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February 22, 2025

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Utilities Pushing for Return to Owning Generation in Pennsylvania

PPL is backing legislation this year that would let utilities in Pennsylvania own generation, which would unwind a key part of the state’s nearly 30-year experience with restructuring.

The utility holding company, which is based in Pennsylvania and owns utilities there, announced its support for utility-owned generation on an earnings call last summer after capacity prices in PJM spiked. (See PPL Backs Utility-owned Generation in Pa. After PJM Capacity Price Spike.)

“In Pennsylvania, specifically, we continue to advocate for a state-focused, no-regrets strategy that addresses impending energy shortfalls and provides the state with additional tools to help protect customers from price volatility and reliability concerns,” PPL CEO Vincent Sorgi said during the company’s year-end earnings call with analysts Feb. 13. “We believe one way to do this is to allow regulated electric utilities to invest in generation resources up to and including owning and operating generation again. This would complement the competitive market by addressing resource adequacy gaps, rather than relying solely on market forces to deliver a solution.”

Sorgi’s remarks came after The Standard-Journal published an op-ed by Christine Martin, president of PPL Electric Utilities, outlining the case for letting utilities back into the generation business without setting up a separate firm that operates generation using only market revenues.

That generated pushback from three former chairs of the Pennsylvania Public Utility Commission — James Cawley (D), Robert Powelson (R) and Glen Thomas (R) — in an op-ed published in The Scranton Times-Tribune, arguing utility-owned generation would gouge consumers. All three have long supported competitive markets, and Thomas is the president of PJM Power Providers, which represents independent power producers who would have to compete with rate-based generation if the change went through.

“PPL’s policy shift ignores the fortunate position that Pennsylvania now enjoys thanks to competitive markets,” the three wrote. “Pennsylvania currently has 70% more power than it needs to meet peak demand. This enviable surplus means Pennsylvania nearly always exports power to neighboring states with generation deficits, no matter how much demand fluctuates.”

But Pennsylvania is in PJM, and Cawley noted in an interview that other states in the RTO are falling short on building new generation. That has helped lead to higher prices in the entire market. Pennsylvania has better policies to encourage new generation than neighboring states like New Jersey and Maryland, he added.

“As we say in our op-ed, independent producers will take the risk, and they will meet that demand,” Cawley said.

Martin argued just the opposite in her piece.

“We cannot simply wait for the market to ‘fix’ the issue, especially when that same market is failing to bring new generation capacity online in a timely manner,” Martin wrote. “PJM is working on market reforms, and while these are steps in the right direction, they are unlikely to address the immediate crisis facing Pennsylvania and our region.”

On the earnings call, Sorgi said that the firm expected a bill to be introduced in the legislature this spring or summer that would allow for utilities to own generation. Other options include incentives for utilities to enter into power purchase agreements that go beyond the state’s default service auctions, or a “Baseload Energy Fund” that would be modeled on a program in Texas that paid for natural gas plants outside ERCOT’s market. (See PUC Shortlists 17 Projects for Loans from Texas Energy Fund.)

PPL is not the only utility that does business in Pennsylvania to endorse the idea of utility-owned generation. Exelon CEO Calvin Butler made comments during his own firm’s earnings call the same week endorsing the policy shift, saying the rapid load growth forecasted for the PJM region shows that “complementary” approaches to the market are needed to ensure adequate supply.

“It is clear that states are and should be proactively involved in supply solutions that complement the markets,” Butler said, “not to mention pursuing policies that enable more demand-side solutions. There is no single answer to meeting the levels of load growth that are anticipated. But instead, a variety of solutions across regulated and merchant participants is necessary.”

Cawley served on the PUC for two stints, in 1979-1985 and again in 2005-2015, so he has seen Pennsylvania as a regulated state and a competitive one. He said the change was for the best.

“When I first got into regulation, right after the Three Mile Island accident, there were all these nuclear power plants that were nearing completion, and then we had to decide how much of the cost would be allowed in the rate base,” Cawley said. “It’s an impossible test. Some construction project that’s been going on for 15 years with enormous cost overruns; that’s a game the utilities will win every time.” Utilities are masters at the accounting game; they know how to recover every cost, he added. But deregulation eliminated that. Competition ensures that customers do not bear the risk for massive cost overruns in generation construction, which was commonplace after Three Mile Island, he said.

Both PPL and Exelon used to be in the generation business, but both spun off their competitive firms, with Talen Energy and Constellation Energy as the results, respectively. Now the utilities are using scare tactics to get back into the generation business, but without the risks facing competitive generators, Cawley argued.

“It’s an effort to confuse people, to get legislators afraid that reliability is somehow going to suffer because there won’t be enough added generation,” Cawley said. “Well, that’s certainly nonsense. In Pennsylvania, we have been a net exporter of power for decades, and it’s going to stay that way, at least for another 10 years, even if nothing was built.”

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PJM MRC/MC Preview: Feb. 20, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 13: Emergency Operations to establish new wildfire procedures for the RTO and transmission owners to follow ahead of and during fire conditions that could impact

Issue Tracking: Wildfire Procedure

C. Endorse proposed revisions to Manual 40: Training and Certification Requirements drafted through the document’s periodic review.

Endorsements (9:10-10:10)

  1. Manual 14H: New Service Requests Cycle Process Revisions (9:10-9:30)

PJM’s Jonathan Thompson will review proposed revisions to Manual 14H detailing the site control requirements for projects in the interconnection queue. Voting on the changes has been deferred twice as some developers seek alternative language to revisions they argue would be overly onerous and require them to hold onto land unnecessary for the completion of their projects. PJM has countered that clear rules are needed that can be applied to all projects in the queue. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

Issue Tracking: Site Control Modification Clarification 

  1. DR Availability Window (9:30-10:10)

PJM’s Pat Bruno is set to review two proposed packages to revise the availability window for demand response (DR) resources and how they are modeled in the RTO’s effective load carrying capability (ELCC) analysis. The proposals would replace the window with modeling output in all hours, shift the winter peak load (WPL) of each resource to be measured at a set hour, and create an average load profile for DR participants to be used in the ELCC analysis. The two packages differ in which year they would apply to, with the main motion starting implementation in the 2027/28 delivery year and the alternate being effective one year earlier. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)  

Issue Tracking: DR Availability Window 

Members Committee

Endorsements (11:50-12:05)

  1. The MC will consider same-day endorsement of the proposed revisions to the DR availability window. Expedited consideration is being sought to allow PJM staff to begin making the changes for the 2026/27 delivery year if the alternative is endorsed by the MRC. 
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DOE Conditionally Approves Commonwealth LNG to Export

The Department of Energy has approved the first authorization to export liquid natural gas from a new domestic facility since the Biden administration’s pause on new approvals. 

“Today marks one of many steps that DOE will be taking to assure our future as a reliable energy supplier to the world and resume regular order to our regulatory responsibilities over natural gas exports,” Energy Secretary Chris Wright said Dec. 14. 

The Commonwealth LNG facility, which will be built in Cameron Parish, La., is owned by Kimmeridge Texas Gas and will be able to export 1.2 Bcfd once it is built. 

The project won approval from FERC in 2022, but the case was remanded to it by a federal appeals court. FERC is working on a new, supplemental environmental impact statement, and a final order is expected this summer. 

Then-President Joe Biden paused DOE’s approval of additional exports in January 2024 so the department could study their impacts. A court overturned the pause over the summer, and Biden’s DOE approved exports from a facility built in Mexico in August. (See DOE Approves 1st LNG Exports Since Biden Administration’s Pause.) 

The department released the study in late 2024; it said exporting more LNG would lead to higher domestic prices for the sake of shipping gas not to just allies, but China with its massive demand for energy. Since the report, China has put tariffs on U.S. LNG exports in response to President Donald Trump’s imposition of tariffs on it. (See DOE Warns About Further Increases of US LNG Exports.) 

“We expect China’s imposition of tariffs on U.S. LNG to have a limited effect on U.S. LNG exports,” the Energy Information Administration said in its Short-Term Energy Outlook (STEO) for February. “With ample demand for LNG globally, we expect that any LNG not purchased by China would be imported elsewhere.” 

In the conditional order approving the exports, DOE found they are likely to yield economic benefits to the U.S., diversify global LNG supplies, and improve energy security for U.S. allies. 

DOE has approved a total of 46.88 Bcfd in exports of LNG from the Lower 48 states, with 39 final orders and the conditional order for Commonwealth. DOE expects to issue a final order later in 2025. 

EIA expects LNG exports will record highs in 2025, averaging 15 Bcfd, but so will domestic production — hitting almost 105 Bcfd, it said in the STEO. 

The outlook also noted that the very cold January contributed to higher natural gas price forecasts this year, adding 65 cents to the EIA’s 2025 average price forecast, which hit $3.80/MMBtu. 

The Industrial Energy Consumers of America was the only group to protest the application on time, arguing that the additional exports would put upward pressure on domestic natural gas prices, making its members less competitive. 

DOE responded that based on forecasts for high domestic production, the additional exports conditionally approved Feb. 14 would not increase prices in the U.S.  

“With these decisions in hand, subject to a FERC final order, which we expect in July 2025, and DOE final authorization, Commonwealth anticipates reaching a final investment decision in September 2025, with first LNG production expected in Q1 2029,” said Commonwealth CEO Farhad Ahrabi. 

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Board Orders MISO to Get Answers on IMM’s Role in Tx Planning

Board members have directed MISO to seek guidance on the role of the Independent Market Monitor in transmission planning following a year of IMM David Patton criticizing MISO’s nearly $22 billion long-range transmission plan (LRTP) portfolio.  

MISO’s Markets Committee of the Board of Directors voted unanimously on the measure in a special, virtual meeting Feb. 14. The motion from the board instructs MISO’s legal department to reach out to FERC for its perspective on whether the IMM should be scrutinizing the RTO’s transmission planning. It also directs MISO to communicate to the IMM that it will not pay for work related to transmission planning “until further direction from FERC.”  

MISO confirmed it received the committee’s directions. In a statement to RTO Insider, it said it is “working to determine the next steps to effectuate the committee resolution.”  

MISO IMM David Patton was a vocal opponent of the second LRTP portfolio throughout 2024, repeatedly telling planners they were overstating the benefits of the collection of mostly 765-kV lines and deeming the 20-year future assumptions that transmission needs were established upon unrealistic. Patton argued for a downsized portfolio. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan and $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.) 

While many MISO members have said the IMM should not interfere in transmission planning and should concentrate solely on markets, Patton has said he believes planning is within his scope of work because of how planning and markets “interact with one another.” 

The board’s potential IMM funding freeze comes as MISO is gearing up to update the 20-year scenarios it uses as the basis for long-range planning. MISO has planned a first workshop with stakeholders on the futures Feb. 28. The grid operator plans to retool the futures for the remainder of the year and embark on another LRTP portfolio in 2026. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.) Patton is likely to disagree with the temporary stop work order, though he ultimately declined to comment on the Markets Committee’s motion.  

MISO Director H.B. “Trip” Doggett said board members and MISO made a portion of the Feb. 14 meeting public in an effort to be more transparent about the board’s activities and budget items related to the IMM.   

By the end of 2024, MISO’s IMM budget was about $236,000 over an approximate $8 million allotment. Doggett said board members analyzed the overrun extensively and found it ultimately was linked to rooting out demand response schemes in the markets and work dedicated to taming market-to-market congestion between MISO and SPP after a North Dakota data center taxed a transmission constraint.  

Doggett said the Monitor’s assessments of the LRTP did not contribute to the cost increase. The committee approved the IMM’s 2024 budget, including overage, in full.  

MISO directors agreed it was time for the board to attempt to clear up the IMM’s authority. Director Nancy Lange said it was appropriate to get “clarity on future work related to the LRTP.”   

“I think it’s an important step,” Director Robert Lurie agreed.  

Some MISO members said they were concerned about the optics of the board’s decision.  

WPPI Energy’s Steve Leovy said while it’s fine for the board to want clarification around the IMM’s role, the whole “situation has a bad look to it” because the Monitor disagreed with MISO’s planning assumptions and benefit calculations. Leovy said he wondered if the board would take such action if the IMM had backed the second LRTP portfolio.  

“This has a bit of an appearance of retaliation, in my opinion. … A bit of an attempt to stifle the discussion,” Leovy said.  

North Dakota Public Service Commissioner Jill Kringstad said her state appreciated the IMM’s independent voice during the planning process. WEC Energy Group’s Chris Plante, speaking as a representative of MISO’s transmission-dependent utilities, also said he found the IMM’s perspective helpful, especially as he questioned the RTO’s processes.  

Following the meeting, ITC’s Brian Drumm said the Markets Committee’s unanimous approval to confirm that the IMM’s scope of duties “do not extend to participation in MISO’s transmission expansion planning processes will provide important clarity for MISO and its stakeholders going forward.”  

Drumm pointed out that MISO has said before that it believes recommendations related to transmission planning are outside the scope of the Monitor’s duties. 

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Anti-nuclear Groups Challenge Palisades Reopening

Anti-nuclear groups have united in an attempt to stop Michigan’s Palisades Nuclear Generating Station from being brought back to life.  

The coalition — Beyond Nuclear, Don’t Waste Michigan, Michigan Safe Energy Future, Nuclear Energy Information Service of Chicago and Three Mile Island Alert of Pennsylvania — argued in front of a trio of administrative law judges from the Nuclear Regulatory Commission’s Atomic Safety and Licensing Board Panel that neither the NRC nor owner Holtec is putting enough thought into the restart of the plant.  

Holtec aims to bring Palisades back online in October. (See Holtec Confident on Late 2025 Restart of Palisades Nuclear Plant.)  

To revive Palisades, Holtec needs an exemption on the certifications granted as previous owner Entergy was shutting down the plant. The certifications prohibit operation of the reactor or placement of fuel into the reactor vessel. Additionally, Holtec needs four license amendments that will allow it to refuel the plant and restart operations. The quartet of amendments would alter technical specifications, revise an emergency plan to support the return of operations and update the methodology for studying potential consequences of a main steam line rupture.  

Beyond Nuclear and others entered a request for hearing in Holtec’s exemption and amendment requests (50-255). Oral argument pre-hearings were held virtually Feb. 12.  

Coalition attorney Wally Taylor said restarting a reactor in decommissioning status should require “more than just some paper shuffling, as Holtec and the NRC suggest.” 

Taylor argued that Holtec requires a new operating license, not a license adjustment to reopen Palisades.  

Taylor said Holtec and NRC “cobbled together a plan … to try to accomplish a restart” with licensing exemptions and adjustments because there is no regulatory pathway to restarting a closed and decommissioned nuclear reactor. He said Holtec and NRC’s “ad-hoc, patchwork” method to relicense a closed nuclear plant runs afoul of the Atomic Energy Act.  

According to the coalition, Holtec and the NRC are cherry-picking regulations that will ensure a restart while bypassing a new Updated Final Safety Analysis Report. The group said Holtec has admitted that “current regulations do not specify a particular mechanism for reauthorizing operation of a nuclear power plant after both certifications [regarding decommissioning] are submitted on the docket and before operating license expiration.” 

“Since there is no dedicated regulatory procedure for restarting a closed reactor, the NRC has no authority to approve the license amendments requested by Holtec,” the coalition argued in its October request for hearing.  

The group said Holtec currently holds an operating license that specifies that fuel is permanently removed from the core while no new fuel is introduced in the reactor. Absent a fresh license, the group argued that Palisades shouldn’t be allowed to produce electricity.  

The anti-nuclear groups also argue that the NRC is duty-bound to draw up a full environmental impact statement for a Palisades return pursuant to the National Environmental Policy Act. Taylor said NRC staff erred by not ordering one and Holtec erred by not submitting an environmental report.  

NRC staff issued a draft environmental assessment in mid-January that found no significant impacts; the regulatory body doesn’t plan to move to a more intensive environmental impact statement.  

Michael Spencer, attorney for NRC staff, argued the coalition’s petition is inadmissible because the arguments attack existing regulatory frameworks or are outside of the scope of the case.  

Spencer also said the case involves an already constructed plant that safely operated for decades when Entergy voluntarily shut it down before its 2031 license end date. He pointed out that Holtec is attempting to restore a license to a plant that has undergone previous safety and environmental reviews.  

Spencer said the case is “not a forum for broader” debates about a Palisades reopening. He said the groups did not limit their arguments to the procedure and attacked the plant’s restart.  

Stan Blanton, an attorney for Holtec, said the groups inappropriately challenge NRC’s authority to permit a nuclear plant restart. He said Holtec’s plan is to “simply restore Palisades to its pre-decommissioning status.”  

“There’s no question about what regulations need to be followed,” Blanton argued, adding that Palisades has an operating license in effect that is applicable to NRC’s restart authority.   

Blanton said Holtec maintains the restart would not cause a major environmental impact that would require a formal environmental report.  

Blanton agreed with an administrative law judge’s statement that Holtec’s license exemption request can be likened to an officer waving a motorist through a red light.  

But the anti-nuclear groups argued that “Holtec’s legerdemain, to force all of the safety oversight for Palisades through the tiny eyelet” of a code in the federal regulations, “runs into the laws of chemistry and physics.”  

The groups contended that Holtec’s current path to a Palisades resurrection is a violation of 10 CFR 50.59, titled “Changes, tests and experiments,” in the Code of Federal Regulations. They maintained that Holtec should have petitioned the NRC before undertaking significant work at the reactor.  

“Without proper layup and very suspect planning for the reopening of Palisades, this aged, degraded reactor almost inevitably will face unforeseen engineering and operational difficulties, hitherto unrecognized safety issues, and the cussedness that accompanies any obsolescent machine or vehicle,” the coalition warned in its hearing request.  

The anti-nuclear groups’ petition included expert testimony from Arnold Gundersen of Fairewinds Associates, who argued that after Entergy terminated the old Palisades operating license, a permit cannot be reissued to Holtec “without Palisades meeting the new, more stringent safety criteria of the 21st century.”  

Gundersen said since nuclear plants’ design basis assumptions are dramatically different than in the mid-1960s, the NRC must compel Holtec to revisit the plant’s assumptions. Gunderson said worsening climate change likely would create more frequent “unanticipated scenarios” outside of the design bounds. 

Gundersen also said he was concerned about damage from internal vibrations to the plant’s steam generator and Entergy disposing of “indispensable” quality assurance records. He said Holtec was moving at a reckless pace, borrowing a phrase from Union Admiral David Farragut as he commanded his fleet to enter Mobile Bay: “Damn the torpedoes. Full speed ahead.” 

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SPP Secures Funding to Begin Markets+ Phase 2

SPP said Feb. 14 it has received enough commitments to support the funding necessary for Markets+’s second developmental phase, the buildout of market systems that will begin in the second quarter of this year.

The grid operator said it has received signed Phase 2 funding agreements from eight interested participants in its proposed day-ahead service offering, including Arizona Public Service, Bonneville Power Administration, Chelan County (Wash.) Public Utility District (PUD), Grant County (Wash.) PUD, Powerex, Salt River Project, Tacoma Power and Tucson Electric Power.

Powerex, the marketing and trading arm of Vancouver, British Columbia-based BC Hydro, and Chelan PUD announced their Phase 2 funding commitments in January. (See Powerex Commits to Funding, Joining SPP’s Markets+ and Chelan PUD Commits to SPP Markets+ Phase 2 Funding.)

SPP noted in a statement that the entities operate a diverse mix of generating resources and serve more than 216,000,000 MWh in the Western Interconnection’s Desert Southwest, Pacific Northwest and Mountain West regions.

“The continued engagement and support of Markets+ by Western entities has certainly driven this day-ahead market one step closer to reality during this critical time for our industry,” SPP CEO Barbara Sugg said in the statement.

SPP said it will finance the projected $150 million in implementation costs, recovering them through the Markets+ operations. Staff said they have not distributed other funding agreements and do not yet have a full list of Phase 2 participants.

“There may be more coming,” SPP spokesperson Meghan Sever told RTO Insider.

The RTO said it will post exact financial commitments for Phase 2 funding on Feb. 17. Funding obligations will be based on the participants’ load share.

Powerex and BPA were the leading funders of Phase 1, meeting obligated 20.2% and 15.2% shares, respectively, for the phase’s $9.7 million in costs. Powerex was charged $1.96 million and BPA $1.47 million.

Public Service Co. of Colorado was the only other participant with a share above 10%, being charged 12.3% of Phase 1’s cost, about $1.19 million. PSCo has not yet returned to SPP a financial commitment agreement for the next phase.

Funding shares for all Phase 2 participants have increased due to the withdrawal of some entities from Markets+ development.

The grid operator gave interested Phase 2 financial backers a Feb. 14 deadline to submit executed funding agreements, a two-month extension from its original December target. It said the agreements are vital to meeting the Markets+ launch date of 2027.

FERC approved the Markets+ tariff on Jan. 16. (See SPP Markets+ Tariff Wins FERC Approval.)

BPA Looking at $26.6M Commitment

During Phase 2, stakeholders and SPP staff will work together to develop the systems needed to operate the market and conduct market trials and parallel operations.

BPA spokesperson Doug Johnson told RTO Insider the agency’s “initial commitment could be up to $26.6 million depending on the final number of Phase 2 funding participants.” The federal agency said it still plans a March release of its draft day-ahead market policy. It will issue a final decision in May.

BPA and SPP have differed over whether the Phase 2 funding is an actual commitment to join Markets+. In a December letter, a group of U.S. senators referenced an SPP statement that asserted, “[implementation] activities cannot begin until prospective market participants execute Phase 2 funding agreements, essentially committing to join Markets+.” (See BPA Has not Made ‘Business Case’ for Markets+, NW Senators Say.)

In response, BPA Administrator John Hairston rebuffed the assertion, saying “Phase 2 funding is not a commitment to joining Markets+; it is a commitment to continue funding development of the market.”

Hairston also noted that BPA will provide $25,000 toward the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets, SPP’s competitor in the West. (See In Letter to Senators, BPA Tempers Markets+ Leaning.)

SPP has maintained it simply wants to give Western entities a choice in markets. Its COO, Antoine Lucas, told RTO Insider during an October interview that the debate over day-ahead markets appears to be focused on pressuring entities into a market selection, “rather than work directly with those Western entities to truly understand what their issues and concerns are, and also work to try and accommodate them and address those issues so they want to choose to be within that market.” (See SPP Sees Bias in Brattle Western Market Studies, Exec Says.)

The RTO included comments in its news release from several Phase 2 participants who expressed their support of Markets+.

Chelan PUD’s Janet Jaspers said SPP’s market “offers consensus-driven, stakeholder-led governance” and an “equitable market design” that leverages the Western Resource Adequacy Program.

“We look forward to bringing the benefits of Markets+ participation to our customers and the western region,” Salt River Project’s Josh Robertson added.

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Tacoma Power to Join SPP’s Markets+

Tacoma Power has signed an agreement to join SPP’s Markets+, making the Washington utility the second Pacific Northwest entity to commit to participating in the market in the past month.

The Feb. 13 announcement comes as little surprise, given that Tacoma has been among the Western entities contributing to the series of “issue alerts” published since last summer favorably comparing Markets+ with CAISO’s Extended Day-Ahead Market. (See Pathways Step 2 Not Good Enough, Markets+ Backers Say.)

The municipal utility also has been counted among the majority of the Bonneville Power Administration’s base of publicly owned utility “preference” customers urging the federal power marketing administration to sign on to the SPP effort.

“A diverse group of electric utilities came together with a common goal: to build an energy market that will benefit our customers by optimizing how utilities in the West buy and sell electricity,” Chris Robinson, Tacoma Power’s general manager, said in a statement. “We’ve accomplished this with a durable and independent governance structure that will provide the right value for hydropower and will ensure the benefits continue flowing to our customers far into the future.”

Tacoma’s Public Utility Board approved the utility’s commitment to Markets+ last November, according to the statement.

“Tacoma Power will continue to participate in ongoing market development over the next two years. This will create the systems that will enable Markets+ to operate while Tacoma and other utilities complete the internal onboarding steps necessary to integrate market operations,” the utility said.

According to a spreadsheet posted to SPP’s website last October, Tacoma would be responsible for a 1.7% share of the funding for the Phase 2 implementation phase of Markets+, equating to more than $4.8 million.

Tacoma Power serves more than 180,000 electric customers in the city of Tacoma and nearby communities, as well providing power to the U.S. military’s Joint Base Lewis-McChord. The utility owns about 643 MW of hydroelectric generation, which account for more than 80% of its nearly carbon-free resource mix. It also operates 2,386 miles of transmission and distribution lines.

The utility’s announcement follows a similar one by Powerex, the largest Markets+ funder, which in January said it had committed to joining and paying its share of Phase 2 funding. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

Last month, Chelan County Public Utility District, another publicly owned utility in Washington, committed to funding Phase 2 but said it still had not decided to join the market. (See Chelan PUD Commits to SPP Markets+ Phase 2 Funding.)

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Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’

A new paper from Powerex is likely to reignite the debate between supporters of CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ just as the competition between the two markets approaches critical junctures. 

Chief among them: the pending introduction of legislation in California to allow CAISO to relax its oversight over its Western markets; the Bonneville Power Administration’s impending draft decision on a day-ahead market choice; and an expected continuation of participant commitments to both markets. 

The paper, which Powerex published Feb. 11, contends that EDAM contains a “design flaw” that could saddle non-CAISO participants with $1 billion in unjustifiable charges that effectively would be conveyed as payments to participants operating within the ISO. 

Powerex contends EDAM’s treatment of firm transmission rights and congestion would leave the market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while not providing them adequate ability to recover or hedge against those costs — what the company calls an “aberration” among organized markets. 

“The PacifiCorp, NV Energy and Idaho Power transmission systems are the most exposed to this outcome, including when the utilities use their own transmission systems to deliver their own generation to their own load,” Powerex wrote in the paper. 

The potential “transfer of value” could have a “wide range of harmful consequences” in those service territories, including: raising costs for retail ratepayers; eliminating incentives for third parties to invest in transmission service; shifting the benefits of non-CAISO transmission expansion projects to ISO customers; and “undermining the proper functioning of other regional programs and markets,” such as the Western Resource Adequacy Program and Markets+. 

Powerex’s assertions prompted a sharp response from CAISO and PacifiCorp, the first utility to commit to joining EDAM and whose recent tariff filing apparently prompted the concern. 

“Powerex, a primary funder of Markets+, continues to publish hyperbole and unsupported assertions, with economic impact estimates that defy market logic,” CAISO Director of Communications Jayme Ackemann and PacifiCorp spokesperson Omar Granados said in a joint statement to RTO Insider. 

Ackemann and Granados called the paper “misinformed and inflammatory” and said it represents “an attempt to derail” EDAM “rather than improve it.” 

Vancouver, Canada-based Powerex is the marketing subsidiary of BC Hydro, the Canadian Crown corporation that provides power for most of British Columbia and operates about 11,680 MW of hydroelectric capacity. Through a trading operation that spans the Western Interconnection, Powerex owns transmission rights on multiple systems throughout the sprawling region. 

The company currently participates in CAISO’s Western Energy Imbalance Market (WEIM) but has been a key backer of SPP’s Markets+ in its competition with EDAM for day-ahead participants and, in that capacity, a vocal critic of CAISO and its EDAM. Powerex recently committed to joining Markets+ and providing a substantial share of funding for Phase 2 implementation stage of the market. (See Powerex Commits to Funding, Joining SPP’s Markets+.) 

On the other hand, PacifiCorp — along with Portland General Electric — is scheduled to begin trading in EDAM next year, while NV Energy and Idaho Power are heavily leaning in favor of joining the CAISO market. 

Parallel Flows

The complexity of Powerex’s argument mirrors that of how energy flows on the electricity grid — and how those flows are reflected in the rules and processes of organized wholesale electricity markets. 

Powerex notes that under FERC’s Open Access Transmission Tariff (OATT) framework of transmission rights, “entities that invest in firm OATT transmission service obtain the right to deliver generation from lower-price locations to load in higher-price locations.” 

The company also points out that — as in other markets — EDAM will be “layered” on top of that framework, requiring a resource to sell its supply at one locational marginal price, while an end user will pay a different LMP at the point of consumption.

And as in other markets, EDAM electricity deliveries will be subject to a “net financial settlement” that reflects the difference between the prices at the two locations — which can include charges stemming from the congestion on the lines between those points. 

The assessment of congestion charges is complicated by the fact that flows of energy associated with a scheduled delivery do not always follow the “contract path” but often are channeled through a neighboring system, producing “parallel” flows on that system. 

In EDAM, Powerex contends, this means a delivery scheduled between PacifiCorp’s East and West balancing authority areas, for example, could produce a parallel flow that causes congestion in the CAISO BAA. EDAM then would apply the charge for that congestion to the PacifiCorp transaction. 

Powerex contends EDAM deviates from “all other” U.S. markets because it does not provide “a financial hedge that returns the day-ahead congestion charges on a delivery path back to the entities with firm transmission rights on that delivery path” — as required by FERC. 

“Instead, EDAM will allocate congestion revenues based on the modeled locations of congestion ‘bottlenecks,’” the paper says. 

Powerex says WEIM data show that the “most prevalent” of those bottlenecks occur in CAISO’s system. 

“Under the EDAM design, this means the California ISO’s customers can be expected to receive the vast majority of the flow-based congestion charges collected from activity on other transmission systems throughout the EDAM footprint,” the paper says. 

Powerex contends that in every electricity market in the U.S. but EDAM, customers using service from one transmission service provider (TSP) are either not liable for the cost of parallel flows on other systems, or able to mitigate that cost through specific market mechanisms, such as hedging instruments like financial transmission rights. In the case of Markets+, congestion charges will be returned to the firm rights holder. 

“This EDAM market design flaw will have the greatest impact on those adjacent transmission systems outside of California that also provide significant north-to-south and south-to-north connectivity: namely, PacifiCorp, NV Energy and Idaho Power,” Powerex wrote. “If each of these utilities join EDAM under its current design, it will be … [CAISO’s] own customers that will collect the vast majority of the locational price difference from activity on the PacifiCorp, NV Energy and Idaho Power transmission systems.” 

‘Completely Meaningless’

Powerex said the issue came to light in January when PacifiCorp filed with FERC its EDAM tariff, which noted the utility could offer its firm transmission customers only a “partial hedge” against congestion charges. That hedging option would reverse only the portion of congestion related to transmission constraints modeled within PacifiCorp’s system, “even though the schedules would pay congestion charges that also include parallel flows on other transmission systems,” Powerex contended. 

In November, Powerex announced it would cancel a large portion of its transmission rights on the PacifiCorp system in response to the expected OATT changes. (See Powerex to Cancel Rights on PacifiCorp Tx System over EDAM Changes.) 

Powerex said its experience in the WEIM “shows unambiguously” that the transmission constraints that most often limit physical flows between locations throughout that market are in CAISO. 

“Since the EDAM design distributes congestion charges based on the location of the constraints that cause LMPs to separate, and data shows these constraints will predominantly be located in … [CAISO’s] transmission system, once EDAM commences, customers that use PacifiCorp transmission service will pay large new congestion charges that will go almost entirely to … [CAISO’s] own customers,” Powerex said. 

Under one scenario modeled to show heavy solar penetration in the Southwest, Powerex found the “value transfer” from non-CAISO BAAs to CAISO to reach $1 billion annually, a figure not reflected in production cost modeling studies that repeatedly have shown that most Western entities will realize greater economic benefits from participating in EDAM than in Markets+, including a series of studies performed by The Brattle Group. 

“All of the EDAM benefits studies to date have completely missed this important market design issue, and given its magnitude, the results of these studies are completely meaningless,” Powerex said. 

‘Feigned Concern’

“Focusing narrowly on one aspect of market design, in isolation, conveys an intentionally distorted picture,” CAISO and PacifiCorp said in their joint statement. “As a power marketer, Powerex is simply attempting to force changes to the EDAM market design that have already been approved by FERC for its own economic interest.” 

They also contend that, based on the assumed EDAM market footprint, it is “illogical” to estimate that the three cited BAAs would be forced to pay $1 billion in congestion revenues for congestion occurring in CAISO. 

“Such claims, which Powerex attempts to cloak in feigned concern for NV Energy, Idaho Power Co. and PacifiCorp customers, are not supported by the analysis from the very entities that are responsible for providing service to those customers,” they said. 

They said the FERC docket (ER25-951) for PacifiCorp’s EDAM tariff is the “appropriate venue” for Powerex to air its concerns about the market. 

“While we appreciate Powerex’s continued engagement in Western energy market design, its approach continues to be counterproductive,” CAISO and PacifiCorp said. 

In an email to RTO Insider, Brattle Group principal John Tsoukalis said his company’s EDAM benefits studies “have repeatedly found results that are consistent with the actual experience in WEIM over the last 10 years”: that ISO customers “in fact receive less benefits on a load-ratio-share basis than other market participants due to the fact that CAISO already has a day-ahead market in place.” 

He said the allocation of congestion revenues “is necessarily simplified in our studies, which means that real-world congestion revenue allocations may differ from our estimates,” adding that those revenues are only one metric examined in the studies. 

“Of course, it is possible that EDAM implementation might uncover some revenue allocation issues that will need to be addressed, just as PacifiCorp’s filing addresses some items that have come up and CAISO stakeholder processes have addressed issues in the past,” Tsoukalis told RTO Insider. 

Tsoukalis additionally contended that Powerex’s paper did not provide enough detail to replicate its analysis and “vet its conclusions” and that it failed to cover several aspects of EDAM that will differ from the WEIM, including expectations that: 

    • EDAM participants will contribute significantly more transmission than they do in WEIM, thereby reducing congestion;  
    • major new transmission projects under development are likely to “significantly reduce” and change the pattern of congestion; and 
    • optimized day-ahead unit commitment and dispatch “will further increase the effectiveness of how the existing grid is used.” 

Tsoukalis also pointed out that EDAM will disaggregate price differences between areas into congestion revenues and “transfer” revenues collected when a transfer constraint results in differentials between two BAAs. 

“The [Powerex] memo does not discuss the transfer revenue portion of the EDAM design, which means that EDAM congestion revenues will be more limited than the price differences that [Powerex] uses in its illustrations,” he said. 

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Mass. DPU Proposes Major Shift in Gas Line Extension Policies

The Massachusetts Department of Public Utilities has proposed requiring customers who request new gas service to cover the full cost of any needed line extensions, which effectively would end the gas utilities’ practice of spreading these costs across their rate base.

The proposal is the latest step in the department’s docket focused on aligning gas regulations with the state’s statutory decarbonization requirements (DPU 20-80).

Under the current rules, the utilities are not allowed to subsidize new gas connections through the existing rate base. However, a utility may charge the connection costs to the rate base if it expects to recover the costs from the additional revenues received from the new customer.

In late 2023, the DPU issued a major order setting the regulatory framework for the state’s transition away from natural gas, which announced the department’s plans to reform the “standards for investments to serve new customers.” (See Massachusetts Moves to Limit New Gas Infrastructure.)

The DPU directed the local distribution companies (LDCs) to review their tariffs, policies and practices regarding line extensions, specifically inquiring about “de facto free extension allowances” and “whether existing state policies are inconsistent with current practices by incentivizing new customers to join the gas distribution system.”

The utilities filed testimony in 2024 detailing their line extension procedures, providing some insight into their extension policies and the scope of the demand for new gas service.

Data from Eversource and National Grid’s testimonies indicate the companies continue to add thousands of gas hookups each year, although the annual number of new connections generally has decreased over the past 10 years.

The gas companies testified their expansion policies are consistent with state climate policy, while climate advocacy groups — along with the state Attorney General’s Office and Department of Energy Resources — argued the policies undermine state programs to reduce gas use.

In testimony submitted to the DPU, a representative of National Grid said the “addition of new customers must be viewed in conjunction with the elimination of leak prone pipe and other gas infrastructure work which may reduce GHG emissions to determine if the company is meeting its emission reduction targets.”

They added that the “the implications of connections policy for GHG targets must also consider interactions and dependencies across sectors and fuels.”

Pushing back on the utilities’ claims, the research firm Groundwork Data, with funding from the Conservation Law Foundation, Environmental Defense Fund and Sierra Club, made the case that utilities’ extension procedures “are inconsistent across LDCs, increasingly inconsistent with the principle that existing customers should not subsidize new customers, and inconsistent with state climate policy.”

“Since 2018, approximately 80% of new service-only connections have been provided at no cost,” Groundwork Data wrote. “The average cost of adding new customers was $9,000 in 2023, totaling over $160 million across the Massachusetts LDCs.”

‘Pretty Big Deal’

The DPU appeared to side with the environmental groups and government agencies in its draft policy, which directs the utilities to “require a customer seeking an extension for new gas service to pay for the entire cost of connecting to the distribution system,” unless the customer can qualify for an exception.

To qualify for an exception, the utility would need to show the extension would drive a “demonstrable reduction” in emissions, be consistent with the state’s climate limits, and that the customer has “no feasible alternatives” to natural gas.

Keeping with the current rules, the utilities also would have to ensure the cost of adding the connection does not exceed the added revenues they expect to receive from the new customer, “so that existing customers do not subsidize the cost of the extension of service,” the DPU wrote.

Ben Butterworth, of the Acadia Center, called the draft policy “a pretty big deal,” adding that it likely will result in “a significant reduction in terms of the growth of the system.”

“Obviously those three variables are open to interpretation by the commission, but my interpretation is the vast majority of projects would have an extremely hard time meeting those criteria,” Butterworth said.

National Grid and Eversource declined to comment on the draft policy. The DPU set a March 13 deadline for comments.

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BPA Committed to Trump’s Energy Goals, Hairston Says

Bonneville Power Administration CEO John Hairston said during the agency’s quarterly business review Feb. 13 that BPA is committed to President Donald Trump’s goal to “unleash American energy dominance,” while also revealing that approximately 200 BPA federal employees have accepted the president’s deferred resignation offer. 

About 6% of BPA’s federal workforce have opted into the Office of Personnel Management’s (OPM) deferred resignation program, and the agency has rescinded 90 job offers following a hiring freeze on federal employees imposed by Trump on Jan. 20, staff said during the quarterly business review.  

About 2.3 million federal employees received the buyout offer in a Jan. 28 message titled “Fork in the Road.” Employees who accepted the offer would receive a severance package 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 offer is one of many actions, including a flurry of executive orders, that Trump has taken since regaining the presidency on Jan. 20, which have directly impacted BPA. Another example is the order on Unleashing American Energy. 

BPA Administrator Hairston acknowledged there is “a lot of interest in BPA implementation of President Trump’s executive orders, and how those orders are expected to impact our business.”  

“We see great opportunity in supporting and advancing the administration goals to unleash American energy dominance, and indeed, Bonneville will play a key role in our region as we continue to execute our mission by delivering safe, reliable transmission services,” Hairston said. 

BPA has taken other actions in light of recent executive orders, including shutting down a culture office under the agency’s Diversity, Equity and Inclusion program and requiring workers to return to the office full-time. BPA also is updating its strategic plan to align with the Trump administration’s direction, Hairston said. 

Veronica Wittig, acting chief financial officer at BPA, said the agency works closely with the Department of Energy to carry out Trump’s directives. BPA forecasts negative net revenues of $44 million in the first quarter of 2025, compared with BPA’s target of positive $70 million, Wittig said. 

“The Q1 forecast was developed based on information at the end of December 2024 and does not reflect the impact of executive order on BPA’s financial forecasts,” Wittig said. 

Additionally, Wittig noted, “there is significant uncertainty at this time of the year with respect to water conditions and market prices, so net revenues picture may change significantly, which may also impact some of our other financial [key performance indicators].” 

The call also touched on other BPA initiatives, including the agency’s work to offer new long-term power contracts under its provider-of-choice program. BPA hopes to have final contract templates by June with signed contracts by December, according to Hairston. 

Hairston noted the pause on several transmission planning processes spurred by 65 GW of transmission requests.

The agency also is on track to release its day-ahead market draft policy in March, followed by a final policy and record of decision in May, Hairston said, referring to BPA’s upcoming choice of whether to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market. 

Additionally, on Jan. 30, BPA broke ground on a new control center located in Vancouver, Wash., which will be fully integrated into BPA’s system by 2031, Hairston said.  

“It will begin a new era of grid visibility and control for BPA,” Hairston said. “The new facility has been intelligently designed to address evolving technology, continuity, safety and security needs. Its design will support the evolution of the bulk power grid over the next 50 years, while providing flexibility for growth and market opportunities.”