is the second-largest generation asset in OPPD’s over-3.2-GW portfolio. 

The station’s location on the edge of a neighborhood with a higher poverty rate and a higher percentage of Black residents than the rest of Douglas County has led to complaints of environmental racism as the process of conversion and retirement stretched over more than a decade. 

OPPD initially had targeted completion in 2023, but in 2022, its board voted to postpone the move until two new natural gas facilities finished construction and completed the SPP interconnection process. That has happened: The 450-MW Turtle Creek Station started operation in June, and the 150-MW Standing Bear Lake Station apparently is complete. 

The move runs counter to the pro-coal stance of President Donald Trump and some other Republicans. Nebraska Gov. Jim Pillen (R) applauded the lawsuit, saying: “It’s foolish for any power district to turn away from the single-most affordable means of energy production known to mankind. Nebraska is blessed to have readily available coal reserves in Wyoming and the railroad infrastructure to get it here.” 

Hilgers’ lawsuit draws heavily on OPPD’s own statements and data. It states and asserts: 

    • The mission of Nebraska’s public power utilities as dictated by unambiguous state policy is to provide reliable electricity at the lowest cost consistent with sound business judgment. 
    • OPPD policies — notably the decision to end coal at the North Omaha Station — prioritize other considerations. 
    • By OPPD’s own admission, the retirement/conversion plan for North Omaha Station was based primarily on environmental considerations, in contravention of state policy. 
    • OPPD has formally incorporated environmental justice into its decision-making process and placed “environmental sensitivity” on par with affordability and reliability, which are “enshrined” as the central pillars for Nebraska’s public policy regarding electricity generation. 
    • OPPD itself has said retiring capacity will make it more difficult to serve existing and new customers, and that rising demand means that without generation capacity additions, it will face a deficiency in its ability to serve new large load requests in the next 10 years. 
    • OPPD said it expects approximately 2,000 MW of new customer requests over the next decade, a much faster rate of growth than previously anticipated. 
    • Replacing coal-fired dispatchable baseload generation resources such as North Omaha Station with intermittent resources will increase the cost of electricity for Nebraskans. 
    • OPPD has announced an aspirational goal of net-zero carbon emissions by 2050; its “Pathways to Decarbonization” calls for the end of coal generation by 2045 but also recognizes that baseload generation still is needed. 
    • OPPD’s decisions indicate it considers environmental justice to be a policy consideration of at least equal and arguably greater importance than the core considerations set forth by the state Legislature: reliability and cost. 
    • The North Omaha Station complies with all national ambient air quality standards; its coal-fired units have a low-emitter status under the federal Mercury and Air Toxic Standards; and OPPD is unaware whether the facility might be making anyone sick. 

OPPD Explains

In letters attached as an appendix to the lawsuit, OPPD President Javier Fernandez said the units to be retired — 1, 2 and 3 — are the oldest in the fleet and are used less than they once were. 

The North Omaha Station’s generating units’ service date, nameplate capacity and average output in the past five years are: 

    • Unit 1: 1954, 63 MW, 6,929 MWh; 
    • Unit 2: 1957, 71.8 MW, 10,423 MWh; 
    • Unit 3: 1959, 92.5 MW, 66,555 MWh; 
    • Unit 4: 1963, 117.7 MW, 612,678 MWh; 
    • Unit 5: 1968, 216.2 MW, 878,663 MWh. 

Fernandez said the system is expected to meet federal and regional grid reliability regulations after the retirement and conversion is complete but acknowledged it would have more margin and better reliability/resiliency if maintenance and life-extension work were performed and North Omaha remained in service in its current configuration. 

Fernandez said OPPD has taken steps to replace the loss of supply from North Omaha. But he also said eastern Nebraska peak growth has increased 500 MW in the past five years, and if sustained load growth continues, OPPD would expect sustained challenges in securing resources to ensure affordable, reliable and timely electric service. 

He estimated OPPD could face a deficiency of anywhere from a few hundred to nearly 2,000 MW in its ability to serve new large load requests over the next 10 years without new capacity beyond assets OPPD already has or is planning. (Present-day system peak load is 2,810 MW.) 

Along with the two new gas-fired stations totaling 600 MW, OPPD has the new Platteview Solar farm, which has a nameplate capacity of 81 MW but SPP accreditation for only 42 MW in the summer and 29 MW the rest of the year. OPPD will buy or build four more 225-MW gas- or oil-fired units that are targeted for 2029 grid operation, as well as a 420-MW solar+storage facility that would go online in 2027 and have summer accredited capacity of 400 MW. 

In May, Sen. Jared Storm introduced and Sen. Tom Brandt co-sponsored Legislative Resolution 234, an interim study to “examine the impact of the net-zero plans and goals of public power utilities.” One of the stated purposes of LR234 is to evaluate the cost and impacts of net-zero initiatives, and the questions Brandt and Storm posed to Fernandez drill down on this. 

What state and federal laws prompt this transition at the North Omaha Station? There are none beyond EPA greenhouse gas regulations, Fernandez wrote in response, and the Trump administration has expressed intent to repeal those. 

Why is North Omaha being partly shut down if OPPD needs more generation? Because that is the plan the board of directors approved in 2014, primarily for environmental reasons, Fernandez said. 

Will the retirement make it harder to serve OPPD’s load? Yes, Fernandez responded. 

Storm asked: “In your professional opinion, should OPPD shut down [North Omaha] at this time?” 

Fernandez replied: “I respectfully must reserve that for our publicly elected board that has hired me to provide direction and implementation of the board’s strategic goals and policies.” 

Hilgers names OPPD, Fernandez and six of the eight OPPD board members as defendants in his lawsuit. 

He’s asking the court to declare that OPPD’s prioritization of factors other than cost or reliability directly contravenes state policy; to deem action under such prioritization invalid; and to enjoin all efforts, initiatives or actions that do not prioritize the cost and reliability of the electricity OPPD delivers. 

Posted on

SPP Wants to Defer $7B in 765-kV Projects to 2026

SPP staff have reiterated their position to defer part of the RTO’s planned 765-kV transmission overlay, setting aside about $7 billion in regional projects from its 2025 transmission assessment.

Instead, they plan to seek approval of up to 50 projects with an estimated cost of $11.16 billion, a 45.9% increase over the record 2024 $7.65 billion assessment. That does not include more than $1 billion for 22 stakeholder-submitted zonal planning criteria (ZPC) projects that also were studied in the 2025 Integrated Transmission Plan for system impact.

“This particular ITP has been a big lift,” SPP’s Casey Cathey, vice president of engineering, told state regulators during an Oct. 10 education session for the Regional State Committee. “It’s probably the most comprehensive study that SPP and its members have ever done, and it reflects where the system is and where our region is growing. Load is growing faster than we’ve ever seen, and our grid is feeling the strain.

“So, the question is, how do we stay ahead of it responsibly and cost effectively?” he asked. “This is a challenging situation for everyone.”

Cathey said deferring $7 billion of transmission projects “that we do believe is necessary” will allow staff to refine termination points for the upper part of a proposed 765-kV overlay in the southern portion of the footprint. He said staff are trying to better understand the full buildout that will be needed to meet the load growth they see ahead in 2026.

“It’s indicating load growth from all of Kansas state all the way up through North Dakota that will necessitate additional EHV [extra-high-voltage] and possibly ultra-high-voltage facilities in the 2026 time frame,” Cathey said.

The southern 765-kV overlay builds on the RTO’s first EHV project, Southwest Public Service’s 345-mile Potter-Crossroads-Phantom transmission line that was part of the 2024 ITP. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)

Staff said subsequent analysis using 2025 data demonstrated that a single 765-kV facility would not provide adequate energy delivery or voltage support for a region where load has increased from 4,700 MW to 11,500 MW between the 2023 and 2025 ITP forecast cycles. They said the SPS region’s isolation from the broader SPP grid makes it critical to use 765-kV solutions to establish “highly efficient” bulk power delivery.

The portfolio includes four 765-kV projects totaling $7.55 billion in costs, comprising the first phase of SPP’s 765-kV backbone. It connects SPS’ grid with the broader SPP network through Oklahoma and back down to Shreveport in northwestern Louisiana.

The Markets and Operations Policy Committee heard much the same presentation during a September education session. (See SPP Considers Deferring 765-kV NTCs to 2026.)

Staff’s presentation to the RSC included two 765-kV segments that they propose to defer while they refine termination points. By deferring a construction permit for the Potter-Woodward segment, a 471-mile facility in western Oklahoma predicted to cost $1.35 billion, SPP preserves the flexibility to evaluate whether more strategic or cost-effective alternatives could be achieved, they said.

SPP says the 2026 ITP will evaluate the need for a complete regional 765-kV network, including areas to the north in the footprint where spot loads were submitted for study for the first time. The Consolidated Planning Process transition assessment that follows also will consider additional EHV lines.

SPP says there’s a fine balance when deferring projects. | SPP

Staff cautioned the RSC that deferring costs may lighten the burden for the 2025 ITP but have unintended consequences for future assessments.

“What we don’t want to do is defer too much where we increase the burden of future ITPs and actually disrupt models,” said Kirk Hall, manager of transmission planning. “If there’s not enough transmission in the model because we’ve deferred too much, then it makes it really difficult to perform studies. It makes it difficult to explain what is going on in the models because in some cases, they may not even solve appropriately.”

Oklahoma Corporation Commission Chair Kim David said new legislation in her state requires the commission to consider an “extensive list” of criteria before approving construction permits for any transmission lines.

“I can just see the writing on the wall with some of this: that there could be a lot of delays; there could be some certificates [of convenience and necessity] not granted,” she said. “When I’m looking at that, I’m just seeing costs rising and costs rising and costs rising. I have some real concerns about it actually coming to fruition.”

“It’s going to be challenging,” Minnesota Public Utilities Commissioner John Tuma agreed, calling 765-kV projects “different animals.”

MISO’s second long-range transmission plan portfolio includes several 765-kV projects that the Minnesota PUC is grappling with. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)

“I hope estimates are being reworked for 765,” Tuma said. “They’re going to be a challenge for us to site.”

It took SPP several meetings with the RSC, Board of Directors and stakeholders to get SPS’ 765-kV project formally approved. The project had a cost estimate of $1.69 billion when it was approved in 2024, but SPS filed a revised estimate of $3.62 billion in June. (See SPP Board Approves 765-kV Project’s Increased Cost.)

The 2025 portfolio, excluding the ZPC projects, has a benefit-to cost ratio between 6:1 and 10:1, preserves reliability and mitigates rising energy costs because of increasing demand, SPP said.

During a joint meeting Oct. 1 between the Transmission and Economic Studies working groups, the TWG endorsed the assessment 10-9, with four abstentions, and the ESWG voted 6-4 in favor, with three abstentions.

The 2025 ITP now goes before MOPC during its Oct. 14-15 meeting in Little Rock, Ark.

Posted on

PJM Drops Non-capacity Backed Load, Shifts Focus to Resource Queue, PRD

PJM has withdrawn its non-capacity backed load (NCBL) proposal, shifting the focus of its solution for rising large load additions (LLAs) to creating a parallel resource interconnection queue, reworking price-responsive demand (PRD) and providing more insight into the load forecasting process for state utility commissions. (See PJM Revises Non-capacity Backed Load Proposal.)

The changes were presented Oct. 1 to stakeholders as part of PJM’s Critical Issue Fast Path (CIFP) process addressing LLAs, now in its second phase, in which design components are fine-tuned before being bundled into comprehensive solutions during phase 3. Another phase 2 meeting is scheduled for Oct. 14 with 11 proposal sponsors set to present.

PJM’s proposed expedited interconnection track (EIT) aims to create a pathway for resources capable of quickly entering service to receive a generator interconnection agreement through a 10-month study process. Applicants would be required to pay a nonrefundable study deposit starting at $500,000 and a $10,000/MW readiness deposit, as well as commit to being in service within three years of requesting an EIT study, though output may be limited if network upgrades are not complete by then. PJM Vice President of Planning Jason Connell said the EIT is envisioned as a permanent addition to the RTO’s interconnection processes.

If a resource does not enter service within three years, it would forfeit the readiness deposit and be subject to the same penalties for breaches of project milestones in the standard interconnection process.

All fuel types would be permitted, but projects would have to be at least 500 MW to participate and only 10 applications would be approved annually. The studies would be conducted according to when they were requested, and network upgrade costs would be assigned individually. No changes would be permitted in site control or attributes such as fuel type, nameplate capacity or equipment type.

Applications would be required to receive sponsorship from the state in which the resource would be located, which Connell said is intended to provide a degree of buy-in and reduce the odds that a project might receive expedited treatment from PJM only to become mired in siting and permitting challenges.

Connell said PJM decided on the 500-MW requirement by determining it would meet the amount of annual load growth expected while limiting the impact to projects in the standard interconnection queue. If a smaller requirement and larger number of applications were allowed, PJM found that would extend the amount of time needed to complete interconnection studies and defeat the purpose of an expedited pathway, he said.

Grant Glazer of MN8 Energy questioned if PJM would consider allowing a portfolio of projects to be included as one application to reach the 500-MW requirement. He said projects with a lower voltage and smaller nameplate capacity would be faster to develop and could provide a more economic form of capacity than larger resources.

PJM’s Tim Horger said EIT studies would use the latest system model case, and the upgrades they’re assigned would be added to the modeling for the next queue cycle. For any projects submitted while Transition Cycle 2 is ongoing, the latest model for that cluster would be used, and the resulting network upgrades would be added to the modeling for Cycle 1.

Adrien Ford, Constellation Energy’s vice president of wholesale market development, questioned if PJM would consider shrinking the 500-MW threshold, saying there are 300-MW uprate projects to nuclear units that could take advantage of the process.

Connell said PJM did not focus on facilitating uprates, as there are already opportunities for their studies to be accelerated.

Unpopular NCBL Dropped

The NCBL concept would have required participating large loads to forgo the guarantee of capacity, exempt them from paying for the service and removed that load from the capacity market.

It would have been triggered if the amount of forecast supply in a Base Residual Auction (BRA) fell short of the amount of expected demand.

The mandatory variant of the proposal received the greatest backlash from stakeholders, who argued it would make the PJM region unattractive for data center developers and undermine market signals. Opponents also argued that making the model voluntary would not solve jurisdictional issues around the RTO defining the retail service consumers could receive.

PJM sought to address the jurisdictional challenges by shifting the responsibility for assigning NCBL status to customers onto electric distribution companies and load-serving entities. It would have determined the RTO-wide amount of NCBL that would be needed to meet the reliability requirement in an auction and allocated portions to zones according to the amount of planned large loads forecast.

Claire Lang-Ree, an advocate with the Natural Resources Defense Council, said it was unlikely that resources utilizing EIT would be able to enter service before 2030, and thus would be unable to help with high capacity prices until after 2033. She questioned whether PJM’s revised proposal could deliver the same reliability as the mandatory NCBL concept.

Old Dominion Electric Cooperative’s Mike Cocco said removing NCBL from PJM’s proposal eliminates the original’s core design component from a reliability perspective. He said the load growth in PJM is unprecedented, and there needs to be a way to ensure it can be integrated reliably without impacting existing consumers, which NCBL would have accomplished. He suggested that changes to the manual load shed procedures could provide a similar benefit, but these decisions need to be part of the centralized CIFP solution, as the issue will only become more contentious if stakeholders wait to negotiate until after the capacity auction.

Horger said PJM is considering changes to manual load shed, but those will likely come outside the CIFP process.

Additional Changes to CIFP Proposal

Instead of the NCBL construct, Horger said PJM is now proposing changes to PRD to encourage flexibility from large loads.

The dynamic retail rate for PRD would be replaced with an energy market price, with the strike price serving as the offer. Horger said the change would make PRD function similar to a voluntary NCBL construct.

PJM is also proposing changes to its load forecasting process to add a step in which state utility commissions could review and provide feedback on the LLAs submitted by utilities under their jurisdiction.

Entities submitting LLAs would be required to ask the customer requesting service whether they are considering multiple sites for their projects and provide that response to PJM. Horger said the change is intended to identify instances where several utilities are projecting load growth for a data center that will ultimately only be built in one location.

Commitments to procure a minimum amount of capacity for planned large load customers are also being considered.

PJM Executive Vice President of Market Services and Strategy Stu Bresler said the RTO is open to exploring a model for long-term capacity procurement, either as part of its CIFP proposal or through subsequent stakeholder processes. He noted that the reliability backstop auction provides for some of that capability already, albeit following three years of the capacity market falling short of the reliability requirement and FERC approval of its implementation.

Advanced Power Proposes Higher Maximum Price

A design component from Advanced Power would double the maximum price of an Incremental Auction (IA) if the corresponding BRA clears short of the reliability requirement and use the increased ceiling for the subsequent BRA if the higher price is needed to clear enough capacity.

Ron Paryl, vice president of markets and risk management for Advanced, said this would create an additional opportunity for demand response to resolve the shortfall, while also allowing the auction to be responsive to updates to load forecasts and provide price discovery for the value of capacity. It would also avoid discrimination between consumers and allow those most price-sensitive to avoid high capacity costs, he said.

Advanced also proposed to lock resources’ effective load-carrying capability ratings if they would fall between a BRA and corresponding IAs, preventing sellers in the BRA from having to procure additional capacity to cover their commitment, particularly if prices increase above the original maximum price under the company’s first two components. If ELCC ratings increase, the resource owner would be able to bid that additional capability into the auction.

The potential for changes to the load forecast to shift resources’ ELCC ratings was seen in discussions around how to apply the 2025 load forecast to the parameters for the third 2025/26 IA; the forecast led the risk profile to shift toward the winter, causing ratings for several resource classes to fall. PJM opted not to include preliminary figures from the forecast, and stakeholders voted to lower the Capacity Performance penalties resources face if they cannot meet their commitment due to falling accreditation. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

Stakeholders questioned how DR offers are mitigated and whether the proposal would create market power concerns, while DR providers said adding reviews of offers would be complicated for aggregated resources.

Paryl said there is no requirement that DR be mitigated and so it should be able to make offers the sellers feel represent the costs for them to curtail.

Joint Proposal from Suppliers, Data Centers

A proposal from large suppliers and data centers would focus on making the forecasting of large loads more accurate and add triggers for demand and supply-side solutions. The proposal was sponsored by Calpine, Constellation, Talen Energy, Amazon, Google and Microsoft.

Large loads would be required to provide commitments, such as electric service agreements or arrangements to bring their own supply, in order to be included in the load forecast. A “reality check” would look at possible supply chain constraints, historic completion rates and other factors that could inhibit the number of projects completed. Characteristics such as ramping and utilization would also be factored in.

If a BRA falls below 98% of the reliability requirement, the demand-side solutions would be implemented immediately in that auction, starting with a voluntary large load DR model where participation is limited to a set number of hours a year, with reduced ELCC ratings. That could be followed by deployment of a new emergency procedure dispatching emergency backup generation to bring some of the large loads off the PJM system. The final step would be a curtailment of large loads participating in a voluntary model akin to NCBL.

If a shortfall persists after the demand-side options have been implemented, the proposal would see PJM solicit multiyear commitments of up to seven years, with shorter offers clearing first. Eligible resources include new and reactivated generation, existing generation with an offer cap above the top of the variable resource requirement (VRR) curve and DR. Those resources would clear at the top of the VRR curve and then enter subsequent auctions at the default gross avoidable-cost rate for their technology class minus the unit-specific estimated energy and ancillary service revenues. The clearing price the units would receive would remain the same across the duration of their commitment. The model would be in place between the 2028/29 and 2031/32 BRAs.

Constellation’s Ford said the BRA trigger criteria are important to minimize the impact to the market signals to attract long-term solutions. “We really want to avoid reliance on these potentially lower-quality products,” she said.

Enchanted Rock

A proposal from microgrid and backup power developer Enchanted Rock would establish a voluntary NCBL model in conjunction with states, EDCs and LSEs to allow large loads to be more flexible and create a pathway for them to interconnect ahead of network upgrades that might inhibit their ability to be reliably integrated onto the grid on a firm basis.

Joel Yu, Enchanted’s senior vice president of policy and external affairs, said voluntary NCBL is the best option for providing data centers with the ability to choose their level of flexibility, but there needs to be more adequate incentives on the supply side.

“If that load is making a commitment to provide flexibility via an NCBL structure or perhaps a different structure — as long as that flexibility can be modeled up front in an interconnection study process — we believe there’s an avenue for that load to access some amount of non-firm grid service on a provisional basis,” Yu said. “We’re not proposing any changes or options with respect to broader planning processes, but [it would] help to attract voluntary participation via the speed-to-power incentive.”

Additional Proposals to be Discussed Oct. 14

Several stakeholders have also submitted alternatives, to be presented during the CIFP meeting Oct. 14.

They include a joint proposal from Eolian Energy and the Brattle Group; proposals from the NRDC, Vistra and East Kentucky Power Cooperative; and a package from Johns Hopkins University associate professor Abe Silverman and Sue Glatz, principal consultant at Glatz Energy Consulting.

There will also be presentations from NOVEC, the Independent Market Monitor, Mainspring Energy, the Maryland Office of People’s Counsel and the office of Pennsylvania Gov. Josh Shapiro, but materials from these had not been posted online as of press time.

The EKPC proposal would require that large loads identify the LSE that will serve them before they can be incorporated into the load forecast and VRR curve, and institute “significant” penalties for LSEs that do not cover their own demand through owned or bilaterally contracted capacity. The penalties would only be assessed against LSEs within locational deliverability areas that are short of their reliability requirements in a BRA. Large loads would be defined as at least 50 MW.

Vistra proposed to impose penalties on any LSEs that are capacity deficient during emergency procedures in an effort to create an incentive for physical hedging and load flexibility. It includes a handful of options for how penalties could be determined.

The NRDC proposed a mandatory NCBL variant for any large loads coming online after the 2026/27 BRA that are not bringing their own generation. Large loads would also be able to gain firm service by participating as DR or PRD, or signing other loads to participate on their behalf; their curtailment risk could also be reduced by contracting with energy-only generation.

The Eolian and Brattle package would create a bilateral integration of generation portfolios and load structure for large loads to procure capacity through adjacent supply, with some backup provided by load flexibility. New resources participating would qualify for a 90-day expedited interconnection study and would not have their output derated by ELCC; instead, the owners of the resource and load would share the risk of underperformance.

The proposal from Silverman and Glatz is based on mandatory NCBL for new large loads so long as the capacity auction clears above the midpoint on the VRR curve. Another option would be to bifurcate the auction, first clearing non-LLA customers and then running a second auction for LLAs and any capacity resources that did not clear in the first run. To reduce the potential for double-counting large loads, they proposed to exclude them from the load forecast unless the relevant utility confirms that all distribution and transmission upgrades will be complete on time; the customer attests that it is not considering alternative locations for the project; and the customer can provide evidence of commercial maturity.

Posted on

Split Colo. PUC Approves Xcel Energy’s Markets+ Application

The Colorado Public Utilities Commission on Oct. 9 issued a split decision approving Public Service Company of Colorado’s application to join SPP’s Markets+, finding that market participation is in the public interest and will “provide a number of benefits.” 

The commission, in a 2-1 vote, approved PSCo’s participation, with Chair Eric Blank and Commissioner Tom Plant finding in favor of the request and Commissioner Megan Gilman dissenting. 

PSCo, a subsidiary of Xcel Energy, filed its request to join Markets+ in February. The commission voted to approve the utility’s participation July 30 but did not issue a comprehensive written decision — including approval of some cost-recovery measures — until now. (See Colo. PUC Approves PSCo’s Markets+ Participation.)  

“In sum, we grant Public Service’s application and authorize the company to recover the costs associated with joining SPP Markets+ because increased integration between Public Service and other utilities in the Western Interconnection will likely provide a number of benefits in the short term, while allowing the company and stakeholders to explore longer-term benefits that may result from [organized wholesale markets] or continued Markets+ participation,” Blank and Plant wrote. 

PSCo’s participation in Markets+ is in the public interest and will improve dispatch of generation resources in Colorado while alleviating market seams, Blank and Plant found. “Adding to those economic benefits are other shorter-term benefits, including near-term resource adequacy benefits associated with participation in the Western Resource Adequacy Program (WRAP),” the commissioners said. 

Markets+ has in place efficient greenhouse gas accounting mechanisms, and participation will lead to wholesale market price transparency and financial benefits, Blank and Plant wrote. Participation in Markets+ also is a step toward PSCo potentially joining an RTO in the future, the decision noted. 

However, Gilman did not share Blank and Plant’s conclusions, reiterating many points she made when the PUC approved PSCo’s Markets+ participation in July.  

Instead, Gilman sided with four organizations that intervened in the case to urge the commission to deny the application. Gilman wrote in her dissent that PSCo “fundamentally failed to satisfy the public interest criteria listed in commission Rule 3752(a) and, therefore, should have properly been denied by the commission without prejudice.” 

For example, Gilman argued that Markets+ lacks sufficient greenhouse gas accounting protocols, noting those are still in development, “leaving the final result unknown.” 

“Further, several parties point to the new potential for unprecedented federal interference, especially related to emissions tracking,” Gilman added. “Such an obvious and emerging risk should not be taken lightly and could stand to significantly complicate processes moving forward.” 

Blank and Plant noted in the decision that Colorado will have some utilities participating in RTO West and Markets+, both of which are operated by SPP, arguing that this is progress toward resolving seams issues. 

However, Gilman said, “There does not appear to be a solid plan for better integration of these markets, nor a timeline upon which to do so provided in this record.” 

Gilman also appeared skeptical that PSCo’s Markets+ participation will lead to greater economic benefits or that the utility will join an organized wholesale market by 2030 as required under Colorado law. 

On the issue of resource adequacy, Gilman noted that while SPP requires Markets+ participants to also join WRAP, the utility “could join the WRAP independent of joining Markets+.” 

“So, while it is accurate that such benefits could come from the necessity to join the WRAP in order to participate in Markets+, it is disingenuous to point to this as a benefit of Markets+, as the WRAP benefits could be achieved for a significantly lower cost in just joining WRAP itself,” Gilman added. 

Advanced Energy United was one of the intervening parties in the case. 

The organization’s regulatory director, Brian Turner, sits on the Launch Committee of the West-Wide Governance Pathways Initiative, established to shift governance of EDAM from CAISO to an independent regional organization. 

“This decision further balkanizes the Western grid, leaves Colorado clean energy isolated, and undermines Colorado’s ability to ensure an affordable, reliable energy future,” Turner told RTO Insider in an email. 

“We are pleased the Colorado Public Utilities Commission approved our participation in Markets+, a wholesale energy market that will benefit our customers and Colorado,” Xcel Energy spokesperson Michelle Aguayo said in an email. “Markets+ is anticipated to lead to economic, operational and environmental benefits, by reducing operational costs through more efficient use of generation resources, which could lead to lower overall energy costs for customers. When paired with a robust transmission network, it can enhance reliability of the power grid by providing sufficient generation resources during times of increased demand.” 

Posted on

Ørsted to Slash Workforce, Refocus on European OSW

Ørsted will reduce its workforce roughly 25% through the end of 2027 as it wraps up construction of offshore wind farms and remakes itself as a more competitive company.

The Danish company said Oct. 9 that it expects to shrink from approximately 8,000 employees to about 6,000 in the next 27 months, starting with around 500 who will be made “redundant” before the end of 2025.

CEO Rasmus Errboe made no specific mention of Ørsted’s U.S. projects in a news release, except to say that the company is committed to finalizing its existing portfolio off the coasts of three continents.

Ørsted’s financial problems stem to a significant degree from the U.S. market, where it built an early leadership position but has been sustaining substantial cost increases and impairments for more than two years. The future is even bleaker, thanks to President Donald Trump’s open hostility to offshore wind development and his administration’s efforts to thwart it.

Errboe said Ørsted will focus on the European market and certain Asian markets in its future offshore wind development efforts. In early 2024, the company said it remained committed to U.S. operations, despite problems there. (See Ørsted Exits Offshore Wind Markets, Remains Committed to US.)

The workforce reduction will come through attrition, terminations, divestment and outsourcing. Errboe said the process will yield a company that is more financially robust, competitive, efficient and flexible — and better able to bid on new offshore wind projects that would build value for Ørsted. It is expected to yield $310 million in annual cost savings.

“We’re committed to maintaining our position as a market leader in offshore wind,” he said. “We also need to reduce our costs for developing, constructing and operating offshore wind farms to strengthen our competitiveness.”

Ørsted has the largest fleet in the offshore wind industry, and the 8.1 GW now under construction would bring its installed capacity to 18.3 GW.

The company operates the first offshore wind farm built in U.S. waters, Block Island Wind, and the first utility-scale facility, South Fork Wind. It is building Revolution Wind and Sunrise Wind off New England and New York. It previously canceled its Ocean Wind project in New Jersey and paused Skipjack Wind in Maryland.

The portfolio is the largest in U.S. waters, and it ran into financial trouble well before Trump was elected to his second term, as the industry struggled with cost and supply chain challenges.

In the 11 months since the election, things have gotten even worse for Ørsted, culminating in a monthlong federal stop-work order in August against Revolution Wind, which was 80% complete at the time. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

Ørsted in August announced it would raise $9.3 billion and self-finance Sunrise Wind. (See Ørsted to Raise $9.3B, Self-finance Sunrise Wind.) Its stock price cratered on the news, punctuating a yearslong slide. The share price has rebounded since then but still is only half what it was a year ago.

Errboe spoke with journalists Oct. 7, after conclusion of Ørsted’s rights issue of new shares to raise the cash. Reuters reported that he said work has fully resumed on Revolution Wind, which is expected to begin operation in the second half of 2026, and that Sunrise Wind is still targeted for commercial operation in the second half of 2027.

Ørsted has said the combined investment in Revolution and Sunrise will be approximately $15.5 billion.

Posted on

Renewable Construction Slump Starts in 2028, Forecast Shows

U.S. construction of new wind, solar and energy storage facilities will decrease significantly over the next five years, with a cliff dive projected to take place in 2028, a BloombergNEF analyst said in an Oct. 8 presentation to the California Energy Commission. 

About 81 GW of new wind, solar and energy storage capacity is projected to be installed in the U.S. in 2027, falling to around 48 GW the following year, the analyst said. In total, the wind, solar and storage resource buildout by 2030 will be 23% below forecasts prior to the Trump administration’s One Big Beautiful Bill Act. 

The large drop in 2028 will stem from the effects of recent federal policies that will be seen more broadly by that time, Derrick Flakoll, policy expert at BloombergNEF, said at the CEC’s Oct. 8 business meeting. Renewable energy projects are, on the contrary, forecast to increase in the next two years as developers “rush to qualify for federal subsidies,” he said. 

But when the decline happens, it will be due in part to new restrictions placed on countries designated as foreign entities of concern, Flakoll said. 

“For both clean energy manufacturing and clean energy deployment, there are penalizations for … supply chains that are tied to China,” Flakoll said. “For projects beginning in 2026, anything other than energy storage needs to be at least 40% non-Chinese … or non-Foreign Entity of Concern.” 

Although construction of renewable energy projects will drop in the coming years, the impact could have been much harder, he said. 

“One reason we only see that 23% decrease is that renewables are generally the fastest thing to get on the grid,” Flakoll said. 

Wind, solar and storage are on average faster to connect to the grid than gas turbine facilities in all markets, except MISO, he said. 

Offshore wind projects are expected to see the sharpest decline in construction. 

“We don’t really see a lot of offshore wind [projects] coming online through 2035,” Flakoll said. “For markets like California, where floating offshore wind is in early stages, we don’t really see anything happening through 2040.” 

Even though construction of clean energy projects will slow in the U.S., domestic manufacturing of utility-scale energy storage equipment is projected to increase dramatically over the next 10 years, from about 12 GWh in 2025 to more than 60 GWh in 2035. This is due in part to battery manufacturing facilities in the U.S. shifting from making batteries for electric vehicles to building batteries for energy storage. 

“There might actually be enough [battery manufacturing] to meet U.S. demand,” Flakoll said. 

CEC Vice Chair Siva Gunda asked about the cost of EV charging in California versus other parts of the U.S.  

Prices will be different for each market, such as in California versus PJM, Flakoll said. These price differences “are ultimately political choices,” he said. 

“The way that California chooses to pay for certain [energy] programs might have an effect on electricity rates,” Flakoll said. “It is [also] based on California’s changing policy landscape. … We are seeing so much policy change in California as we speak.” 

Idaho Gas Plant Capacity Approved for Calif. Utilities

At the Oct. 8 meeting, the CEC also determined that a new, planned natural gas plant in Idaho meets California’s carbon dioxide emissions requirements. The gas plant can therefore provide capacity to Lassen Municipal Utility District and the Truckee Donner Public Utility District, the CEC said in its decision. 

The CEC specifically found that the gas plant’s emission in Idaho will be below the CEC’s Emission Performance Standard for Local Publicly Owned Electric Utilities, which limits generator facilities to 1,100 pounds of CO2 per MWh of energy. 

The planned 364-MW gas plant will be built in Power County, Idaho and owned by the Utah Associated Municipal Power Systems. It will provide about 7 MW of capacity to Lassen and 5.25 MW to Truckee, with both 30-year contracts starting on July 1, 2031. 

Posted on

NYISO Reliability Plan Calls for ‘New Dispatchable Generation’

NYISO released an updated draft of its Comprehensive Reliability Plan for 2025-2034 that calls for the acceleration of new generation development and preservation of “critical, dispatchable capability.”

“New York’s electric system faces an era of profound reliability challenges as resource retirements accelerate, economic development drives demand growth and project delays undermine confidence in future supply,” NYISO writes in the plan’s conclusion. “While this 2025-2034 CRP … identifies no actionable reliability need, this outcome should not be mistaken for long-term system adequacy. The margin for error is extremely narrow.”

This is from the broad range of scenarios for load growth, generation retirement and new generation construction. The majority of NYISO’s scenarios forecast statewide reserve margin declines. (See NYISO Dogged by Uncertainty in Comprehensive Reliability Plan.)

“In the best-case scenario we might have a reliability margin of 2,000 MW,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group on Oct. 7. “Worst case, we could be deficient by 10,000 MW.”

The ISO is calling for “several thousand megawatts of new dispatchable generation” by the 2030s.

“Depending on the load and the way that demand grows, the projected [amount] of green generation may not be enough,” Altman said. “Storage and renewables help, but they don’t get us all the way there.”

Environmental stakeholders at the meeting said this amounts to a call for new fossil fuel generation without outright saying it. But Matt Schwall, director of regulatory affairs for Alpha Generation, noted that NYISO did not “parse words” in its comments on New York’s draft State Energy Plan. “They clearly indicate there’s a need for fossil fuel-based generation: retention of existing and installation of new.”

He went on to say that if the word “dispatchable” was an issue, then maybe the term that should be used is “fossil fuel generation.”

“Well, I would ask for the empirical basis of that as well,” replied Michael Lenoff, an attorney representing Earthjustice.

Another stakeholder asked whether the ISO could highlight a “maybe not probable,” but possible, scenario where the reserve margin slips as soon as 2028. The stakeholder said that such a scenario was critical for evaluating the risks to the grid over the next five years.

NYISO recommends that reliability planning move away from a “reactive posture” toward a more proactive approach. The ISO’s preliminary recommendations include:

    • accounting for a wider range of outcomes in reliability planning rather than relying on a single “expected future”;
    • strengthening reliability planning beyond reliance on emergency measures;
    • including more approaches to address resource shortfalls beyond additional transmission planning; and
    • addressing system voltage performance issues from changes in flow patterns caused by distributed generation and large upstate loads.

NYISO said these recommendations may require changes to its planning process manual and tariff, which it plans to discuss with stakeholders in upcoming meetings.

Posted on

WPP Board Declines to Delay WRAP ‘Binding’ Phase Commitment Deadline

The Western Power Pool’s Board of Directors has denied PacifiCorp’s request to postpone the deadline by which Western Resource Adequacy Program (WRAP) participants must commit to the first “binding” phase of the program, scheduled for winter 2027/28. 

The board’s rejection comes just three weeks before the Oct. 31 commitment deadline and likely adds to the uncertainty building around how many participants could abandon the WRAP before it enters its penalty phase. NV Energy has already notified the Public Utilities Commission of Nevada of its intent to withdraw from the program. (See NV Energy to Withdraw from WRAP.) 

PacifiCorp CEO Cindy Crane requested a one-year postponement of the deadline in a letter to the board Sept. 30. She contended that the WRAP’s Day-Ahead Markets and Planning Reserve Margin task forces have identified critical issues that have emerged since the program was launched in 2020 — including challenges stemming from the split between participants choosing to join either CAISO’s Extended Day-Ahead Market or SPP’s Markets+. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.) 

In rejecting PacifiCorp’s request, WPP board Chair Bill Drummond said the board determined a delay would have a “detrimental effect” on the WRAP and its participants. 

“Delaying the participant decision deadline or the start of binding operations adds uncertainty, undermines confidence in our data and modeling, limits program compliance and stifles unlocking the full benefits of the program, which can only come with the certainty of binding operations,” Drummond said Oct. 8 in a letter addressed to Crane. 

Drummond added that the board “does not believe that the unilateral board action requested by PacifiCorp aligns with the tenets or the spirit of the established governance process, and driving such a request through the process contemplated by the [WRAP] tariff is not feasible with so little time before the decision deadline.” 

He said the voluntary nature of the WRAP “necessitates a bottom-up, member-driven process to make changes that will affect all participants in the program.” 

Drummond also noted that in September, 11 WRAP members “with substantial load, resources and geographic diversity” affirmed their commitment to the winter 2027/28 binding phase, a development that created “critical mass to move forward with confidence.” (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.) 

“Any further delay would jeopardize this critical progress,” Drummond wrote. 

Ten of those 11 members have already committed to joining Markets+, which requires its participants to join the WRAP. Starting in 2026, PacifiCorp will be the first participant in the EDAM, which has no RA program requirement. 

Addressing a second request by Crane, Drummond said WPP will continue to work with stakeholders to refine the design of the WRAP, pointing to “work underway to optimize the program in response to suggestions from participants, including task forces addressing some of the challenges you raised in your letter. These efforts are following the same governance process I referenced earlier.” 

Drummond acknowledged that his response might not satisfy PacifiCorp’s concerns about the WRAP and that the utility “may need to provide notice this month of intent to exit the program” before the first binding season. He said the program’s two-year exit notice means exiting participants continue to comply with the WRAP and remain able to engage in the stakeholder process. 

Asked to comment on Drummond’s letter and on whether the board’s response would mean PacifiCorp will not commit to the WRAP binding phase by the end of October, company spokesperson Omar Granados told RTO Insider: “PacifiCorp appreciates the Western Power Pool and its leadership in addressing resource adequacy in the West. We understand the constraints under which WPP is operating. 

“PacifiCorp remains committed to resolving resource adequacy challenges and engaging with regional partners to identify the best long-term solutions for our customers. With this in mind, we will use the time between now and the deadline to determine the best course of action.” 

Posted on

ISO-NE Reveals 1st Details of Long-term Transmission Proposals

ISO-NE received six proposals from four different companies in response to its request for proposals to address transmission constraints and interconnect onshore wind in Maine, COO Vamsi Chadalavada told the NEPOOL Participants Committee on Oct. 9.

The costs of the proposals range from about $960 million to $4.04 billion, Chadalavada said. Three of the proposals primarily rely on AC transmission, and three rely on HVDC, he added.

Despite ISO-NE’s attempts to standardize the cost calculation requirements, some of the proposals include the cost of corollary upgrades in their price estimates, Chadalavada said. The RTO will attempt to “create an even playing field” between proposals that included corollary upgrade costs and those that did not, he added.

The Longer-Term Transmission Planning procurement requires proposals to increase the capacity of the Maine-New Hampshire interface to 3,000 MW and the Surowiec-South interface to 3,200 MW, and support the interconnection of at least 1,200 MW of onshore wind in Northern Maine. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

Chadalavada said all proposals claim to meet these basic requirements and that ISO-NE received proposals to increase the Maine-New Hampshire interface to 3,600 MW and Surowiec-South to 3,800 MW.

The Maine-New Hampshire interface currently is limited to 2,000 MW, while Surowiec-South is limited to 1,800 MW. When the New England Clean Energy Connect (NECEC) line comes online — potentially around the end of 2025 — ISO-NE plans to increase the transfer limit of Maine-New Hampshire to 2,200 MW and Surowiec-South to 2,800 because of the upgrades associated with NECEC.

Also at the PC meeting, Chadalavada discussed market operations and performance, noting that energy market costs totaled $358 million in September (based on data through Sept. 30), an increase from $321 million in September 2024.

He said a planned transmission outage from mid-October to mid-November will limit flows from New York to New England to about 1,000 MW and flows from New England to New York to between 500 and 600 MW.

Responding to a stakeholder question about expected power imports from Québec in the coming winter, Chadalavada said ISO-NE’s “expectation is that we are going to see a reduced volume of imports, consistent with the past few years, but when we face really cold conditions, we expect the ties to be fully utilized.”

Imports from Québec have dropped significantly since early 2023, largely because of prolonged drought conditions in the province. Despite the significant reduction in total import volume, Hydro-Québec has continued to send large amounts of power during high-price periods in New England and has earned significant Pay-for-Performance credits in recent capacity scarcity events. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)

The PC also voted to approve planning procedure and operating procedure changes, including changes that set the load power factor ranges throughout the region. The revisions are “designed to address growing concerns around light-load and high-voltage conditions as the quantity of distributed energy resources on the New England system continues to increase.”

Posted on

European Regulator Issues ‘Factual Report’ on Iberian Outages

A new report from Europe’s electric grid regulator has revealed new details about the continent’s power system during April’s mass outages in Spain and Portugal, but insight into the causes of the blackout will have to wait for a follow-up report to be issued in 2026. 

The “Grid Incident in Spain and Portugal on 28 April 2025” document, issued Oct. 3 by the European Network of Transmission System Operators (ENTSO-E), constitutes “a factual record to transparently inform stakeholders and governance bodies” and not an assignment of blame for the mass outages. ENTSO-E is an association of 40 transmission system operators (TSO) spanning 36 European countries. 

The outage began the afternoon of April 28 and left the entire population of Spain and Portugal, as well as parts of France, without power for up to 18 hours. Spain’s government and grid operator Red Electrica released separate reports in June concluding the blackouts occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from frequency oscillations exacerbated by a faulty power plant controller.  

Reviewing those reports, U.S. experts — including NERC Chief Engineer Mark Lauby — said the U.S. grid was unlikely to suffer similar challenges because of reliability requirements put in place by FERC and NERC. Lauby said NERC would have to wait for ENTSO-E’s report “to gain any [further] insights into the incident. (See Lauby Says U.S. ‘On the Right Track’ After Iberian Blackout.) 

An expert panel comprising representatives of affected and non-affected transmission system operators (TSOs), national regulatory authorities, regional coordination centers (RCCs) and the European Union’s Agency for the Cooperation of Energy Regulators wrote the report. ENTSO-E set up the panel May 12 to review the outages as required by the EU’s Incident Classification Scale methodology after an event is classified as a Scale 3 incident, meaning termination of operation of part or all of a TSO’s transmission system. 

Red Electrica, Redes Elétrica Nacional and Réseau de Transport d’Électricité — the TSOs for Spain, Portugal and France, respectively — provided input and suggestions for specific chapters but did not act as primary authors for the chapters on their regions. The report’s authors wrote that this was “to ensure the neutrality of the reports delivered by the expert panel.” 

‘Systems Collapsed’

According to ENTSO-E’s report, at 9 a.m. the day of the incident, Spain’s electric grid began to display increasing variability in voltage. These variations were not significant until shortly after 10:30 a.m., when voltage briefly exceeded 430 kV in part of the 400-kV transmission network. 

When the outages began at 12:32 p.m., the voltage of the 400-kV network was below 420 kV and no oscillations with amplitude higher than 20 MHz were observed. Between 12:32:00 and 12:32:57, 208 MW worth of distributed wind and solar generators in southern Spain tripped offline, while distribution grids experienced a rise in net load of about 317 MW. The report’s authors did not identify a cause of this increase but theorized it “might be due to the disconnection of small embedded generators [of less than] 1 MW or to an actual increase in load,” or both. 

Major disconnection events occurred from 12:32:57 to 12:33:18 in the Granada, Badajoz, Sevilla, Segovia, Huelva and Cáceres regions, leading to an additional loss of at least 2 GW of generation. The reason for most of these trips is not known, though the report attributed an unspecified amount to over-voltage protection.  

No generation trips had been observed in Portugal or France up to this point. That changed between 12:33:18 and 12:33:21, when a sharp voltage increase in southern Spain bled over into Portugal, triggering “a cascade of generation losses that caused the frequency of the Spanish and Portuguese power system to decline.” Both countries’ grids began to lose synchronism with the rest of the European power system at 12:33:19.  

At that point, the automatic load shedding and system defense plans of Spain and Portugal were activated but could not prevent the ongoing collapse of the Iberian grid. At 12:33:20, the AC interconnection to Morocco tripped due to underfrequency, and a second later, protection devices disabled the AC overhead lines between France and Spain. Finally, the HVDC lines transmitting power from Spain to France tripped at 12:33:23 and “all system parameters of the Spanish and Portuguese electricity systems collapsed.” 

The French grid was “marginally affected,” according to the report. France experienced load loss of about 7 MW, and one nuclear power plant tripped offline during the incident. 

A review of RCC data indicated the grid was considered secure at the time of the event and no major issues were known. No congestion had been detected on the Iberian transmission network, and the available production capacity was believed to be sufficient for expected consumption. 

In an email to ERO Insider, Lauby wrote that NERC is reviewing ENTSO-E’s factual report and waiting for the regulator to issue its final report on the root causes of the outage, which is being developed by the same panel and expected in the first quarter of 2026. Lauby called this timeline “typical” for detailed system studies. 

“Overall, the lessons learned have not yet changed — that is, to ensure the actions taken to manage oscillations do not exacerbate the ability [to] manage voltage on the system [and] that generating resources should be enabled to provide dynamic voltage support,” Lauby wrote.