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February 16, 2025

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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 $1.42 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.” 

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NERC Leaders Highlight Canada-US Collaboration

MIAMI — Addressing NERC’s Member Representatives Committee and Board of Trustees, CEO Jim Robb said “the recent kerfuffle” over trade tariffs between the U.S. and Canada should not affect the ERO’s ability to work on electric reliability issues on both sides of the border.

Robb acknowledged that President Donald Trump’s proposed tariffs on trade with Canada have created “turbulent waters” between the two countries since the board’s last meeting, as did outgoing Chair Ken DeFontes in his opening remarks. Trump announced a 10% tariff on energy imports from Canada on Feb. 1, only to pause its implementation for 30 days Feb. 3 after promises from Prime Minister Justin Trudeau regarding drug interdiction and immigration.

Derek Olmstead, CEO of Alberta’s Market Surveillance Administrator and representative of Canada’s Energy and Utility Regulators, observed that while the proposed tariffs could lead to difficulty with supply chains, that did not erase the fact that the countries “have common interests that are very much aligned.”

Robb agreed, calling NERC “a great model of international collaboration.”

NERC holds one of its four board meetings in Canada each year; the upcoming August meeting is planned for Calgary, Alberta.

Keenan Steps up to Board Chair

Several of NERC’s leadership positions changed hands at the board meeting. Most notably, DeFontes handed over leadership of the board to Suzanne Keenan, who was elected to succeed him in February 2024. (See NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.)

Trustee George Hawkins has stepped up to take Keenan’s place as vice chair, a position he previously held until Keenan replaced him in that role last February.

DeFontes will remain with NERC as a trustee, having been reelected to another three-year term at the meeting of the MRC that preceded the board meeting.

Trustees Jane Allen and Colleen Sidford also will return for a new term; however, the seat left by departing Trustee Bob Clarke — who is not eligible for renomination because he already has served for 12 years — will remain vacant. Larry Irving, chair of NERC’s Nominating Committee, explained the group elected to defer the search for a new trustee to allow more time to find the best candidate to handle “the current speed of change” in the grid and the technology, security and policy landscape.

MRC Chair Jennifer Flandermeyer also handed off her position to Vice Chair John Haarlow, CEO of Snohomish County Public Utility District. Matt Fischesser of ACES Power will take over as vice chair.

The board passed resolutions honoring both DeFontes and Clarke for their service to the ERO, along with Stan Hoptroff, who is retiring after 10 years as NERC’s vice president of business technology. Hoptroff announced his retirement last year along with Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center; Robb told attendees that Cancel has agreed to defer his retirement until a suitable replacement is found.

Task Force to Examine Standards Process

Having twice exercised their authority to accelerate standards development in order to avoid a pressing deadline, trustees voted at the meeting to take the first steps toward updating NERC’s standards development process.

The board voted unanimously to create the Modernize Standard Processes and Procedures Task Force, originally suggested at the MRC’s November meeting. Greg Ford, CEO of Georgia System Operations Corp., will serve as chair and Todd Lucas of Southern Co. will serve as vice chair. Trustees Sue Kelly and Rob Manning will join as well, with ERO staff, NERC committee chairs, industry representatives and subject matter experts filling the remaining seats.

The task force will conduct a strategic review of the development process and submit recommendations in 12 months for “a modernized standard development process that … ensures that time [from] risk identification and prioritization to reliability standards development can be completed [in] a much more efficient and effective manner.”

NERC Chief Engineer Mark Lauby told trustees the effort is intended to make the standards process more responsive to the growing pace of change in the risk environment, which has made it increasingly difficult for NERC’s consensus-based approach to keep up with new threats to grid reliability.

This challenge was put on display twice since August, as the board was forced to invoke Section 321 of NERC’s Rules of Procedure when the normal process looked unlikely to result in a suitable standard to meet deadlines set by FERC. Trustees turned to Section 321 first in August to break an impasse over ride-through requirements for inverter-based resources, and again in January to authorize the Standards Committee to take over development of a cold-weather standard. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.)

Keenan urged Ford and Lucas to look at every aspect of the standards development process to find any opportunities for improvement but also reminded them that “the process needs to remain stakeholder-based, with reasonable notice, opportunity for public comment, due process [and] openness.”

Soo Jin Kim, NERC’s vice president of engineering and standards, also provided an update for the board on the status of Project 2024-03 (Revisions to EOP-012-2), the subject of the second use of Section 321. Kim told trustees the Standards Committee has posted the proposed cold weather standard, EOP-012-3 (Extreme cold weather preparedness and operations), for a public comment period that will end March 12.

When the comment period has concluded, the committee will submit the standard to the board along with a complete record of its development, including comments. A special board meeting to vote on the standard has been scheduled for March 25, Kim said.

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DTE Energy Ups 5-Year Plan to $30B

DTE Energy has announced it will expand its five-year capital expenditure plan to $30 billion, a $5 billion increase in investment. 

During a Feb. 13 year-end earnings call, CEO Jerry Norcia said the increase will help the utility improve reliability and transition to a cleaner fleet in accordance with Michigan’s 100% clean energy mandate by 2040. Norcia said the plan has the potential for incremental investment above $30 billion depending on “data center opportunities.” 

“This $5 billion increase is a significant increase to our capital plan and is driven by the need to build out renewables to meet the increased demand from the success of our My Green Power voluntary renewable program and to support Michigan’s clean energy legislation, as well as the need to continue to invest to improve reliability for our customers as we continue our efforts to update and modernize our electric grid,” Norcia said. 

Norcia told shareholders that DTE has “a solid, long-term development pipeline in place, providing clear line of sight on panels, land positions and permitting.” 

“We have panels secured through mid-2027, land positions that should take us into the 2030s and beyond, and permits secured for the majority of our projects through 2027,” COO Joi Harris added. 

Norcia said the updated plan includes an additional $3 billion in clean energy investment and $1 billion for improved distribution infrastructure to cut outage rates further. 

Harris said DTE was able to reduce outage durations by 70% over 2024. She said the utility over the next five years expects to further reduce power outages by 30% and halve outage time. 

In 2022 the Michigan Public Service Commission ordered an audit of DTE and Consumers Energy after ratepayer frustration with a “pattern of widespread, lengthy outages from increasingly severe storms.” 

Norcia said the company’s electric arm remains focused on potential demand growth from data centers in its service area. DTE recently signed a nonbinding preliminary agreement with an unnamed company, Norcia said, and if it comes to fruition, it could bring the company’s potential new data center load growth to 2.1 GW. DTE already has signed agreements for an artificial intelligence research facility at the University of Michigan and a 1.4-GW Switch data center complex using some of DTE’s land.

“We are also in discussions with multiple parties for additional opportunities beyond those that I just described,” Norcia said, adding that DTE is supportive of Michigan’s new law offering tax breaks to large data centers. 

Norcia said that while DTE is sitting on some excess capacity to serve new data center load, the company likely must build new capacity in the near term. He said plans for baseload generation to support the growth would come in the utility’s 2026 integrated resource plan. 

DTE earned $1.4 billion ($6.83/share) over 2024 despite the warmest winter in more than 60 years, according to the utility. Over 2023, the company brought in $1.2 billion ($5.73/share) in operating earnings. It released an earnings per share guidance range of $7.09 to $7.23 over 2025. 

Norcia said 2025 performance will be bolstered by the Michigan PSC granting a $217.4 million increase in electric rates in January. The new rates went into effect Feb. 6. The hike in rates was less than half of the $456.4 million that DTE first requested in early 2024. 

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CAISO EDAM Pioneers Share Implementation Details

With go-live dates for its first two participants looming in May and October of next year, implementation activities for CAISO’s Extended Day-Ahead Market are ramping up. 

Representatives of PacifiCorp, Portland General Electric and CAISO gave updates on EDAM preparations during a Feb. 12 joint meeting of the CAISO Board of Governors and the Western Energy Markets (WEM) Governing Body. 

For PacifiCorp, which has an EDAM go-live date of May 1, 2026, much of the recent focus has been on its Open Access Transmission Tariff filing with FERC. 

The company initially filed the tariff in November but decided to withdraw it and submit a new filing Jan. 16. 

The new OATT incorporates a different methodology for congestion revenue allocation — a subject that gave stakeholders “some serious concerns,” according to Robert Eckenrod, PacifiCorp assistant general counsel. 

For example, Western Power Trading Forum questioned the tariff’s measured-demand approach to allocation and planned to file a FERC protest in January, a representative said in December. (See CAISO Leaders Look Ahead to 2025 with Confidence.) 

PacifiCorp was able to work around some limits of the methodology from the initial filing, Eckenrod said, and the new methodology is “more granular and more advantageous.” 

Other than the changes to congestion revenue allocation methodology, the OATT filing is the same as the initial filing. It requested a Feb. 18 due date for comments and a May 16, 2025, decision date. 

PGE Activity

Portland General Electric, which has an EDAM go-live date of Oct. 1, 2026, is planning to file its OATT with FERC by the end of March, said Tiffany Emerson, PGE’s senior manager of strategy and planning. PGE is working with PacifiCorp to align their tariffs, she said. 

As a participant in CAISO’s Western Energy Imbalance Market (WEIM), PGE plans to enhance existing systems and frameworks rather than starting from scratch, Emerson said. Testing of system enhancements will begin in December and continue into 2026. 

Another focus for PGE is settlements.  

“The sheer volume of the transactions that we’re going to settle with … CAISO in the post-go-live EDAM world is just an order of magnitude greater than what we currently do as an EIM participant,” Emerson said. 

WEM Governing Body member Andrew Campbell said he was encouraged to hear that PGE was working with PacifiCorp on EDAM implementation. 

“That’s certainly key to success in this process,” Campbell said. “The entities as they join are helping the ones who are joining after them.” 

In addition to PacifiCorp and PGE, the Balancing Authority of Northern California signed an EDAM implementation agreement with CAISO in November; the Los Angeles Department of Water and Power formally committed to joining in December. (See BANC Signs Agreement to Join EDAM; LADWP Gets Board’s OK to Join CAISO’s EDAM.) 

BANC and LADWP are scheduled to go live with EDAM on May 1, 2027. 

CAISO has been conducting EDAM training with PacifiCorp and EDAM and also has publicly posted training material on the WEM website. Computer-based training for EDAM entities is planned for April, according to Heather Kelley, executive director of CAISO’s project management office. 

CAISO plans to begin integration testing with PacifiCorp this summer.  

“We will be revving up our systems, and they’re going to be connecting to them, and we’ll start to get the market running,” Kelley said. 

Customer Outreach

Kerstin Rock, managing director of Western market policy and analytics at PacifiCorp, noted that some deadlines for EDAM participation are now merely weeks away. For example, the company plans to complete connectivity testing by June 1. 

PacifiCorp also is launching an engagement process for its transmission customers, with a series of workshops starting Feb. 27. Videos of the workshops will be posted on the company’s Open Access Same-time Information System (OASIS). 

CAISO Board of Governors Chair Severin Borenstein thanked PacifiCorp for doing the work that will “smooth the pathway” for other EDAM participants. 

“It’s all becoming real,” Borenstein said. 

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Duke Spending Big to Meet Increasing Load Growth in the Late 2020s

Duke Energy’s leadership changed the guard during its first-quarter earnings call Feb. 13 as retiring CEO Lynn Good and her replacement, Harry Sideris, split the presentation. 

Good announced her retirement effective April 1 early in 2025. (See Duke Names Harry Sideris as Company’s Next CEO.) 

Last year was defined largely by Hurricanes Helene and Milton, which hit Duke’s territory. Good thanked the communities it serves for their support and understanding as the utility restored service after the storms. Duke plans to spend $83 billion in the next five years to meet the growing needs of its utilities. 

“This capital represents infrastructure spending driven by growing jurisdictions and underpinned by robust regulatory processes such as integrated resource plans and approved grid investment spending,” Good said. “With the continuation of our 5 to 7% [earnings per share] growth rate through 2029, with the potential to earn higher in the range as the years progress, Duke Energy enters the back part of this decade in a position of strength, and we’re excited about the future.” 

Good said Sideris and the incoming chair of the board of directors, Ted Craver (formerly Edison International’s CEO), are up to the task of leading the utility. 

“I assume this new role at a pivotal point for our company and industry,” Sideris said. “We share the new administration’s commitment to ensuring the availability of reliable and affordable energy to meet our country’s aspirations for technology leadership and economic growth. These priorities align with our business strategy, and we look forward to working with President Trump, both parties in Congress and our states to build, operate and protect the critical infrastructure needed to deliver on these goals.” 

The needs to meet growing demand and replace aging infrastructure means the firm plans to invest billions of dollars in new generation and the grid, with Sideris saying the firm had a “decade of record infrastructure build.” 

A key source of the new demand for Duke’s utilities is going to be data centers. Sideris said that while Chinese artificial intelligence company DeepSeek’s efficient model might have made headlines and cut into chipmaker Nvidia’s stock, the hyperscale data center developers the utility has worked with already expected efficiency advances. 

“They’re full-speed ahead,” Sideris said. “They’re looking at the fact that these efficiencies may actually increase the demand for AI. So, we have not seen any pullback in anything they’re planning on. In fact, we’ve seen a lot more discussions with accelerating some of their work.” 

Many of the near-term data centers being built in Duke’s territory are not for AI but rather the growth in demand for cloud services, Good said. 

“Then as we move later into the plan, that’s where some of the generative AI data centers are coming in, and that’s when we see the larger load growth,” Sideris said. 

This year and next, Duke expects 1.5 to 2% load growth across all of its utilities, jumping to 3 to 4% in 2027 and staying there through 2029. Its core market of the Carolinas should experience slightly higher growth, with 2% this year and next heading to 4 to 5% for the rest of the 2020s. 

Duke plans to build about 5 GW of new natural gas-fired generation by the end of 2029, mostly in North Carolina, with just one of five plants located in Indiana. The firm plans to start procuring 1.5 GW of solar per year in North Carolina and an additional 900 MW of solar in Florida by 2027. 

The utility also will add storage in the coming years, and it could add small modular reactors by the mid-2030s. Of the $83 billion, Duke plans to spend $37 billion on its transmission and distribution systems. 

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AEP to Increase Investment in Face of Data Center Growth

American Electric Power told financial analysts during its fourth-quarter earnings conference call Feb. 13 that the company is evaluating $10 billion of potential incremental investment because of increasing interest from data centers and other large loads looking to build in its 11-state service territory.

“The tech companies are fast movers, and AEP will be there to support them with whatever technology solution they want to deploy, but we need to ensure that we are protected and compensated,” CEO Bill Fehrman told analysts.

The Columbus, Ohio-based company announced a record $54 billion capital plan in the fall that will last through 2029. Fehrman said AEP expects 20 GW of new load by the end of the decade, much of it in Ohio and Texas.

The utility added 450 MW in its home state in December. It expects an additional 4.7 GW of data center load to come online by year-end.

“We are investing in tailored solutions for new individual large loads to meet their requirements and timelines while mitigating rate impacts to existing customers,” Fehrman said.

AEP already has filed for approval of 2.3 GW of natural gas generation in its Public Service Co. of Oklahoma (PSO) and Southwestern Electric Power Co. service territories. It also has active requests for new generation proposals in Appalachian Power, Indiana Michigan Power and PSO to meet demand.

The company is waiting on a ruling from the Public Utilities Commission of Ohio over proposed tariffs for new large-scale data centers that would require them to pay 85% of their projected energy use each month to cover the cost of infrastructure. AEP filed a settlement agreement with PUCO in October.

“Clearly, we’re going to make sure that this doesn’t fall on the shoulders of our existing customers, and make sure that the appropriate parties who are driving the incremental cost will pay for the incremental cost,” Fehrman said.

AEP reported year-end earnings of $2.97 billion ($5.60/share), an increase from 2023’s performance of $2.21 billion ($4.26/share). For the quarter, earnings were $664 million ($1.25/share), compared to last year’s fourth quarter of $336 million ($0.64/share).

The company’s share price closed at $100.99 on Feb. 13, off $1.36 from its previous close.