RTO Insider

January 31, 2025

TVA CEO Jeff Lyash Announces Plans to Retire

Tennessee Valley Authority CEO Jeff Lyash announced plans to retire “no later than the end of the fiscal year” after running the federal power authority for nearly six years.

“For the past six years, it’s been my privilege to serve with an experienced, talented team at TVA,” said Lyash. “TVA truly is a special place — created more than 90 years ago to improve the quality of life for more than 10 million people across this region. That mission of service continues to be our focus today.”

President Donald Trump criticized Lyash’s high salary back in his first term and the announcement comes less than two weeks into his second, but TVA’s press release was a standard retirement announcement and the end of the fiscal year means he could stay on until this fall. TVA is not taxpayer funded and gets its revenue from power sales.

“I grew up in the small coal-mining town of Shamokin, Pennsylvania, and I cannot think of a better place than TVA to close out my career serving people just like those in my hometown,” Lyash said. “While I’m looking forward to my next chapter, spending more time with family, grandchildren, and friends, I will miss our TVA team and the relationships we’ve built across this region.”

Before joining TVA, Lyash was the CEO of Ontario Power Generation and worked for years at Duke Energy and Progress Energy.

Lyash was appointed to the job in April 2019 and since has run the country’s largest public utility with a focus on building strong partnerships, including with the TVA region’s 153 local power companies, and managing sustained growth.

“Jeff’s knowledge and experience make him one of the top leaders in the energy industry,” said TVA Board Chair Joe Ritch. “Jeff has done more than lead one of the nation’s top power providers, he has helped drive an industry forward. His vision has positioned TVA well for the future, and he has built a legacy that will endure.”

TVA has below average electricity rates and it has been meeting ever-growing demand, with more than 3,500 MW of new generation under construction or online as of early 2025. The authority saw its all-time peak this January when demand hit 35,319 MW.

Lyash positioned TVA to be a leader on new nuclear power, with the authority winning approval for an early site permit from the Nuclear Regulatory Commission to possibly build a small modular reactor. TVA is leading an application with 11 industry partners and the state of Tennessee for an $800 million grant from the U.S. Department of Energy to build that SMR.

“Nuclear is the most reliable and efficient energy the world has ever known, and TVA is uniquely positioned to help drive this forward,” Lyash said. “Advanced nuclear technologies will play a critical role in our region and nation’s drive towards great energy security.”

January 31, 2025

FERC Approves Annual Megawatt Cap for MISO Interconnection Queue

FERC has given MISO an all-clear to cap project hopefuls lining up for its overflowing generator interconnection queue at 50% of the RTO’s peak load.

FERC said MISO’s plan to impose a yearly cap of 50% of the non-coincident peak per study region is fair considering the footprint’s 309-GW, backlogged interconnection queue (ER25-507). The commission said in the Jan. 30 order that the cap “will allow MISO to conduct its study cycles more effectively… which will ultimately benefit interconnection customers.”

The megawatt cap would take effect beginning with the grid operator’s 2025 cycle of queue submissions.

MISO late last year made a second attempt to instate a megawatt cap on its annual queue cycles after FERC rejected MISO’s first attempt based on concerns over too many cap exemptions, the formula to establish the cap being unrealistic and potential resource adequacy deficits from limiting new generation onto the grid. (See MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects; MISO Stakeholders Debate Usefulness of MW Queue Cap Pending Before FERC.)

With the cap in place, MISO said it will reopen acceptance of a new queue cycle at the end of this year. MISO had paused processing new queue cycles for more than a year and skipped a 2024 cycle altogether. (See MISO Unveils Later Timeline for Queue Processing Restart.)

MISO said a jump in interconnection requests beginning in 2020 has made it nearly impossible to create accurate models to study the new interconnections.

It fielded 52.4 GW of requests in 2020, 76.8 GW in 2021, and 170.8 GW in 2022. The queue currently contains nearly 1,700 interconnection requests totaling about 309 GW. By comparison, MISO’s peak load holds at about 127 GW, and the footprint boasts a total 191 GW of functioning installed capacity.

FERC agreed with MISO that “the large number of interconnection requests submitted into MISO’s interconnection queue would cause MISO to make unrealistic modeling assumptions, producing study results with inaccurate network upgrade cost estimates.”

“Such inaccuracies, in turn, would drive withdrawals from the queue, further affecting study results and causing delays,” FERC wrote.

The commission said MISO’s 50% methodology is reasonable based on MISO’s explanation that it represents a cliff before studies begin showing that major transmission upgrades are necessary, which is “typically indicative of voltage collapse.” FERC also said MISO this time explained how the cap still would allow sufficient generation capacity to be developed to meet resource adequacy standards.

MISO has said that even with a cap in place, it could achieve a total 310-GW queue throughput through 2042.

“We agree with MISO that the proposed queue cap formula strikes a reasonable balance between limiting the volume of requests to a level that can be processed efficiently and avoiding unnecessary barriers to entry that will delay the development of the generation capacity needed to meet growing supply shortages within the MISO region,” FERC said.

FERC decided MISO’s thinning of cap exemptions was appropriate and took care of concerns that MISO would have “unbounded” exceptions to the cap. It disagreed with MISO South regulators that removal of an exemption for projects deemed necessities by state public service commissions treads on states’ authority. FERC said if a public utility wants to modify its generator interconnection procedures on file, it must file with FERC.

Exemptions to the cap now are limited to generators with provisional generator interconnection agreements; generators seeking to replace retiring counterparts and in need of extra interconnection service; and those generators wanting to convert their unguaranteed energy resource interconnection service with the higher-quality network resource interconnection service.

FERC dismissed clean energy groups’ concerns that the cap method doesn’t feature a “first-ready, first-served” approach for generation projects. The commission said projects entering the queue still must meet MISO’s commercial readiness requirements to advance into the queue. It also said MISO’s recently raised fees, automatic withdraw penalties and requirements that developers show proof they secured land should winnow out speculative projects. FERC declined to consider Shell Energy’s recommendation that MISO impose a per-developer limit on project submission based on similar reasoning.

FERC also rejected some stakeholders’ arguments that the cap isn’t reasonable because it didn’t resemble approved caps like CAISO’s and wasn’t limited to a specific amount of time like SPP’s. It said it wouldn’t go down the road of deciding whether the cap was “more or less reasonable” than other possible rate designs.

“MISO, CAISO, and SPP have chosen to address interconnection queue management problems caused by an overwhelming number of interconnection requests through different approaches based, in part, on regional needs and characteristics,” the commission said, while pointing out that MISO has committed to reviewing the effectiveness at the cap in about three years.

The commission refused utilities and MISO South regulators’ recommendation that FERC tie approval of the cap to a resource adequacy express lane MISO is working to build into the queue, saying the future filing is a separate issue and not yet up for consideration. (See Generation Developers Ask for Scoring System on MISO Queue Fast Track.)

However, Commissioner Mark Christie wrote separately to encourage MISO to try again at developing exceptions to the cap for generation facilities that are labelled indispensable to resource adequacy by public service commissions. He said FERC “wrongly” rejected exemptions for state-designated generators in MISO’s first filing.

Christie said he was “disappointed in MISO’s failure to include a state exemption in its second filing, as the membership of the commission has changed significantly since last January and already has shown much more acknowledgement of the critically important role played by state utility regulators in ensuring reliable power to their states’ consumers.”

“MISO should have stuck to its guns and vigorously restated its reasons for including a state exemption,” Christie wrote.

While FERC said it was in favor of MISO’s cap, it encouraged the RTO to “continue considering other avenues to manage its interconnection queue” and said MISO’s efforts to automate its studies appear promising.

January 30, 2025January 31, 2025

Shell Quits Atlantic Shores Offshore Wind Project in NJ

One of the partners behind New Jersey’s Atlantic Shores Offshore Wind has bailed out of the long-running project, taking a billion-dollar impairment in the process.

Shell announced the news Jan. 30 with its fourth-quarter 2024 earnings results.

The offshore wind project was not specifically mentioned in material prepared for investors, or in prepared remarks by the CEO and CFO. Instead, the company referred to the $996 million in impairment charges “mainly relating to renewable generation assets in North America.”

Similarly, in its first-quarter 2024 reporting, Shell offered few details about its divestment from SouthCoast Wind, off the Massachusetts coast.

Shell New Energies US had partnered with Ocean Winds North America on SouthCoast and with EDF-RE Offshore Development on Atlantic Shores. Ocean Winds has continued with SouthCoast since Shell’s departure.

In a Jan. 30 statement, Atlantic Shores said it, too, will continue working to deliver the project.

“Business plans, projects, portfolio projections and scopes evolve over time — and as expected for large, capital-intensive infrastructure projects like ours, our shareholders have always prepared long-term strategies that contemplate multiple scenarios that enable Atlantic Shores to reach its full potential,” the company said.

Both projects have secured their key federal permits, which will provide at least short-term protection from the Trump administration’s attempts to halt offshore wind development in U.S. waters, which include a freeze on leasing. (See Critics Slam Trump’s Freeze on New OSW Leases.)

But under Trump’s Day 1 executive order, Atlantic Shores and SouthCoast are subject to a review that could result in their leases being amended or terminated.

Furthermore, Atlantic Shores and SouthCoast both have critical gaps in their balance sheets.

Atlantic Shores won a 1,510-MW contract from New Jersey in June 2021. But in July 2024, it submitted a bid in New Jersey’s fourth solicitation for two projects — one new, but one a rebid of the original project, presumably with higher costs attached. (See 3 OSW Proposals Submitted to NJ.)

New Jersey still has not finalized contracts from that solicitation.

Massachusetts and Rhode Island selected SouthCoast in early September in a three-state solicitation but have not been able to complete negotiations on power purchase agreements. They are now targeting a March 31 execution date — a full year after developers submitted bids.

New Jersey has some of the largest offshore wind goals in the U.S., and its shore region has been the scene of some of the loudest opposition to development of offshore wind farms. Opponents cheered in late 2023 as Ørsted abruptly canceled the Ocean Wind 1 and 2 projects it had contracted with the state. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

And opponents cheered again as word spread of Shell’s pullout.

“Another major blow to the offshore wind scam! Shell is pulling out of the Atlantic Shores project, writing off nearly $1 billion as the industry collapses under its own weight,” U.S. Rep. Jeff Van Drew (R), who represents much of the shore region, posted Jan. 30 on X.

January 30, 2025January 31, 2025

‘Green’ Steel Mill Gets Financial Boost from CEC Grant

San Diego-based Pacific Steel Group (PSG) is planning a zero-carbon-emission steel mill near Mojave, Calif., in a first-of-a-kind project that will set an example for industrial decarbonization.

While there have been other electric steel mills, the Mojave Micro Mill project would be the world’s first fully electric, zero-carbon-emission steel production facility, according to Lin Planchard, a utilities engineer with the California Energy Commission. Electricity for the steel plant will come from on-site solar and the grid, and the plant will be equipped with a carbon-capture system.

The $630 million project will recycle steel to produce rebar for use in California’s construction industry. Currently, scrap metal from California is sent to facilities in Washington, Oregon, Utah, Arizona or even Asia for recycling and rebar production. The rebar then must be transported back to California.

“By building a new rebar mill, California can fill this gap in the market by localizing our scrap recycling and rebar production and thereby reducing emissions from transporting steel by approximately 118,000 tons per year,” Planchard said.

The CEC on Jan. 21 approved a $14 million grant to PSG for long-duration energy storage (LDES) to support about 50 MW of solar power at the steel plant. The storage will be connected to the solar photovoltaic system and a microgrid.

“It will optimize the use of on-site solar energy, support critical operations during outages and contribute to the overall energy management strategy of the facility,” according to the grant request form.

The 32 MWh LDES system will be non-lithium-ion; PSG is exploring multiple chemistries including zinc that are capable of discharging for at least eight hours, company spokeswoman Michelle D’Alonzo told NetZero Insider.

D’Alonzo said the Mojave Micro Mill will electrify processes that traditionally use natural gas. Steel will be recycled at the facility by melting it in an electric arc furnace.

Nearly 90% of the mill’s carbon emissions, which already are low, will be captured, according to a project fact sheet. Captured carbon dioxide will be purified, liquified and used in applications that require CO₂.

Kern County certified an environmental impact report and a statement of overriding consideration for the project in March 2024. PSG expects to break ground on the steel mill in March and start operations in early 2027.

When completed, the Mojave Micro Mill would be the only operational steel mill in the state, which hasn’t seen a new steel mill in more than 50 years.

“I love this project,” CEC Chair David Hochschild said during the Jan. 21 meeting. “This marries many of the things that we’re trying to do together: industrial decarbonization, new manufacturing, assembly and recycling facilities, and cutting-edge clean energy technologies and grid reliability.”

In addition to the CEC grant award, the Mojave Micro Mill got a boost Jan. 16 when Generate Capital announced a $200 million secured loan to PSG for the project. Generate Capital is a San Francisco-based sustainable infrastructure investment firm.

“PSG’s innovative approach demonstrates how we can significantly reduce emissions in the industrial sector while meeting the rising demand for greener building materials economically,” Generate Capital President Bill Sonneborn said in a statement.

As the most widely used metal in the world, steel is one of the largest single sources of carbon emissions, accounting for 7% of global and almost 30% of industrial emissions, Generate said in a release.

“Decarbonizing the steel market, therefore, is vital to achieving the transition to net-zero emissions,” the investment firm said.

January 30, 2025January 31, 2025

Texas RE Calls ITCS Recommendations ‘Very High Level’

Fulfilling the recommendations from NERC’s Interregional Transfer Capability Study will not be a simple task, a speaker said at a webinar Jan. 29 hosted by the Texas Reliability Entity.

“I don’t expect that we’re going to have a mandate from Congress to build anything at a certain level, particularly with the administration we have now, but I don’t know for sure. Nobody does,” Mark Henry, Texas RE’s chief engineer and director of reliability outreach, said at the regional entity’s “Talk with Texas RE.”

Henry took part in writing the ITCS as part of the ERO Executive Leadership Group; he told attendees that industry stakeholders from Texas also contributed through the ITCS Advisory Group.

NERC filed the ITCS with FERC in November 2024 as ordered by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) The commission posted the report for a 12-month public comment period Nov. 26 and will submit a report on its conclusions to Congress after the comment period concludes, along with recommendations for statutory changes, if any (AD25-4).

The three parts of the ITCS submitted last year include a transfer capability analysis summing up the current transfer capabilities between transmission planning regions in North America, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability. A fourth document is planned in the second quarter of 2025 covering transfer capabilities and prudent additions from the U.S. to Canada and between Canadian provinces.

NERC recommended 35 GW of additional transfer capability across the North American grid, while noting that it still was not possible to resolve all the potential energy deficiencies identified over the 10 years of the study.

Henry observed that these additions included a significant amount of added capacity — 14,100 MW — in ERCOT across the existing SPP-South connection (4,100 MW) and two new connections to Front Range (5,700 MW) and MISO-South (4,300 MW). These still hypothetical new connections do not represent any specific projects or locations, he said, because identifying such opportunities would be outside the ITCS’ scope.

Henry emphasized that the ITCS should be seen as a jumping-off point for further studies and planning work, rather than a blueprint for solving the grid’s transmission problems. He pointed out that the study only posited transfer additions between neighboring regions and added that even if such additions are constructed, there is no guarantee the regions will be able to use the full capacity, because severe weather or other conditions that lead to energy shortfalls in one region could easily affect a nearby one.

In addition, Henry reminded listeners of the constraints imposed on the team. The FRA set NERC a deadline of just 18 months to complete the first-of-its-kind study, and the ERO had to choose its focus carefully to ensure it could finish on time.

“With the time and resources allowed for this, we kept this at a very, very high level,” Henry said. “The first part of meeting and maintaining is just to recognize that you’re going to have to do a lot of additional work. You’re going to have to study the system in more detail and identify where you might actually accomplish some of these transfers.”

Henry promised that NERC will continue to study the topics raised in the ITCS and refine its findings. He also urged listeners to “offer some insight” and reactions to the report through FERC’s comment process.

January 30, 2025January 31, 2025

BPA Employees Confront Trump’s ‘Fork in the Road’

Employees of the Bonneville Power Administration received the same buyout offer from the Trump administration as millions of other federal workers, staff have confirmed to RTO Insider.

The move came despite the federal power marketing administration’s status as a self-funding entity and its key role in Northwestern electricity generation and transmission and regional fish conservation efforts.

BPA also operates a balancing authority area covering about 300,000 square miles, which encompasses large parts of Oregon, Washington, Idaho and Montana, and smaller sections in California, Nevada, Wyoming and Nevada.

The agency is headed by Administrator John Hairston, who has served in that role since January 2021.

The Trump administration emailed the buyout offers to about 2.3 million federal employees through the Office of Personnel Management (OPM) in a Jan. 28 message titled, “Fork in the Road.”

The message instructed recipients to type the word “Resign” into the subject line and reply if they want to accept the offer of the “deferred resignation” arrangement, with the promise they’d be provided a severance package consisting of eight months’ pay and benefits through Sept. 30, the end of the federal fiscal year. Employees were directed to respond by Feb. 6.

The email explained that the move is part of an effort to “reform” the federal workforce around “four pillars,” consisting of a policy to require most remote workers to return to their physical offices five days a week; a “performance culture” that will “insist on excellence at every level”; a “more streamlined and flexible workforce” resulting from downsizing; and “enhanced standards of conduct” intended to retain “employees who are reliable, loyal, trustworthy and who strive for excellence in their daily work.”

The administration has said it expects 5 to 10% of the federal workforce to accept the offer, which observers have said looks to be modeled closely on the approach that Elon Musk used with employees at Twitter (now X) after he assumed ownership of the social media platform in 2022. Trump picked Musk to lead efforts at the unofficial “Department of Government Efficiency,” charged with reducing the size of federal operations.

‘Ridiculous Deal’

A BPA employee who spoke on background to RTO Insider said fellow staff members had expressed concern about the unexpected development but generally were “keeping their heads down” and continuing to perform their duties amid the uncertainty.

Portland-based BPA employs more than 3,000 people and manages the output from 31 hydroelectric dams in the Federal Columbia River Power System with a combined capacity of about 22,440 MW. The agency also operates more than 15,000 miles of transmission lines — about 75% of the Northwest grid.

Asked to comment about the potential impact of the order, a BPA spokesperson referred RTO Insider to the agency’s parent agency, the U.S. Department of Energy, for a response.

DOE did not respond to a series of questions seeking clarity on several points, including:

- What steps DOE is taking to evaluate the operational impact on BPA and the other three PMAs of potentially high staff turnover in such a short period of time.
- Whether DOE is aware of how and when OPM will inform the department and the PMAs about specific resignations at the agencies.
- Whether DOE has been provided guidance by the administration about how BPA and the other PMAs should implement the “four pillars” outlined in the buyout memo or been given a time frame for doing so.
- Whether DOE expects BPA, the other PMAs and the Tennessee Valley Authority to be in any way insulated from the measures laid out in the email based on their self-funding models.

In an email to RTO Insider, U.S. Sen. Jeff Merkley (D-Ore.) said Trump “has no authority to offer this ridiculous deal, nor does he have authority to guarantee it. If folks take this so-called deal, they could be left high and dry by the president.

“Nonpartisan BPA professionals work hard to provide reliable, affordable electricity across the Pacific Northwest, and citizens and local businesses depend on the agency for its critical services.”

The offices of Sens. Ron Wyden (D-Ore.) and Maria Cantwell (D-Wash.) did not respond to requests for comment as of press time.

Scott Simms, executive director of the Portland-based Public Power Council — whose membership consists of BPA’s “preference” customer base of publicly owned utilities that purchase low-cost power from the agency — said the group is “gravely concerned” by the development.

“BPA is funded by Northwest ratepayers and not taxpayers, and its mission supports the Northwest economy; ensures the flow of reliable, domestically produced electricity; and provides employment in rural areas,” Simms said in an email. “I think if certain decision-makers knew that, they would do everything possible to retain this valuable workforce. This will be important for us to emphasize in the weeks and months ahead so we don’t suffer unintended consequences to our power system and our region’s communities that depend on it.”

January 30, 2025

765-kV Lines in West Texas Inch Closer to Reality

The drive to build 765-kV lines in Texas continues to inch forward, with ERCOT and stakeholders working to provide enough information for regulators to reach a decision on which framework to go with by May 1.

During an extra high voltage (EHV) workshop Jan. 27, ERCOT staff shared with stakeholders their “traditional” 345-kV portfolio of projects as part of its annual Regional Transmission Plan (RTP). They also included for the first time a 765-kV study, a result of their 2024 Permian Basin Reliability Plan identifying transmission facilities and import paths needed to serve existing and future demand in petroleum-rich West Texas.

The Texas Public Utility Commission in September approved the Permian Basin plan, which included both 345-kV and 765-kV infrastructure, and $13 billion to $15 billion in initial investment. However, it deferred a decision on the import paths’ voltage levels to no later than May 1, 2025. (See Texas PUC Approves Permian Reliability Plan.)

The commission plans to open a comment period following a Jan. 31 discussion of the two plans. The PUC will host its own EHV workshop March 7 (55718).

“My understanding from working with commission staff is that’s just the beginning of the process,” Prabhu Gnanam, ERCOT’s director of grid planning, told the workshop’s attendees. “All of this to help set up the commissioners to be able to make a decision before May 1.”

Either plan will require thousands of miles of transmission lines to be built through 2030. Both will cost more than $30 billion, according to initial projections, far surpassing the last project of its kind in Texas, the Competitive Renewable Energy Zone (CREZ) initiative completed in 2014. That project resulted in 3,600 miles of transmission lines, built at a cost of $6.9 billion. CREZ has freed up more than 23 GW of wind capacity in West Texas that since has been added to the grid.

New 345-kV lines and upgrades as part of the 345-kV plan. | ERCOT

The Texas 765-kV Strategic Transmission Expansion Plan (STEP) has an estimated construction cost of $32.99 billion and includes:

- 2,468 miles of 765-kV lines.

- 649 miles of new 345-kV lines and 1,098 miles of existing 345-kV upgrades.

- 324 miles of new 138-kV lines and 1,287 miles of existing 138-kV upgrades.

- 446 miles of existing 69-to-138-kV conversions.

The 2024 RTP 345-kV plan has a projected construction cost of $30.75 billion and includes:

- 2,673 miles of new 345-kV lines and 1,913 miles of existing 345-kV upgrades.

- 334 miles of new 138-kV lines and 1,714 miles of existing 138-kV upgrades.

- 647 miles of existing 69-kV to 138-kV conversions.

Both plans will require an estimated $5 billion annually over the six-year planning horizon, as compared to an average of $3 billion per year over 2022/24, the grid operator said.

ERCOT says its analysis indicates the 765-kV STEP would provide “significant economic and reliability benefits” to the system because 765-kV lines are more efficient in moving power from resource-rich regional to load centers over long distances.

The grid operator said last year it expects over 150 GW of demand, more than its current capacity, to be added to the system by 2030. Almost 50 GW of that expected demand is from the oil and gas natural load, AI and data centers, cryptocurrency mining, electrification, and hydrogen processing and related infrastructure.

“If those large loads move from one county to the next, you’re still making that power flow across the state,” Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told the workshop’s attendees. “Then you can deal with any changes to the large loads through the subsequent underlying 345-kV network that will support it.”

Staff conducted steady-state transfer capability, dynamic stability and system strength analyses to gain a clearer picture of how either option could support reliability and grid stability. Staff said the higher-voltage option would reduce congestion costs by $229 million annually and cut system production costs by $28 million, both annually. (ERCOT has incurred $4.27 billion in congestion costs the past two years.)

The 765-kV STEP would reduce energy losses by 560 GWh each year, equivalent to a 128-MW thermal unit operating at a 50% capacity factor, staff said in its report. It also would yield an increase of up to 3,000 MW in power transfer capability and a 13% stability limit in West Texas.

ERCOT used $6.2 million/mile and $4.2 million/mile as “generic cost estimates” for the 765-kV and 345-kV facilities. The 765-kV cost estimate is based on the same dollar figure used in MISO’s Long-range Transmission Plan, approved in December and including 1,800 miles of new 765-kV projects. The 345-kV number is based on the average cost for new 345-kV lines provided by transmission service providers in the Permian Basin study.

“As we look at the additional transfer capability of the higher-voltage network, which also would be setting us up for future growth as well and giving us some breathing room … the TSPs and stakeholders that try to take outages on the system today can tell you that we have maximized or optimized the use of our current system,” Hobbs said.

January 30, 2025January 31, 2025

BPA Considers Impact of Fees in Day-ahead Market Choice

PORTLAND, Ore. — The Bonneville Power Administration could face high implementation fees and operating costs under both SPP’s Markets+ and CAISO’s EDAM, but exact amounts are in flux, and various factors could soften the financial blow, staff members said during BPA’s member meeting Jan. 29.

Rachel Dibble, vice president of bulk power marketing at BPA, told RTO Insider that implementation fees are “one part of the puzzle” in the agency’s final market decision. The agency will weigh those considerations against results of production cost models, “as well as all the other quantitative elements that weren’t included in the production cost model,” Dibble added.

“As far as the magnitude of those numbers, they probably sit more in the ongoing revenue … and costs that we would generate from participating in the market,” Dibble said. “I would expect over time, we would make back all of the money that we would be investing in getting ready to enter a market. So, we will certainly consider them, and they will be part of the decision.”

SPP estimates Phase 2 implementation costs across the entire Markets+ footprint will be about $150 million, and it is unclear exactly how much of that BPA would be responsible for. Agency staff have noted it’s probably about $25 million, which is more than the $2.5-$3 million in implementation fees expected under an EDAM scenario.

However, CAISO also has projected $29 million annually in grid management charge fees for the BPA BAA across all scheduling coordinators. The charge is a transactional fee applied to each transaction, and the agency itself would “bear only a share of these charges based on its activities representing its loads and resources in the market,” according to a staff presentation.

Andy Meyers, market initiatives policy lead with BPA, noted the agency itself would pay less than $29 million under EDAM, adding that “knowing exactly what Bonneville’s portion of that is an … outstanding question, but knowing kind of where the maximum is for the BAA is helpful in providing a reference point.”

By contrast, the $150 million Phase 2 costs associated with Markets+ would be financed, and BPA would repay its portion of the loan with a market transaction fee applied to each transaction made in the market. The $150 million covers staff, facilities, infrastructure, tools and applications.

BPA would pay its share of the Phase 2 funding fees on top of annual operating costs, which are projected to be between $13 million and $15 million, according to the staff’s presentation.

Still, Laura Trolese with The Energy Authority noted that BPA would pay Phase 2 funding fees on market transactions over several years, which potentially could limit the financial impact.

Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, asked whether BPA still would be on the hook for its share of the Phase 2 portion if the agency decides to leave Markets+ after signing a Phase 2 agreement.

BPA Chief Business Transformation Officer Nita Zimmerman responded that it “gets into the specifics of the funding agreement. That’s up to SPP to share and not me. It really depends on how far the funding agreements go as to how much we would be on the hook for and at what point.”

Likewise, BPA could not provide a definite answer to what extent the fee agreements factor in “inflationary assumptions,” following a question by Stefanie Johnson, strategic adviser at Seattle City Light.

There are still details, like specific amounts, timing and mechanics, that BPA needs to iron out before it can give stakeholders a clearer picture of how implementation fees would impact the agency under either Markets+ or EDAM. The agency also is working on estimates for internal implementation costs, staff said.

BPA has said it will issue a draft day-ahead market decision in March and a final decision in May.

January 30, 2025January 31, 2025

New England Gas Generation Hit a Record High in 2024

As overall power production ticked up in New England in 2024, natural gas generation reached its highest annual total in the region’s history, accounting for over 55% of all generation and 51% of net energy for load, according to new data from ISO-NE.

Natural gas generation provided 59,883 GWh of power in 2024, up from 55,585 in 2023, which resulted in an increase in annual power sector emissions. Oil generation remained steady year-over-year, while coal generation accounted for 234 GWh, a small increase relative to 2023.

One of the largest year-over-year changes came from a major reduction in power imported from Canada, as a massive drought caused Hydro-Québec to reduce its exports. Net imports from Canada declined for the second straight year, dropping to 6,067 GWh, less than half of the 2023 levels.

For renewables, solar and wind generation both increased in 2024 compared to 2023, but they remain a relatively small part of the region’s resource mix. Solar increased from 3,852 GWh in 2023 to 4,554 GWh, while wind increased from 3,302 GWh to 3,517 GWh. This does not include power from behind-the-meter solar, which reduced net load by about 4,300 GWh in 2023.

While solar has grown steadily over the past 10 years, wind power production has been largely stagnant since 2017. Despite the year-over-year increase, wind was lower in 2024 compared to 2019-2022. This could change rapidly if Vineyard Wind 1 and Revolution Wind ramp up power production in 2025 and 2026.

Nuclear generation rebounded in 2024 after a significant down year in 2023. It has remained relatively consistent around 26,000 GWh of annual generation after the closure of the Pilgrim Nuclear Power Station in 2019.

The decrease in imports, coupled with the spike in gas generation, contributed to the highest annual generation total in the region since 2013. The peak load in 2024 was 24,871 MW, up 828 MW from 2023 but in line with the region’s average annual peak over the past 10 years.

Both the peak load and total annual generation remain well below the highs reached in the mid-2000s. The region hit its all-time peak in 2006 at 28,130 MW, while total generation peaked at 131,877 GWh in 2005.

In the coming years, ISO-NE’s peak load and overall generation requirements are projected to increase exponentially with heating and transportation electrification. The RTO projects the peak load to increase by about 10% by 2033, coupled with a 17% increase in electricity consumption. (See ISO-NE Predicts 10% Increase in Peak Demand by 2033.)

These increases likely will accelerate in the years prior to 2050. ISO-NE projected in its Economic Planning for the Clean Energy Transition study that the region’s peak load will reach 60.8 GW by 2050. Massachusetts’ 2050 Decarbonization Study projected a more modest 57 GW.

As demand increases, the states will need to find a way to reverse the increase in gas generation to meet their climate goals for 2030 and beyond. ISO-NE has expressed interest in establishing new market mechanisms to support low-carbon resources and dispatchable resources, but the states have been slow to pursue these options.

Beyond emissions concerns, there are physical constraints to how much more gas generation the region could add to meet rising demand, particularly during the winter. Gas utilities reserve much of the pipeline capacity into the region in the winter to meet heating needs, limiting gas generation during these periods.

In 2023, Enbridge proposed a significant pipeline expansion project, intended to help ease some of the region’s gas constraints. The company marketed the project to meet growing demand from generation and local distribution companies. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)

It has not filed the project with FERC, and it told a municipal utility in May that it is “looking to get signatures on the precedent agreements, and at that point, we will file with [FERC].”

However, Enbridge and the gas utilities could face a challenging regulatory environment to approve contracts for the project in Massachusetts, where regulators are pushing the utilities to transition away from natural gas in accordance with the state’s decarbonization requirements.

January 30, 2025

MISO Unveils Later Timeline for Queue Processing Restart

MISO is pushing back a restart of its swamped generator interconnection queue by a few months while it tries to study through the backlog with tech company Pearl Street.

The RTO now plans to finish the first phase of studies on the 2022 batch of project proposals before it begins studying the 2023 class in May. It won’t begin analyzing 2025 entrants until the fourth quarter. However, MISO hopes to have all projects striking interconnection agreements over 2026, with the 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026.

Last year, MISO tentatively scheduled the 2025 cycle of queue projects to begin in the third quarter. It also said it would begin studying the 123 GW of 2023 interconnection requests in February. (See 2023 Queue Cycle Delayed into 2025 as MISO Seeks Software Help on Studies.)

MISO skipped acceptance of a 2024 queue class altogether. The RTO hasn’t processed a new queue cycle in more than a year, saying it needs to introduce study automation and implement a megawatt cap to make processing requests less daunting. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.)

It is betting that Pittsburgh-based tech startup Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) can get its overtaxed queue down to a one-year process.

Pearl Street and MISO are automating several aspects of the queue, including the studies that select network upgrades and estimate costs, study reports, and the process behind power flow model building, dispatching and solving.

In a teleconference Jan. 28, MISO’s Ryan Westphal told the Interconnection Process Working Group that the RTO is “testing and getting things tuned in” on the automated work.

Westphal said that while MISO and Pearl Street have made “significant progress” on implementing SUGAR, they “need a little more time” to refine the process and make it more user friendly as stakeholders have requested.

He said that by Feb. 10, MISO will begin using Pearl Street in earnest on the proposals that entered the queue in 2022. It hopes to finish the first phase of interconnection studies for the 2022 cycle by early May.

Westphal said MISO is choosing to complete the 2022 cycle’s first phase studies before it starts on 2023’s class to limit ambiguity in study results. He said a prior cycle’s resources become assumptions in future study cycles, so MISO should avoid study overlap. The sheer size of the 2022 and 2023 queue cycles — 171 GW and 123 GW, respectively — also makes some separation a wise call.

“The 2022 cycle is large, as everyone remembers, so it’s really prudent to get it through the queue,” Westphal said.

Westphal said at this point, MISO plans to kick off the 2022 cycle on Feb. 10 and the 2023 cycle on May 5. The RTO hopes the technology can help it shrink the first phase of studies to 90 days.

It further estimates that SUGAR will reduce time spent on the 2022 and 2023 cycles by anywhere from 270 to 365 days, a “massive engineering time savings.”

“We have to move through the backlog to get through to the place we want to be,” Westphal said. He predicted “a lot of work” and MISO continuing to process simultaneous cycles until it can cut its queue down to a one-year interconnection process.

“We think that SUGAR gives us the best chance to do that,” Westphal said. “We’re hoping this is a big piece of us being able to achieve a one-year queue process.”

The RTO also hopes that SUGAR can speed up the first phase of interconnection studies in particular so its engineers can devote more attention to the more intricate, back-end studies of the queue, Westphal said.