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January 29, 2026

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SPP Waits on FERC Order to Refund Z2 Credits

SPP staff say they still are waiting for an order from FERC before they can begin distributing millions of dollars in compensation to transmission upgrade sponsors from its beleaguered Attachment Z2 process and unwinding billions of dollars in settlements.

The numbers are huge.

The grid operator says it owes about $147 million in refunds, plus an additional $46 million or so in interest to transmission users that made payments under the Z2 process as far back as 18 years ago. It says it also will have to unwind and recalculate more than $20 billion in market settlements dating back to 2015 to resettle that Z2 activity.

Only about 1 to 2% of the latter resettlements are related to the Z2 process, staff told stakeholders during a Jan. 26 virtual meeting.

“This will impact both network and point-to-point activities, so if you’re a transmission customer or transmission owner, you will be impacted, most likely,” said Steve Davis, SPP’s settlements manager. “It’s a large mountain that we’re chiseling away to have a smaller impact.”

That mountain has grown to Everest proportions since 2008, when SPP received FERC’s approval for its tariff attachment that awards credits to sponsors from upgrade sponsors whose service could not be provided “but for” the upgrade. The attachment also required the RTO to invoice the charges monthly and to make any adjustments within one year.

However, software problems delayed Z2’s final implementation for eight years before 2016, during which the RTO did not invoice any upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 activity from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

SPP General Counsel Paul Suskie has called the Z2 resettlement headache “the most litigated, drawn-out process we’ve ever had.”

The RTO proposed a solution to unwind credit payment obligations assessed under Z2 and made an informational filing at FERC in 2024. In September, the commission ordered the grid operator to make a compliance filing for the proposal. (See FERC Requires Additional Z2 Filing from SPP.)

SPP answered with a filing in November (ER16-1341). It also issued updated refund balances with accrued interest to entities affected by FERC’s remand.

The commission has yet to respond to that filing.

Asked when SPP expects to see the commission’s order, Davis said, “I wish I knew, and that’s probably the best answer we could give. We would love it to be tomorrow, but honestly, I don’t know that we have any indication from FERC.”

SPP’s Charles Locke reminded stakeholders that FERC’s initial order in the proceeding indicated SPP was not to act on the Z2 refunds “until it was specifically authorized to do so by FERC.”

Davis said whenever a favorable order comes, “We plan on hitting the ground running.”

About a month after FERC’s order, SPP will issue final invoices for the refund period. Staff then will complete and deploy an interim Z2 resettlement system and calculate and administer the revised credit payment obligations.

When that process is complete — about eight to 12 months, SPP says — resettlement invoices will be issued for the 2015-2020 operating days. Staff said more than $580 million in Z2 credits have been applied since Sept. 1, 2015; undoing and refunding those historical settlements will require recalculating each operating day since, a process projected to take about two years.

“I keep calling it ‘reshaking of the snow globe,’” Davis said. “We have to recalculate inputs into the Z2 process as if the 2009 period through the September 2015 really never happened.”

Market participants facing big bills will be able to take advantage of a five-year payment plan, using FERC’s interest rate. The commission’s rate for the first quarter of 2026 is 7.20%.

At some point, SPP will transition to the current settlement system for production invoices. Additional resettlements will be run on that system monthly, with staff expecting to resettle three historical operating months each month. They expect to be in sync with normal monthly settlements in 2031.

Ironically, SPP no longer uses the Z2 process. Stakeholders recommended, and the grid operator approved, eliminating Z2 credits in 2020 and replaced them with incremental long-term congestion rights (ILTCRs) for new upgrades. The ILTCRs will limit total compensation to each upgrade’s directly assigned upgrade costs and interest.

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New England Power Demand Grew for 2nd Straight Year in 2025

After years of declining or stagnant power demand in New England, annual energy demand ticked up for the second straight year in 2025, potentially indicating the start of a broader upward trend.

Total system demand grew by about 0.8% in 2025, while in-region power production increased by about 2.8%, according to RTO Insider’s review of data recently released by ISO-NE. Over the past two years, total energy demand has increased by about 2.6%, and in June 2025, the region experienced its highest peak load since 2013.

From the early 2000s through 2023, net energy for load in New England steadily declined because of energy efficiency investments and the growth of behind-the-meter solar. But ISO-NE expects electrification of heating and transportation to reverse this trend and predicts that annual energy demand will increase by 11.4% from 2025 to 2034, accompanied by a more than 2-GW increase in peak load. By 2050, ISO-NE forecasts peak load reaching up to 57 GW. (See ISO-NE’s Final 10-year Demand Forecast Tapers Expectations and ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

These forecasts generally do not account for potential data center demand growth, which could add an additional significant source of demand growth. While high power prices have largely kept developers of large-scale data centers away from the region, its largest electric utilities have indicated an uptick in interest in large load interconnections from developers.

As demand increased in the past year, net imports from Québec declined by about 54%. 2025 marks the third straight year with a significant decline in imports from the province. Net imports accounted for just 2% of energy in the region in 2025, compared to an average of over 11% between 2014 and 2022.

New England annual imports from Quebec | © RTO Insider LLC

The decline in net imports appears to be driven in part by an ongoing multiyear drought affecting hydropower reservoirs in Québec. According to data from the energy consulting firm McCullough Research, the combined energy content at three of Hydro-Québec’s largest reservoirs entered the winter at its lowest point in the last six years. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)

Hydro-Québec has said it reduced its exports in the leadup to the New England Clean Energy Connect (NECEC) and Champlain Hudson Power Express (CHPE) transmission projects coming online. Both lines include significant supply obligations for the company. NECEC began commercial operations Jan. 16, while CHPE expects to come online by midyear.

It is unclear how the NECEC line will impact New England’s net imports from Québec. While Hydro-Québec has signed 20-year supply contracts with Massachusetts electric utilities for firm power at a fixed price, it is not prohibited from simultaneously importing power from New England on other lines.

While Hydro-Québec plans to make significant long-term investments to add renewable capacity and increase hydropower production, it has a slim reserve margin for the current winter, and reliability issues in the province have forced it to cut or reduce supply along the line for extended periods over the past five days. The contracted supply is not associated with new capacity supply obligations with ISO-NE, but the company faces penalties by Massachusetts for supply interruptions on the line. (See Hydro-Québec Halted NECEC Deliveries amid Reliability Concerns.)

Increased generation from gas, oil, wind, solar and nuclear resources helped fill the gap left by the decline in imports from Québec.

Nuclear and wind power saw the biggest year-over-year growth, both increasing by over 1,000 GWh. The region’s nuclear fleet produced at its highest level since 2019, the year the Pilgrim Nuclear Power Station closed.

New England annual wind and solar generation | © RTO Insider LLC

Wind power in the region saw a boost as Vineyard Wind ramped up power production in the latter half of 2025. By the end of the year, the 800-MW project had reached about 72% of its production capability. Wind power should be in line for another big year in 2026 if Vineyard and Revolution Wind are both able to complete construction. Revolution is in the late stages of construction but has yet to start producing power. Both projects have obtained stays on the Trump administration’s December stop-work order.

Wind and solar power each accounted for about 4% of total energy in 2025. Solar production increased modestly, by about 6%. This does not include behind-the-meter solar, which has grown significantly in recent years and is the largest category of solar in the region. ISO-NE’s most recent load forecast projected behind-the-meter solar providing 6,316 GWh of energy in 2025, compared to the 4,836 GWh provided by front-of-meter solar during the year.

Oil-fired generation also spiked significantly in 2025. About 80% of this use occurred in January, February or December. The region’s reliance on oil tends to be concentrated during high-demand winter periods when generators have limited access to pipeline gas. Over the past week, sustained cold weather has caused generators to rely heavily on their stored fuel inventories, with oil frequently meeting about a third of energy demand in the region.

Despite the region’s heavy reliance on oil when temperatures drop, oil-fired generation accounted for less than 1% of total energy in 2025.

Gas generation in New England hit another record in 2025, increasing by about 0.8%. Annual gas generation in New England has increased by 21.4% since 2020.

New England annual gas generation | © RTO Insider LLC

The increased reliance on gas and oil generation contributed to an annual increase in power system carbon emissions. Based on data through Nov. 30, ISO-NE estimates that annual emissions rose by about 2%.

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Oregon PUC Probes PGE on Data Center Cost-sharing Proposals

The Oregon Public Utility Commission questioned Portland General Electric’s proposals concerning grid infrastructure cost allocation for data centers, voicing concern that the utility risked prioritizing data centers over other customers.

The Oregon PUC held the hearing under docket UM 2377, which it created in March 2025 to investigate the impact that large loads have on other customers. But with Oregon legislators passing the POWER Act in 2025, UM 2377 has become a first step in rolling out the law.

The POWER Act aims to create a separate customer category for large energy users, such as data centers, and require those users to pay a proportionate share of their infrastructure and energy costs. The law defines a large energy use facility as one that uses more than 20 MW. It applies only to Oregon’s investor-owned utilities. (See Oregon House Passes Bill to Shift Energy Costs onto Data Centers.)

The Jan. 21 hearing focused on PGE’s written testimony submitted on Dec. 19.

PGE wrote that it aims to create a “durable, transparent and equitable rate structure that fairly allocates growth-related costs to the customers driving system growth, whether they are large loads such as data centers or residential demand from increasing use of air conditioning, so that each customer class pays for the costs it causes and the system benefits it receives.”

PUC Chair Letha Tawney asked for clarification on PGE’s proposal, including its proposal to continue to offer an opt-in approach for grid flexibility from data centers.

Tawney asked why the utility is sticking to its voluntary flexibility approach instead of implementing a mandatory requirement to tackle potential “scarcity events” that can impact the system and other customers.

“Your proposition is the opt-in is working: We shouldn’t worry about mandating something,” Tawney said. “I guess I’m really concerned about grid constraints driving pricing and reliability events, truly. So, why should I have confidence that the opt-in is sufficient, as opposed to mandating, from a reliability perspective, that this flexibility has to be on the table?”

In exchange for flexibility, PGE offers data center developers “speed to market,” which has resulted in “very aggressive flexibility proposals,” PGE’s Isaac Barrow replied.

Barrow contended that the opt-in approach has led to “significant resources [at] zero cost to the utility or any other participant, to provide the most benefit.”

“There is also a technical challenge, because it is very bespoke,” Barrow said. “I’m not sure what requirements you could bring forward that would allow that specific optimization of the flexibility proposals.”

Tawney also asked how PGE’s proposals could impact other customers’ compliance with Oregon House Bill 2021, which directs the state’s investor-owned utilities to reduce greenhouse gas emissions by 80% by 2030, on the path to achieving 100% GHG-free generation by 2040. (See Clean Energy, Equity Goals to Reshape Oregon IRP Process.)

PGE has proposed implementing a Peak Growth Modifier (PGM), a methodology to allocate fixed generation and transmission costs to customer classes based on their contribution to peak load growth.

“I am concerned that there is a limited universe of large-scale clean energy projects that are well priced and have reasonable commercial online dates, have interconnection agreements signed and some sort of line of sight to actually energizing,” Tawney said.

She asked how the PGM could address the potential of large loads consuming lower-cost generation resources while leaving residential customers with higher-cost options for HB 2021 compliance.

PGE has proposed new special contracts aimed at allowing large load customers to accelerate buildout of clean energy on the grid with the idea that it would “only be the resources that are left over from an RFP process, allowing for the best projects to go to our cost-of-service customers,” according to Jacquelyn Ferchland, senior manager of rates and regulatory affairs at PGE.

Barrow added that the special contracts would address effective load carrying capability and “what is the appropriate risk allocation for underproduction as well as overproduction of the specific contracted asset.”

He noted that if PGE does not serve data centers within the HB 2021 framework, other entities without decarbonization requirements may take over.

“With the demand we’re seeing, if … PGE does not serve these entities within our service portfolio, within the protections of House Bill 2021, there is a strong potential that they get served by an entity that does not have decarbonization as to the greenhouse gas requirements or is not subject to the Power Act or House Bill 2021,” Barrow said.

Financial Concerns

The hearing also touched on the financial pressure from buildout of resources to meet demand from data center customers.

Although tools like Contributions in Aid of Construction could alleviate some of the pressure, that might not be enough, Tawney said. She noted the risk of PGE running out of capital for other projects.

PGE keeps the balance sheet in mind, which is why the utility does not build at the speed data center customers would like, according to Ferchland. PGE’s flexibility approach and special contracts aim to allow data centers to connect to the utility’s system faster, she said.

“But otherwise, we are concerned about pressure on our balance sheet, and we would want to make sure that we move only as quickly as appropriate to ensure that our balance sheet remains healthy,” Ferchland said.

“I am concerned that you’re articulating a pacing based on your financial situation that I’m not seeing in the tariff,” Tawney said. “And I’m not understanding how you would be able to accomplish without sort of being accused of a discriminatory behavior towards a particular customer. So, understanding that would be really helpful.”

The commission’s final order is due by April 30, 2026, according to the docket.

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Judge Lifts Stop-work Order Against Vineyard Wind

A judge has lifted the federal stop-work order on Vineyard Wind 1, allowing work to resume on the long-running, nearly completed Massachusetts offshore wind project.

The Jan. 27 ruling by the U.S. District Court for Massachusetts (1:26-cv-10156) is the latest legal setback for the Trump administration’s campaign against offshore wind, which culminated in a Dec. 22 blanket stop-work order that cited national security concerns. (See All U.S. Offshore Wind Construction Halted and Offshore Wind Developers Fight to get Back in the Water.)

Four of the five facilities under construction in U.S. waters have won permission in January from four federal judges to resume work.

The fifth, Sunrise Wind, is set for a Feb. 2 hearing on its request for a preliminary injunction (1:26-cv-00028) before the same judge who granted Revolution Wind’s request for a preliminary injunction Jan. 12. (See Judge Again Lifts Revolution Wind Stop-work Order.)

Empire Wind and Coastal Virginia Offshore Wind also have secured injunctions. (See Judge Allows Construction to Resume on Empire Wind and Dominion Wins Injunction, Can Restart Offshore Wind Construction.)

Vineyard was the last of the five projects to request an injunction, waiting until Jan. 15 to file in court. Later Jan. 27, after the injunction was issued, Vineyard said it “will continue to work with the administration to understand the matters raised in the [stop-work] order.”

“Vineyard Wind will focus on working in coordination with its contractors, the federal government, and other relevant stakeholders and authorities to safely restart activities as it continues to deliver a critical source of new power to the New England region,” it added.

The 62-turbine, 800-MW Vineyard Wind 1 is a joint venture of Avangrid and Copenhagen Infrastructure Partners that put its first steel in the water in June 2023. It was far behind its original schedule even before the stop-work order, but it is nearly complete and has begun sending power to the grid.

The impact of the stop-work order has extended beyond the developers themselves.

GE Vernova, the manufacturer of the turbines and blades being installed off the south coast of Massachusetts, said Jan. 28 that the federal stop-work order contributed to the $225 million loss the company’s wind business recorded in the fourth quarter of 2025.

CFO Ken Parks said during an earnings call that one turbine is left to be installed and 10 need blades installed.

If GE Vernova does not install these components before March 31, he said, it will lose access to the installation vessel needed for the work. If it cannot install the equipment, it cannot bill the developer for the work, potentially resulting in a $250 million loss in 2026, he said.

For this and other reasons, the wind business will record a $600 million loss for 2025, 50% more than the $400 million predicted in early December, giving it a ‑6.6% EBITDA margin for the year.

GE Vernova’s two other component businesses fared much better: Power recorded 52% more orders and 10% more revenue in 2025 than in 2024 and boosted its EBITDA margin to 14.7%. Electrification recorded 21% more orders and 26% more revenue year over year and bumped its EBITDA margin up to 14.9%.

U.S. Sens. Ed Markey and Elizabeth Warren (D-Mass.) welcomed the Jan. 27 injunction.

“This stay is an important step in the process to fight back against the Trump administration’s lawless attacks against our union jobs, grid security and energy affordability,” they said. “Vineyard Wind 1 is currently delivering affordable and reliable power into our grid and has the permits, financing and approval to deliver even more. Shutting off Vineyard Wind 1 would kill thousands of local union jobs, prevent power from reaching 400,000 homes, and cause us to lose out on $3 billion of energy savings.”

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Regulators: MISO Stakeholders Should Decide Cost-sharing for DOE Coal Plant Orders

State regulators in MISO asked FERC to let power industry stakeholders determine how to allocate the costs of an Indiana coal plant forced to stay online by the Trump administration’s Department of Energy.

The Organization of MISO States (OMS) said the RTO’s stakeholders and regulators should decide on now to divvy up the costs of sustaining operations at thermal plants whose retirements are delayed under emergency orders issued by DOE under Section 202(c) of the Federal Power Act.

Northern Indiana Public Service Co. — whose units 17 and 18 at its R.M. Schahfer Generating Station are under such orders through March 23 — filed in late 2025 to recover costs of running the plant from MISO Midwest participants (EL26-36). (See Enviros Warn NIPSCO Against Rebuilding Coal Unit on DOE Emergency Order.)

FERC previously approved a cost allocation plan for MISO Midwest entities to split the expenses of running the J.H. Campbell coal plant in Michigan — another of a handful of aging thermal plants set to retire that DOE says can’t be spared due to reliability concerns.

OMS said instead of applying a similar allocation, FERC this time should task MISO with engaging its member states and stakeholders to design a cost allocation for the Schahfer units. If FERC decides against that avenue, it should open NIPSCO’s request for an allocation plan to a hearing that weighs anticipated rate impacts and provides opportunity for comments from affected states and customers, OMS said.

“In either case, OMS stresses that any ultimate cost assignment that results from this proceeding should be based on a clear demonstration of need and commensurate with benefits received to help mitigate unintended consequences,” OMS wrote.

OMS said if FERC continues to allow the costs of emergency orders to be allocated across MISO Midwest, generation owners could start to exploit a predictable outcome.

“If the commission routinely approves broad regional cost allocation for 202(c) order costs without a demonstrated, commensurate benefit, utilities may be incentivized to accelerate retirements and cash in on a 202(c) order cost shift, moving costs away from local customers and onto an 11-state region,” OMS wrote in Jan. 20 comments to FERC.

The regulators’ group said DOE’s “self-determined energy emergency does not obviate the commission’s obligation to establish just and reasonable rates.” It said a cost allocation design should be “equitable and durable,” especially because DOE is likely to order other retiring thermal units to stay in service.

OMS noted also that while FERC regulates wholesale markets and interstate transmission, “states are responsible for determining what generation is needed, where it is located, how it is financed and whether it is prudent to serve retail customers.”

OMS said NIPSCO’s proposal would spread Schahfer expenses broadly across MISO Midwest, even to customers who won’t experience any reliability benefit, “including Indiana.” The group noted that PJM, its member states and stakeholders were allowed to develop a cost-recovery plan last year when DOE ordered Constellation Energy’s Eddystone Generating Station to keep running.

Multiple OMS members abstained from the vote to submit the comments, including the Arkansas Public Service Commission, the Louisiana Public Service Commission, the Mississippi Public Service Commission, the New Orleans City Council, the Public Utility Commission of Texas, and, interestingly, the Indiana Utility Regulatory Commission.

FERC has already rejected similar requests in the case of the J.H. Campbell coal plant when it decided in late summer 2025 that costs should be spread across MISO Midwest. Those costs have risen to $80 million and climbing after three emergency orders. (See FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States and J.H. Campbell Tab Rises to $80M on DOE’s Stay Open Orders.)

Consulting Firm Predicts Tens of Millions in Costs

Keeping Schahfer units 17 and 18 operating is likely to come with steep costs. Synapse Energy Economics estimated that DOE’s initial 90-day extension of the trio of Indiana coal plants under emergency orders — the Schahfer units and CenterPoint’s Culley Unit 2 — would cost $20.6 million under economic commitment practices. Schahfer would account for the lion’s share of the cost, which could rise significantly, the consulting firm found.

“If DOE extends the order long term, we estimate the coal units would require an additional $33.7 million per year in capital expenditures to replace equipment as it wears out and install environmental controls to maintain compliance with environmental regulations,” Synapse wrote in a report prepared for Earthjustice, Sierra Club and the Environmental Law and Policy Center.

All three units were to retire at the end of 2025.

Synapse’s numbers don’t account for the extensive turbine repairs NIPSCO has said Schahfer Unit 18 requires immediately before becoming available for dispatch. NIPSCO officials have said that work could take six months or more.

The Illinois Commerce Commission likewise asked FERC to give states and stakeholders space to asses a suitable cost-recovery for the Culley unit under CenterPoint’s complaint for a cost allocation mechanism (EL26-38). The ICC said DOE’s orders are becoming “routine” and order issuances could go on for years.

“The likely frequency and length of these orders, much longer than [an] initial 90-day period, is crucial in considering how to handle cost allocation for generating units that are unexpectedly and unnecessarily being retained on the system,” ICC wrote in Jan. 23 comments to FERC.

The state commission said given the “volume of DOE 202(c) orders, and the potential harmful impacts on ratepayers across the MISO region, a robust stakeholder process is needed.” It said DOE’s continued orders to retiring coal plants will “result in significant, but currently unknown costs with unknown benefits.”

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MISO Pushes Interconnection Queue Timelines Back Again

MISO announced further delays in its generator interconnection queue for the cycles of projects that entered in 2022, 2023 and 2025.

The grid operator said it does not expect to complete the second phase of studies for 2022 project entries until May 7, 2026. MISO similarly said 2023 project entries would not finish second phase studies until Sept. 3, 2026. The RTO conducts its interconnection studies in three phases.

The updated timeline is months behind what MISO originally said it could manage as it rolled out a new, automated study process.

In early 2025, MISO hoped to have all generation projects in the 2022, 2023 and 2025 cycles striking interconnection agreements over 2026, with 2025 project entries finishing up by year-end. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Now, MISO does not expect the 2022 cycle of projects to execute generation agreements until early January 2027. The 2023 cycle would follow in late March 2027.

MISO reported that the 2022 class of generation hopefuls are experiencing modeling delays across all regions.

“We’re still so bogged down by previous cycles and restudies and the backlog churn,” Senior Manager of Resource Utilization Kyle Trotter explained at a meeting of the Interconnection Process Working Group on Jan. 27. “We have ’21, ’22, ’23 and ’25 all in flight at the same time.”

MISO is nearing completion on its 2021 cycle, save for a cascading model delay for projects located in its Central region.

The later timeline leaves the 2025 cycle of projects pushed later as well, though MISO has yet to estimate realistic dates. The RTO’s most recent queue processing chart targets the 2025 cycle’s dates according to the scheduling prescribed by FERC Order 2023. If MISO were to follow that, it would have to complete the second study phase by mid-July and sign interconnection agreements in early February 2027, months ahead of the expected wrap up of the 2023 group.

But Trotter said MISO would not begin the second batch of studies on the 2025 cycle of projects until it has sufficiently moved the 2023 cycle along. He said it would seek a waiver with FERC to delay studies for the 2025 cycle.

“We haven’t yet been in contact with FERC about it, in filing a waiver for the 2025 cycle,” Trotter said.

Trotter declined to provide more details on what exactly the RTO would request to waive. He said it is still discussing details internally with its legal team and must engage FERC before presenting its request to stakeholders.

David Ticknor, senior interconnection engineer at RES Group, reminded MISO of the importance of working quickly to approve projects so that renewables can secure federal tax credits before their discontinuation.

MISO in late 2025 refused stakeholders’ request to delay kicking off studies for the 2025 cycle to clear some of the four-year backlog before taking on more analyses. (See MISO Declines Stakeholder Ask for Pause on 2025 Queue to Clear Backlog.)

Stakeholders asked where it stands on acceptance of 2026 cycle of generation projects.

“We would project the 2026 cycle closing at the end of the year, similar to years past,” Trotter answered, adding that study kickoff would occur in early 2027.

In a related queue matter, MISO wants to standardize its collection of data from generation developers to help speed up its power flow modeling delays.

Manager of Resource Utilization Rob Lamoureux said the RTO needs rule changes to make sure it receives consistent modeling data from developers. He said it could complete studies faster and more accurately if it could draw on identical fields for modeling data.

Lamoureux said the various fields slow down MISO’s modeling and that a more regimented data collection would produce better models for Pearl Street’s SUGAR software, which the RTO is using to automate studies.

“Half of the files from ’23 and ’25 had to be manually reworked,” Lamoureux told stakeholders. He said MISO had to intervene to manually feed data into its systems for 50% of the modeling files from the 2023 cycle and 53% of files in the 2025 cycle.

He reminded stakeholders that MISO would face penalties of $1,000 to $2,500 per business day by the 2027 cycle under Order 2023 if it does not reasonably meet deadlines.

Ryan Westphal said MISO’s tariff currently permits more than a dozen formatting methods. In some cases, it receives conflicting data in redundant entries from the same developer, he said.

Lamoureux said MISO would put together a draft data standard for stakeholder review in time for the IPWG’s March 10 meeting.

“If we get these changes out soon, they could be implemented before the 2026 cycle,” he said.

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BPA Provides More Details on $5B Tx Projects

The Bonneville Power Administration provided updates on the agency’s $5 billion in transmission projects as some stakeholders asked about sunsetting of tax credits and coordination efforts with other developers in the West.

BPA staff discussed the agency’s Grid Expansion and Reinforcement Portfolio (GERP) during a Jan. 27 meeting. GERP consists of more than 20 proposed transmission line and substation projects. The initiative, previously called Evolving Grid, aims to improve transmission and reliability in the Northwest, according to the agency’s website. (See Stakeholders Seek More Details on BPA’s ‘Evolving Grid’ Projects.)

BPA launched GERP in two phases in 2023 and 2024.

GERP 1.0 includes 10 proposed projects focused on 363 miles of transmission lines at a preliminary cost of $2 billion. It includes upgrades, rebuilds and improvements to existing facilities, as well as two new substations and one new transmission line.

The projects are all proposed as they have not undergone an environmental assessment under the National Environmental Policy Act (NEPA), according to BPA’s Eric Orth.

Orth said he does not anticipate many NEPA challenges because many of the GERP 1.0 projects concern upgrades to existing facilities.

“They’re not brand-new lines going through new territory,” Orth said. “We will do our due diligence when it comes to NEPA, but I don’t anticipate any big challenges with these lines or substation projects.”

The largest upgrade under GERP 1.0 is the replacement of a 91-mile, 230-kV line with a 500-kV line between BPA’s Big Eddy substation and Pearl substation. The upgrade has a preliminary estimated cost of $670 million and an estimated completion by 2033.

Orth said staff are scoping the project.

“We are well on our way,” Orth said. “We’ve got a good plan of service, and we’re currently putting together plans to solicit the project this summer for an engineer, procure, construct contract. And so that’s exciting. That’s a big step. Essentially … the project will be at a 30% design, and we will bid that out competitively to a pool of contractors to finish the project.”

Many of the GERP 1.0 projects have an estimated completion date after Dec. 31, 2029, when federal tax credits for solar and wind projects are set to expire, according to Alex Swerzbin, vice president of power marketing and transmission at NewSun Energy.

“If these generating projects aren’t energized, they’re going to lose out on your tax credits, which could be 30, 40% tax rate and value of the project,” Swerzbin said.

Customers can help by coordinating with BPA “as projects develop through scoping and design. Many of the schedules are tied to how long it takes to procure some of the materials,” Orth said.

BPA is working on “on ways to condense schedules,” Orth said. “But I think the question is a good reminder for us to maybe go back and look at which projects are tied to some renewable generation interconnection requests and see if we can do anything with the timing.”

GERP 2.0

GERP 2.0 includes 13 proposed projects with a preliminary projected cost of $3.9 billion. BPA aims to complete GERP 1.0 projects in the next five to six years, while GERP 2.0 projects have a longer timeline. Many of the 2.0 projects build on 1.0 upgrades, BPA’s Matt Hagensen said.

One major GERP 2.0 project is the Lower Columbia NOB initiative, a three-part effort aimed at improving connectivity from the lower Columbia region to the Nevada-Oregon border with 500-kV transmission lines and a new substation near the border.

The project has a preliminary estimated cost of $1.9 billion with an estimated completion by 2035.

“It’ll help create more interregional connectivity,” Hagensen said about Lower Columbia NOB. “We do have some joint studies going on with some southern partners in Nevada that would build up to that station. And so really creating that opportunity and that resource diversity between the Northwest and the Southwest.”

Fred Heutte, senior policy associate at the NW Energy Coalition, asked about coordination with other developers, pointing to PacifiCorp’s Blueprint South project, a new 180-mile line in south-central Oregon.

Hagensen said BPA coordinates with other stakeholders through regional planning to assess how projects interact.

Heutte noted “these are multibillion dollar projects,” saying “we kind of got to get it right.”

Western regional assessments focus primarily on east-west connectivity, according to Heutte.

“I think the north-south configuration is something that really needs more attention,” he said. “So, just to say, this is a very interesting project. It has lots of big pieces and there are other forces at play here. And just to encourage Bonneville to provide more information about the discussions and studies that are being done, and again, more context, because this is a very big deal.”

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NextEra Reports Sharp Growth in Generation Portfolio, Backlog

NextEra Energy Resources brought 7.2 GW of new generation and storage into operation and added 13.5 GW to its backlog in 2025.

Both were records for the energy infrastructure developer, parent company NextEra Energy said Jan. 27 as it reported fourth-quarter and full-year financial results.

Looking forward, NextEra Energy Resources expects to bring more than 75 GW of additional capacity online through 2032: 0.6 GW of nuclear, 4 to 8 GW of natural gas, 8.5 to 14.5 GW of wind, 31.5 to 41.5 GW of solar and 32 to 43 GW of storage.

The nuclear addition would be the planned restart of the Duane Arnold reactor in Iowa in 2028 or 2029. The natural gas generation would not start operation until 2030 or even 2032 — a reflection of the delays surrounding new gas turbine delivery.

NextEra Energy utility subsidiary Florida Power & Light (FPL) also had a good year, making $8.9 billion in capital investments in 2025 and planning as much as $90 billion to $100 billion through 2032 to keep up with the state’s rapid growth.

FPL has had expressions of interest from developers about more than 20 GW of new large load demand and is in advanced discussions about projects representing roughly 9 GW of demand, which it could begin serving incrementally in 2028.

Each gigawatt would incur about $2 billion in capital expenses, which then would be recovered through FPL’s regulated rate of return, which will range from 10 to 12% under a new four-year rate agreement with the Florida Public Service Commission. That agreement also includes a large load tariff to protect existing customers from bearing the costs.

“As we enter a new year, we’re focused on the opportunity in front of us,” NextEra Energy CEO John Ketchum said Jan. 27 during a conference call with financial analysts. “America needs more electrons on the grid, and America needs a proven energy infrastructure builder to get the job done. That’s who we are, and that’s what we do.”

Ketchum offered other details:

    • NextEra Energy Resources is “laser-focused” on what it expects to be the dominant trend in the large load market — bring your own generation — and feels it is uniquely positioned to deliver on this, with its decades of experience, its strong balance sheet and its longstanding relationships across sectors.
    • Revenue from certain existing generation assets will be growing — 6 GW of nuclear and renewable power purchase agreements struck more than a decade ago under very different market conditions will be expiring through 2032 and the successor PPAs are expected to command higher prices during re-contracting.
    • The company has a partnership with GE Vernova that makes it confident it can secure a supply of gas turbines at a competitive price.
    • NextEra views small modular reactors (SMRs) as an important future technology, with potential for 6 GW of co-location with the company’s existing large reactors, plus additional SMRs on greenfield sites serving large loads. It has identified about a dozen companies as the most promising among the scores of potential developers in the SMR space, but it does not presently plan any partnerships and will be looking for shared risk and capped financial exposure on any SMR venture it undertakes.
    • NextEra is not sure if it will participate in the upcoming PJM backstop auction — the details need to be finalized, and regulatory and financial certainty need to be in place before such a decision can be made.

“As I look at it, with how we’re positioned around [bring your own generation], we have so many opportunities around the United States right now that that we are pursuing, but certainly we have a close, keen eye on PJM as well, and are watching to see how things play out,” Ketchum said during the call.

Solid Earnings Growth Expected

NextEra Energy reported fourth-quarter 2025 operating revenue of $6.5 billion and net income of $1.54 billion, or $0.73/share. That compares with $5.39 billion, $1.2 billion and $0.58 in the fourth quarter a year earlier.

For all of 2025, the company reported operating revenue of $27.41 billion and net income of $6.84 billion, or $3.30/share, compared with $24.75 billion, $6.95 billion and $3.37 for all of 2024.

Adjusted 2025 earnings were $3.71/share, up 8.2% over 2024.

NextEra Energy said it expects adjusted earnings per share to continue to grow at a compound annual rate greater than 8% through 2032 and will attempt to extend that streak through 2035.

The company’s stock price rose 1.97% Jan. 27 to close near its 52-week high.

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Customer Group Offers FERC Policies to Grow the Power System Affordably

FERC must balance the need to grow the grid while keeping rates affordable for customers, the Electricity Customer Alliance argues in a recent white paper laying out suggestions to thread the needle.

The authors of “A Customer-Centric Agenda for FERC” argue that the commission will play a key role in making sure the wholesale power markets are designed in way that can serve exponentially rising demand from data centers, reshoring manufacturing and electrification. It also has an important role in convening state regulators to address issues, as it has in recent years alongside National Association of Regulatory Utility Commissioners meetings.

ECA’s members are all kinds of customers, from hyperscale data centers down to consumer advocates for residential customers, and it advocates for maintaining a reliable grid while keeping rates affordable, Executive Director Jeff Dennis said in an interview.

“We see a number of issues swirling around FERC and wholesale electricity markets and the transmission grid,” Dennis said. “There’s just a lot going on out there. And our goal is really to take a lot of those issues and put them in a customer-centric framework that really connects the dots for the commission and other stakeholders around our national bipartisan goals for AI leadership, national security, economic growth and improving affordability for customers.”

So far, the impact of the return of load growth has not led to lower prices, with PJM seeing its capacity market prices surge as demand from data centers has led the market to fall short of its target reserve margin.

A big reason for the climbing prices in PJM is the load forecasts that the RTO relies on to set the curve for its capacity market, Dennis said.

“I pinpoint the load forecast because I think as we’ve seen, those load forecasts are incredibly uncertain,” he added. “PJM itself has dialed those back almost in half. And so, the challenge that we’re facing right now is we have these load forecasts that are projecting large growth.” (See Pessimistic PJM Slightly Decreases Load Forecast.)

Load forecasts include many big developments that are unlikely to be economic any time soon and can suffer from double counting as well, Dennis said.

“I think on top of that, we’re living in a world where the price signal that the capacity market produces is being felt by customers much sooner because of the delays that we’ve experienced in the auctions in PJM over the years, and so we don’t have that three years forward,” he added.

Load growth can mean lower prices for existing customers as the costs of the bulk power system are spread over a larger base. ECA’s paper argues for steps to get to that end state, where development of supply keeps pace with demand growth. The right structures for regional planning and cost allocation need to be struck to get to that state.

“We have to integrate these loads into the network in order to get those benefits,” Dennis said. “The whole goal is, if you can bring in new customers and new load below the peak, then what you’re doing is you’re taking all the existing fixed cost that the market has already invested in, and you’re spreading it over more customers, which helps bring down those costs. So, the trick is, how do you do that in a way that also isolates any incremental additions to the peak [that] these loads are making and then appropriately allocate those costs to the new loads that are driving them?”

One area where FERC is going to be able to make a quick impact on the whole set of issues is through the RTO’s compliance filings for Order 1920, which changed transmission planning and cost allocation rules.

“Customers really do value the core tenants of Order 1920 around economic regional planning to identify the best options to build transmission that meets multiple needs and get us out of this paradigm we’re in right now, where we’re building lots of local transmission for one-off reliability needs, or other things like that, that are raising costs to consumers,” Dennis said.

The commission will have to weigh the tradeoffs between getting Order 1920 in place quickly to deal with the surging load growth and the standard practice for many large-scale rule changes, where jurisdictional utilities file multiple rounds of compliance filings, he added.

FERC has held collaborative meetings with states tied to NARUC for the last several years, but Dennis said those kinds of joint federal-state boards could be created to tackle more narrow issues than they have so far.

“FERC has a really important role in bringing together federal and state policymakers and regulators around these issues to understand where there is complication in that sort of intersection and handoff between what happens in the wholesale electricity market, what happens with the transmission grid and what happens at the retail level,” he added.

Flexibility has often been discussed as a way to help data centers achieve speed-to-power, but it could bring up issues around cost allocation that would benefit from formal cooperation between FERC and the states, for example, Dennis said.

“There are opportunities to do more at a little bit more granular level than those quarterly meetings, which are very helpful as a place for them to talk about big issues,” Dennis said. “But that’s not the only thing that could be done with that authority.”

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Nevada Regulators Approve SWIP-North Construction Permit

Nevada regulators approved a construction permit for the Southwest Intertie Project-North transmission line, keeping the project on track for a 2028 operation date.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Jan. 27 to approve the permit for the project, also known as SWIP-North.

The 285-mile, 500-kV line is being developed by LS Power subsidiary Great Basin Transmission for an estimated $1 billion. It will run from the Robinson Summit substation in eastern Nevada to Idaho Power’s Midpoint substation near Twin Falls. Most of the line — 208 miles — will be in Nevada.

Mark Milburn, senior vice president of LS Power, said the PUCN permit is the final major approval needed for the transmission line.

“We continue to make steady progress on SWIP-North,” Milburn said in an emailed statement. “We plan to begin construction in 2026 and be placed in operation by 2028.”

SWIP-North is one piece of the larger Southwest Intertie Project corridor. At its south end, SWIP-North will connect to the 231-mile One Nevada (ON) line that ends near Las Vegas. The ON line in turn connects to Desert Link, also known as the Harry Allen-to-Eldorado line, which ends at Southern California Edison’s Eldorado substation.

NV Energy will be entitled to free rights for about 1,000 MW of SWIP-North capacity, or roughly half, according to Great Basin’s November 2025 application to the PUCN. CAISO and Idaho Power will have rights to the remainder.

“NV Energy can use those capacity rights to access new generation resources, support more efficient network service operations, increase participation in Western Energy Imbalance Market (WEIM) transactions, or support wholesale wheeling transactions, which can generate additional revenue or offset current charges,” Great Basin said in the application.

The completion of SWIP-North also will increase the capacity of the ON line, which has been limited by northern Nevada’s 345-kV transmission system, Great Basin said.

The PUCN approval of the SWIP-North construction permit follows FERC approval in November 2025 for incentives and a transmission owner tariff for the project. (See FERC Approves Incentives, Tariff for SWIP-North.)

In December 2025, the Idaho Public Utilities Commission granted the project a certificate of public convenience and necessity.

On its website, Idaho Power, which owns 23% of SWIP-North, recapped project benefits identified by Idaho PUC staff. Those include relieving transmission congestion in the region and delaying the need for other grid projects.

Idaho Power said SWIP-North will allow it to meet winter demand by importing electricity from the Desert Southwest, where cooler weather in winter reduces electricity demand and prices.

Idaho Power emphasized that the purpose of its SWIP-North ownership is not so it can send energy to California.

“Idaho Power’s ownership in SWIP-North only allows us to import energy from south to north,” the company said. “Our ownership stake does not involve selling energy to California or anywhere else.”