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January 28, 2026

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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.”

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CPUC Portfolio Shows Offshore Wind Delayed up to 6 Years

California’s two large offshore wind projects could be delayed by up to six years due to recent federal policy actions, a California Public Utilities Commission administrative law judge said Jan. 14.

The Morro Bay offshore wind project is now forecast to come online by 2036 rather than 2032, CPUC ALJ Julie Fitch said in a proposed decision on electric integrated resource planning and procurement. A second project, in Humboldt County, is projected to come online by 2041 rather than by 2035.

The delays are “reasonable and should be adopted as the recommendation for CAISO’s 2026-2027 Transmission Planning Process,” Fitch said in the proposed decision.

The forecasted delays are part of the CPUC’s latest electricity and sensitivity resource portfolios, which the commission sends to CAISO for inclusion in the TPP. The ISO uses each TPP to determine whether additional transmission projects are needed in its region.

Although federal policy will affect California’s offshore wind projects, regardless of these policy changes, “it is important to note that offshore wind is not optimally selected in least-cost modeling,” the proposed decision says.

Numerous parties cautioned against delaying transmission planning that would support offshore wind in Humboldt County beyond 2036.

Environmental Defense Fund told the CPUC that the offshore wind industry is “at an inflection point” and that delaying the planned projects’ online dates could cause a “significant chilling effect that would not be in the interest of ratepayers,” the proposed decision says.

CalCCA recommended the CPUC maintain the amount of in-state and offshore wind in previous TPP portfolios and limit out-of-state wind. And Humboldt County representatives questioned why the North Coast offshore wind project is delayed by six years while Central Coast is delayed only by four years, the proposed decision says.

Many other stakeholders expressed concern that the state is planning to rely heavily on new out-of-state solar development when in-state resources, such as offshore wind, would be preferable, the proposed decision says.

In October, the California Energy Commission approved $42 million for five offshore wind projects at California ports. (See CEC Approves 5 Offshore Wind Projects at California Ports.) In November, the CEC added $9.2 million more for research on deepwater HVDC transmission. (See ‘There’s Room for Everybody’: California Ports Prepare for OSW Development.)

The current TPP base case for 2025-2026 includes 4.5 GW of new offshore wind capacity.

Additional RA Procurement Proposed

Under the proposed decision, load-serving entities would need to procure an additional 2,000 MW of net qualifying capacity (NQC) by 2030 and 4,000 MW more by 2032.

This additional procurement is the result of the CEC’s 2024 Integrated Energy Policy Report demand forecast, which showed an increase in demand due to data center growth and vehicle and building electrification, and a decrease in the number of people who plan to install behind-the-meter solar and storage units.

In the CPUC’s analysis, Diablo Canyon Power Plant (DCPP) was modeled as offline in all years, and all combined heat and power plants were kept online. While it is “likely that DCPP will be online through 2030 in reality,” the proposed decision says the CPUC’s model follows the requirements of California’s Senate Bill 846, which extended the operating life of the nuclear plant.

Energy storage resources can only account for up to 50% of the additional NQC amounts under the proposed decision.

The “real winner” of the procurement order is geothermal energy, Farhad Billimoria, representative of Aurora Energy Research, told RTO Insider. With offshore wind development in the state facing continued delays, community choice aggregators will again be forced to scramble for clean firm capacity, leaving geothermal as the only realistic, if still costly, option, Billimoria said.

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New England TOs Propose Asset Condition Projects Totaling $110M

Eversource Energy and National Grid introduced asset condition projects totaling about $110 million at the ISO-NE Planning Advisory Committee meeting Jan. 27.

The proposals coincide with ISO-NE’s ongoing efforts to establish an internal asset condition reviewer. This role is intended to increase transparency into the transmission owners’ asset condition spending, which has cost the region billions in recent years. (See ISO-NE Responds to Feedback on Asset Condition Reviewer Role.)

Eversource presented a group of asset condition projects that would replace structures on six transmission lines in New Hampshire. The combined estimated costs total $101.6 million, while the expected in-service dates range from the fourth quarter of 2026 to the third quarter of 2027.

In southern New Hampshire, Eversource proposes a $32 million project on Line 367. The company would replace 97 345-kV wood structures with an average age of 55 years, along with a seven-year-old steel structure with damage from bullet holes. The estimated per-structure cost is $330,000.

Eversource’s Steve Allen noted that the company estimates the typical useful life of 115- and 345-kV natural wood structures to be 40 to 60 years.

Fifty-seven of the structures on the line require immediate replacement, while Eversource also proposes to replace the 41 other original wood structures. Replacing all original wood structures would prevent the need for an additional project “in the near future,” Allen said.

On Line A126, a 115-kV line in western New Hampshire, Eversource proposes a $7.4 million project to replace 20 wood structures with an average age of 72 years. The estimated per-structure cost is $370,000.

In southeastern New Hampshire, the company proposes to spend $38.1 million to replace 96 structures on the 115-kV A152 line. Twenty-eight of the structures need immediate replacement, while 41 structures have engineering concerns, Allen said. The average age of the wood structures is 57 years, and the estimated per-structure cost is $397,000.

Eversource proposes a $5.6 million project on the 115-kV B143 line in southern New Hampshire. The project would replace 16 wood structures at an estimated per-structure cost of $351,000. The structure ages range from 48 to 59 years.

In eastern New Hampshire, Eversource proposes a $5.5 million project on the 115-kV K174 line to replace 15 wood structures with an average age of 58 years. The company considers four of the structures to be immediate replacement needs. The estimated per-structure replacement cost is $370,000.

In central New Hampshire, the company proposes a $12.5 million project on the 115-kV M127 line. The project would replace 39 wood structures, which have an average age of 58 years, at an estimated per-structure cost of $321,000.

Allen noted that the ISO-NE 2050 Transmission Study forecasts overloads on the A152 and K174 lines, though Eversource did not identify any project modifications to address these needs. ISO-NE plans to begin stakeholder discussions about right-sizing asset condition projects in the third quarter of this year.

Eversource also presented an update on asset condition projects at two river crossings affecting several lines in Connecticut. The modifications to the design have reduced the total estimated cost by about $5.5 million. The updated combined cost estimate now totals $101.3 million.

Rafael Panos of National Grid presented a $7.3 million asset condition project to replace a pair of 61-year-old circuit breakers at a substation in Brockton, Mass. The existing breakers are deteriorating and difficult to find parts for, Panos said. The project’s estimated in-service date is May 2027.

Asset Condition Interim Review

Also at the PAC meeting, Brent Oberlin, executive director of transmission planning at ISO-NE, discussed the RTO’s interim asset condition review process. ISO-NE is working to stand up the permanent reviewer at the beginning of 2027 and is relying on an external consultant to review nine selected projects during the interim period.

The list of nine projects in the interim review is mostly unchanged from the initial list ISO-NE presented in October, though the RTO has replaced National Grid’s proposed rebuild of Line 323 in eastern Massachusetts with a different project by the company in western Massachusetts expected to cost more than $200 million. ISO-NE made the change after an outage opportunity arose for National Grid to pursue the 323 project on an earlier timeline, Oberlin said. (See ISO-NE Gives Update on Asset Condition Reviewer Role.)

ISO-NE has initiated the interim review for several projects and expects about a three-month review process for most projects on the list, he said, adding that the RTO plans to eventually present results to the PAC and “will be looking to take lessons learned and feedback on the interim process to inform the development of the permanent [asset condition] reviewer role.”

Oberlin said additional asset condition projects that are proposed in 2026 but not on the interim list will not be subject to review. Jeff Iafrati, a consultant for Customized Energy Solutions, expressed concern that this could result in TOs advancing projects for the rest of the year to avoid review.

Alex Lawton of Advanced Energy United echoed this concern, saying, “It would be more assuring if there was a bit more review for upcoming projects.”

“While it’s a possibility, I really think it’s a limited risk,” Oberlin responded.

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Beware of Unintended Consequences

By Randy Hardy

Since 2019, the Bonneville Power Administration, Pacific Northwest utilities, independent power producers and other interested parties have struggled with politically required, but operationally difficult, development of renewable/storage resources in the region.

While much of this struggle involved slower than expected generation interconnection and transmission access/construction by BPA, the dynamics behind such clean energy development are considerably more complicated. As a former BPA CEO with over 40 years of dealing with PNW energy issues, I thought a more comprehensive analysis of this situation might be helpful.

Background

In 2019 and 2021, Washington and Oregon set ambitious clean energy goals, requiring their utilities to achieve 80% clean/decarbonized energy portfolios by 2030. At that time, those states’ two main utilities, Puget Sound Energy (PSE) and Portland General Electric (PGE), were roughly 35 to 40% clean/decarbonized. Today they are only 45 to 50%. While such limited progress seems problematic, the nature of the non-ISO/RTO grid in the PNW and our specific transmission difficulties slowed renewable energy development substantially.

Geography

Northwest geography significantly complicates regional transmission development. Nearly all wind and solar sites are east of the Cascade Mountain Range, while loads are mostly in Seattle and Portland. In addition, current high-voltage cross-Cascades transmission lines are fully loaded. So devising methods to provide new transmission to PNW load centers or even upgrading existing 230-kV transmission to 500 kV across this environmentally sensitive barrier is a major challenge. I would estimate the degree of difficulty associated with overcoming this challenge, since it affects nearly all PNW renewables development, probably exceeds such geographic/environmental challenges in any other region.

BPA Generation Interconnection/Transmission Access

BPA owns and operates roughly 70% of the region’s high voltage transmission. Despite this transmission position, it operates, not as an RTO/ISO, but under FERC’s Open Access Transmission Tariff (OATT) regime. It currently has 115 GW in its generation interconnection (GI) queue and, like RTOs/ISOs in other regions, is struggling to interconnect these resources as rapidly as possible.

Unlike those entities, however, as an OATT utility it also must operate a separate transmission access process complete with its own first-come, first-served queue for providing transmission capacity to renewable resource developers and others.

Randy Hardy

BPA typically processed this queue via an annual transmission cluster study that analyzed each submitted transmission service request (TSR) and thereby provided a specific plan of service for each such project. That CS queue has increased dramatically since 2020. Specifically: 2020 CS, 4 GW; 2021 CS, 6 GW; 2022 CS, 11 GW; 2023 CS, 17 GW; and 2025 CS, 65 GW.

This recent exponential growth in TSRs has stalled BPA’s ability to analyze the 65 GW in its 2025 CS because of the multiple years required to perform such complicated power flow analyses and because the amount far exceeds any credible projection (even with data centers) of future PNW load. As a result, any project in the 2025 CS probably will not receive any long-term firm (LTF) transmission until well after 2030.

BPA TSRs From 2020-2023

For TSRs submitted to BPA from 2020 to 2023, the situation is better but still challenging. As a result of these TSRs, BPA plans to significantly expand its transmission portfolio, primarily through upgrading cross-Cascade 230-kV transmission lines to 500 kV, plus adding series capacitors and reconductoring existing high-voltage transmission.

This program, labeled its Grid Expansion and Reinforcement Portfolio (GERP), will cost $5 billion according to BPA, although realistically closer to $10 billion given all the environmental and procurement cost escalation factors involved. However, given the permitting realities, BPA staffing shortages and GI/TSR processing challenges, most GERP transmission projects will not be energized until well after Washington/Oregon 2030 80% clean energy deadlines.

The relatively good news: when eventually energized, GERP projects probably will enable PSE and PGE to meet their 80% clean energy goals. In addition, BPA also has enabled 3 to 5 GW of clean energy projects to reach Portland and Seattle by repurposing existing LTF transmission freed up by retirement of Colstrip and other thermal resources.

Complicating Factors

    • Data Center Load Growth

Similar to electric utilities in other regions, PNW entities have experienced dramatic increases in projected loads driven by data centers and, to a lesser extent, electrification. From 2001 to 2022, annual PNW load growth equaled 1% or less. Loads from 2025 to 2034 now are estimated to grow by 2 to 3% annually.

Recent announcements of potential data center amounts/locations in the PNW total 12 to 15 GW by the mid-2030s mainly in Hillsboro (west of Portland), Salem or east of the Cascades (e.g. northeastern Oregon). Current data center load projections could easily be double or half of the 12- to 15-GW estimate.

In almost any case, they will increase regional loads substantially. This phenomenon dramatically increases the transmission capacity required to serve them, as well as the time needed to build such transmission and its cost. For example, over 3 GW of data center load is projected for Hillsboro (mostly in PGE’s service territory), but reaching this densely populated area involves multiple 230/500-kV upgrades by BPA and PGE and likely will cost $2 billion or more.

    • BPA Staffing

BPA experienced substantial staff reductions and associated turmoil resulting from the Trump/Musk actions in early 2025. While regional parties helped BPA avoid the worst of these, they still lost 200 of their 3,100 employees in February 2025 and, despite finally being exempted from the federal hiring freeze in November, have yet to even get back to their start of 2025 staffing levels. Then there’s the additional 400-plus staff they are projected to need (bringing total eventual staffing to roughly 3,500) to timely process all the GI/transmission access requests needed to meet reliability/clean energy requirements.

Both the data center boom and administration staffing restrictions came at the worst possible time, given BPA’s GI/TSR queues and unique transmission processing problems. Better late than never for DOE to exempt them from the federal hiring freeze, but the PNW effectively lost a year or more in its ability to identify and build the high voltage transmission necessary to meet PNW clean energy, reliability and data processing needs.

Conclusions

    • While well intended, Washington/Oregon goals of 80% clean/decarbonized energy by 2030 were set without consideration of the transmission access and construction realities BPA and other regional transmission providers would face.
    • Achieving such goals also was handicapped by emerging data center load growth and administration staff reductions on BPA.
    • Perhaps most significant, besides these transmission realities, the 80% by 2030 mandates set off a virtual gold rush of TSRs, resulting in the 65 GW in BPA’s 2025 CS queue that are not capable of being processed in any reasonable time frame — if at all.
    • Many of these outcomes could/should have been foreseen and planned for. Others represented unfortunate surprises that were unanticipated under reasonable assumptions.
    • The probable result: BPA/PNW will simply need to muddle through this mess over the next five to seven years. As mentioned before, GERP projects eventually will enable PNW utilities to reach 80%, but probably not until 2033 to 2035.
    • Even with these transmission realities now plainly visible, Washington and Oregon legislators have yet to deal with the affordability of these clean energy mandates. This is an emerging problem but no doubt will worsen significantly in the next five years. Given that both PGE and PSE are only at 45 to 50% clean/decarbonized now, reaching 80% (whenever that occurs) will involve substituting 1 GW or more of renewable energy for energy from existing thermal resources. Such substitution involves replacing current coal/natural gas generation, probably costing utility consumers $40 to $50/MWh, with wind/solar which nominally cost $50 to $60/MWh busbar. However, when you include balancing, load following, additional transmission costs and purchasing additional energy to serve load when the wind does not blow or the sun is not shining, increases delivered cost to utility customers by $25 to $30/MWh. Then this $80 to $85/MWh delivered cost energy could well increase by an additional $20 to $30/MWh when federal tax credits expire, raising the overall cost for renewables to reach the 80% goal past $100/MWh. While this problem is belatedly being recognized, it has yet to be dealt with in any meaningful way by either state legislature.

Lesson Learned

Beware of unintended consequences. As this article hopefully illustrates, they already have adversely impacted the timing and (potentially) the cost of achieving 80% by 2030, and, if further action is not taken, they will further frustrate achieving such goals in the next four to five years.

Industry watcher Randy Hardy was CEO of the Bonneville Power Administration from 1991 to 1997. Prior to that, he held a similar title at Seattle City Light.

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Federal Briefs

Judge: Trump Admin Unlawfully Suspended NEVI

Judge Tana Lin, of the U.S. District Court for Western Washington, ruled that the Trump administration unlawfully suspended funding awarded to support the expansion of EV charger infrastructure.

Lin ruled in favor of 20 states and D.C., which had filed their lawsuit after the Department of Transportation in February suspended the National Electric Vehicle Infrastructure program enacted by Congress in 2021 under President Joe Biden.

The Trump administration argued it was a temporary pause, which it later ended after the judge earlier issued a preliminary injunction and the agency issued new guidance.

More: Reuters

Study: 50% of CO2 Emissions Come from 32 Companies

A report from think tank InfluenceMap claims 32 fossil fuel companies were responsible for half the global carbon dioxide emissions in 2024.

State-owned fossil fuel producers made up 17 of the top 20 emitters in the Carbon Majors report. All 17 are controlled by countries that opposed a proposed fossil fuel phaseout at the U.N.’s COP30 climate summit in December.

Saudi Aramco was the biggest state-controlled polluter, as it was responsible for 1.7 billion tons of CO2 from exported oil. ExxonMobil was the largest investor-owned polluter at 610 million tons.

More: The Guardian

Europe Reinforces Wind Commitment with 100-GW Pledge

The U.K., Germany, Denmark and other European countries signed a clean energy pact at a summit in Hamburg, pledging to deliver 100 GW of offshore wind power through large-scale joint projects, the British government said.

North Sea countries agreed in 2023 to a broader goal of 300 GW of offshore wind capacity by 2050. That followed Russia’s invasion of Ukraine, which sharpened fears about Europe’s dependency on Russian gas. The new deal will be signed at the North Sea Summit by Britain, Belgium, Denmark, France, Germany, Iceland, Ireland, Luxembourg, the Netherlands and Norway.

More: Reuters

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Company Briefs

Microsoft Proposes $13.3B Wisconsin Expansion

Microsoft is planning a $13.3 billion expansion of its Mount Pleasant, Wisc., operations, proposing to build 15 new data centers and other facilities across more than 1,300 acres.

The development includes two separate campuses: a Durand Avenue Site with up to nine data centers and a 96,000-square-foot office and storage building, and an International Drive Site with six data centers and a 74,000-square-foot office and storage building.

The expansion plans were submitted to the Mount Pleasant Plan Commission.

More: Racine County Eye

Court Approves Amazon Acquisition of Solar Project

The U.S. Bankruptcy Court for the Southern District of Texas approved the sale of the Sunstone solar-plus-storage project to Amazon Energy for $83 million.

The 1.2-GW solar and 1.2-GW battery storage asset in Oregon was previously held by Pine Gate Renewables. Pine Gate filed for Chapter 11 bankruptcy protection in 2025.

More: pv magazine

Laser Company Invests $1.3B to Enrich Uranium

Laser Isotope Separation Technologies announced it plans to build a $1.3 billion uranium enrichment complex at the Heritage Center Industrial Park in Tennessee.

LIS has the only laser uranium enrichment technology created and patented in the U.S.

The facility should create more than 200 jobs over a seven-year period. In return for its investment, Oak Ridge will halve LIS’ property taxes over 15 years.

More: Knoxville News Sentinel

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State Briefs

CALIFORNIA

State Surpasses 2.5 Million ZEV Sales

The state has surpassed 2.5 million cumulative zero-emission vehicle sales in 2025, according to the Energy Commission.

In the fourth quarter of 2025, Californians bought 79,066 new ZEVs, accounting for 18.9% of all new vehicle sales. Meanwhile, cumulative new ZEV sales have grown by more than 300% since 2019.

More: EV Infrastructure News

CONNECTICUT

Green Bank Sues Bankrupt PosiGen for $22M

The Connecticut Green Bank filed a lawsuit seeking repayment of $22.2 million in outstanding loans made to PosiGen, a solar panel leasing company that filed for bankruptcy in November.

The Green Bank, which receives roughly $23 million per year from ratepayers through a charge to invest in green technology, partnered with PosiGen between 2015 and 2021 to lease solar panels to low- and moderate-income households. Overall, the bank loaned PosiGen a total of $56.7 million “through a variety of loan facilities,” but it said it did not lend any ratepayer funds.

More: Inside Investigator

IOWA

House Passes Bill Banning Eminent Domain for Carbon Pipelines

The House of Representatives voted 64-28 to pass a bill that ban the use of eminent domain for carbon capture pipelines.

The bill now goes to the Senate for consideration.

More: Iowa Public Radio

MARYLAND

Gov. Moore Proposes Record Funds for Renewables

Gov. Wes Moore proposed a record $306 million for renewable and clean energy programs in the fiscal year 2027 budget.

Much of that money would be drawn from the Strategic Energy Investment Fund, which is managed by the state Energy Administration and is funded by utility payments and proceeds from the Regional Greenhouse Gas Initiative. Climate funding from SEIF in the fiscal year 2027 budget stood at about $328 million.

Moore’s total budget was $70.8 billion and accounts for an estimated $1.5 billion cash shortfall.

More: Inside Climate News

MASSACHUSETTS

Gov. Healey to Spend $180M to Help Reduce Utility Bills

Gov. Maura Healey plans to spend $180 million as part of a plan to temporarily reduce electricity gas bills by 25% and 10%, respectively, for residential customers for the months of February and March, the administration announced.

A spokesperson for Energy and Environmental Affairs Secretary Rebecca Tepper said the $180 million the administration plans to tap will cover an estimated 15% reduction in electricity bills. Utilities will then delay collecting an additional 10% of electric bills in February and March, with plans to recover those payments April through December. Companies will also plan to defer an estimated 10% of gas bill payments during February and March.

More: WBUR

MINNESOTA

PUC Rules Burning Trash, Wood ‘Carbon-free’

The Public Utilities Commission last week confirmed a law that says burning trash and wood to generate electricity will now be considered a carbon-free source.

The PUC ruled that facilities that burn municipal waste or biomass to generate electricity can still be considered carbon-free, even if they emit large amounts of carbon dioxide or other greenhouse emissions. They can do so if they pass a life-cycle analysis that proves burning trash or biomass generates fewer greenhouse gases than what would most likely occur if the wood or waste were disposed in another manner.

Only about 2% of electricity generated in the state comes from biomass and trash incineration.

More: MPR News

NEVADA

NV Energy Offers to Make Overcharged Customers Whole

NV Energy, which balked weeks ago at fully reimbursing overcharged customers, is reversing course and proposing to pay $63 million to more than 100,000 residential customers it has overcharged since 2002, the company announced.

The utility, which owed customers a total of $65.4 million, initially offered to reimburse a portion of affected customers just $2.5 million, claiming regulations limited their obligation to repay customers for just six months of overcharges. The offer “ensures that compensation is provided expeditiously” following Public Utilities Commission approval, NV Energy said.

More: Nevada Current

TEXAS

EPE Requests Gas Plant for Data Center

El Paso Electric is seeking Public Utility Commission approval for a 366-MW natural gas power plant that will fuel a $1.5 billion, 1-GW Meta data center.

The plant will be exclusively connected to the data center for the first five years, according to filings. Then it would be connected to the broader El Paso Electric grid. Meta would be responsible for all the costs during the first five years.

The plant will require approvals from both the PUC and the Commission on Environmental Quality. If approved, it is expected to be operational by 2027.

More: Inside Climate News