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February 20, 2026

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Southern Forecasts Continued Large Loads Growth

Southern Co. is “extraordinarily positioned to capture and serve growth” during “a watershed moment for the energy industry and our nation,” CEO Chris Womack said during the company’s fourth-quarter earnings call Feb. 19.

Southern reported net income of $416 million ($0.38/share) for the final quarter of 2025, down from $534 million for the same period in 2024, and full-year net income of $4.3 billion ($3.94/share), down from $4.4 billion for 2024.

The drops came despite a rise in operating revenue from $6.3 billion in the fourth quarter of 2024 to $7 billion for the final quarter of 2025, and growth in full-year operating revenue from $26.7 billion to $29.6 billion.

Adjusted earnings per share for 2025 came to $4.30, CFO David Poroch said on the call, up from $4.05 in 2024 and once again at “the very top of our … guidance range,” which the company set at $4.20 to $4.30 in last year’s fourth-quarter earnings report. (See Strong Southeast Economy Bolstered Southern Co. Growth in 2024.) Southern set an adjusted EPS goal for 2026 of $4.50 to $4.60.

“I’m convinced that 2025 will stand out as a transformative year for Southern Co., one in which we achieved milestones that will propel the future of our business and customers for generations to come,” Womack said. “Economic development activity at our utilities is robust and provides a tremendous foundation for sustainable growth.”

As in previous years, Womack and Poroch credited the strong economy in Southern’s territories for the company’s performance, with $0.34 of the EPS growth attributed to its state-regulated electric utilities. Weather-adjusted retail electricity sales grew across all customer classes in 2025: 39,000 new residential customers were added over the previous year, resulting in growth of 0.8%; industrial sales rose 1.4%, with primary metals and lumber leading the growth; and commercial sales grew 2.8%, 1.8% of which was driven by data centers.

Southern expects the strong retail electric sales growth to continue through the coming years thanks to data centers and other large loads, Poroch said, with 10 GW of facilities already under construction for 26 companies, including Google, Meta and Microsoft, an increase of 2 GW from projections in the prior quarter. Another 10 GW is either finalizing or in late-stage discussions, and the company has a pipeline of more than 125 prospective projects totaling over 75 GW.

“The framework and methodology under which we approach contracting with large load customers are, we believe, one of the best in the industry, and are uniquely designed to benefit and protect existing customers and investors,” Poroch said. “Our contracts include a robust set of terms and conditions [such as] minimum terms of at least 15 years for data centers, with some going out even further over the term of the contract.”

Poroch also reviewed the company’s capital expenditure plan, which has increased from $63 billion in investments through 2030 planned last year to $81 billion. The main driver of the expansion is new generation facilities announced in 2025, including five combined cycle plants, three combustion turbines, two combined solar and battery plants and 17 battery energy storage system facilities.

“We are clearly in a phase of execution,” Womack said. “The planned large-scale buildout across our electric system in the Southeast over the next several years is tremendous and Southern Company’s experience, expertise and scale support the necessary execution. … We are experiencing incredible growth, and we are making investments in all parts of our business to recognize the value of the extraordinary opportunities in front of us.”

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FERC Eliminates Western ‘Soft’ Price Cap

FERC rescinded the West-wide wholesale electricity price cap mechanism it implemented in response to widespread price manipulation during the Western energy crisis of 2000-2001, saying development of new markets and expanded authority has led to improved monitoring capabilities.

The commission found in a Feb. 19 order that the WECC soft price cap framework “is no longer just and reasonable.” It cited three reasons for eliminating the price cap: the evolution of Western wholesale markets, FERC’s expanded legal authority to monitor market misconduct and filing burdens associated with the price cap (EL10-56).

“Upon consideration of the record developed in response to the 206 Order, we have determined, as discussed below, that the WECC soft price cap is no longer just and reasonable, and we rescind the WECC soft price cap effective as of July 18, 2025,” the commission wrote in the order.

A product of the Western energy crisis of 2000/01, the policy requires sellers to justify the costs behind power prices exceeding the soft cap of $1,000/MWh, or refund any amount earned above the cap.

(While the policy is referred to as the “WECC soft price cap,” WECC is not involved with it or any regional market operations.)

The policy came into question after the D.C. Circuit Court of Appeals ruled in 2024 that FERC must conduct a public interest analysis of the price cap under the Mobile-Sierra doctrine. The case concerned a series of 2022 FERC orders requiring electricity sellers to refund a portion of the high prices they earned during an August 2020 heat wave. (See FERC Proposes to Eliminate Western ‘Soft’ Price Cap and FERC Must Apply ‘Mobile-Sierra’ to Western Soft Cap Refunds.)

Following the court’s decision, FERC proposed eliminating the policy all together and launched a Section 206 proceeding in July 2025.

When initiating the 206 proceeding, FERC recounted the D.C. Circuit’s findings and noted that, while FERC has over time revised the soft offer cap to reflect increases in CAISO’s caps, it has never reassessed whether the framework is necessary to ensure just and reasonable rates in the West as required under the Mobile-Sierra doctrine.

In the Feb. 19 order, FERC reiterated many of its initial findings, saying the policy is no longer justified.

One major reason is the development of new wholesale markets in the West, which provide alternatives to traditional bilateral markets. These newer markets, like CAISO’s Western Energy Imbalance Market and the Extended Day-Ahead Market (EDAM), already include market monitoring tools to address potential abuse, FERC wrote.

“In particular, we note that RTO West and EDAM are scheduled to go live this spring (of 2026) and will meaningfully expand Western market participants’ access to centralized, day-ahead markets as an alternative to existing bilateral trading activities,” the order stated. “While we recognize that Markets+ is not scheduled to go live until next year, and that participation in these new market constructs will expand gradually over time, we nonetheless find that the coming expansion of these market alternatives provides additional support for eliminating the WECC soft price cap at this time.”

‘Important Check’

Another reason to eliminate the cap is FERC’s own ability to tackle misconduct, according to the order.

The Energy Policy Act of 2005 granted the commission “authority to pursue allegations of market manipulation in FERC-jurisdictional wholesale electric markets, which serves as an important check against the types of misconduct that fueled the Western energy crisis and led to the adoption of the currently effective soft price cap,” the order states.

The 2005 act has led to development of new tools, capabilities and enforcement mechanisms, the order notes.

“In total, these various data sources and improved analytical capabilities provide the commission far more comprehensive, timely, and actionable information to identify and address market misconduct than was available to the commission in 2002 when it established the WECC soft price cap,” FERC wrote. “We conclude that these capabilities are also more effective at deterring, identifying and addressing market misconduct than any delayed and indirect oversight via review of individual sellers’ spot market transactions under a Mobile-Sierra framework.”

The Feb. 19 order affirmed the commission’s preliminary finding “that the administrative burdens associated with the soft price cap framework outweigh the negligible benefits associated with retaining the cap merely as a flagging mechanism.”

“We also find that this negligible benefit does not offset the burden imposed on sellers and the commission,” the order states. “We affirm the commission’s preliminary finding in the 206 Order that ‘the filing requirement imposes costs on market participants and the commission and creates uncertainty for individual transactions while those filings are pending review at the commission.”’

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California, 12 Other States Sue Trump Admin. Over Energy Grant Terminations

Thirteen blue states are suing the Trump administration for reversing Biden administration funding commitments worth $7.6 billion for energy and infrastructure projects.

California Attorney General Rob Bonta filed the complaint (26-cv-01417) Feb. 18 in U.S. District Court in the Northern District of California. He was joined by the attorneys general of a dozen other states as plaintiffs.

They name the U.S. Department of Energy, the U.S Office of Management and Budget, DOE Secretary Chris Wright and OMB Director Russell Vought as defendants.

The plaintiffs ask the court to declare the funding cuts unconstitutional on the grounds the president cannot reverse funding appropriated by Congress or target opponents. They seek reversal of the grant terminations and abandonments, and they want an injunction against similar cuts in the future.

The grant terminations were announced Oct. 2 as President Donald Trump and his Republican allies in Congress were locked in a budget standoff with Democrats. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

Some of the cuts would spill over into Republican-led states or congressional districts, but all were centered in 16 “blue” states won by then-Vice President Kamala Harris in her losing run against President Donald Trump in 2024.

The 32 U.S. senators representing those 16 states all were Democrats and all voted against a bill that would have averted the autumn 2025 federal government shutdown.

At the time, DOE framed the cuts as part of a process by the new Trump administration to winnow out wasteful spending. But as it defended a subsequent legal challenge led by the city of St. Paul, Minn., against a handful of the grant terminations, the Trump administration acknowledged that the October grant cancellations were based primarily on their locations in blue states, and asserted that was legitimate justification. Further, the administration acknowledged that the grants terminated in blue states were comparable to red-state grants it did not terminate.

The judge in the St. Paul case (25-cv-03899) ruled Jan. 12 that this approach had violated the plaintiffs’ guarantee to equal protection of laws under the Fifth Amendment to the U.S. Constitution. (See Judge Rules Blue-state Energy Grant Terminations Unlawful.)

But that ruling pertains only to seven grants at the center of that case.

RTO Insider asked DOE at the time whether it considered the ruling applicable to the other 300-plus grants it terminated in October 2025.

DOE did not answer the question, but its Feb. 13 filing in the St. Paul case sheds some light: It told the judge the plaintiffs’ request for a permanent injunction was unwarranted but if any injunctive relief were granted it should pertain only to the seven grants in question.

California filed its lawsuit three business days later.

It is joined by the attorneys general of Colorado, Connecticut, Illinois, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, Vermont, Washington and Wisconsin.

The California Governor’s Office of Business and Economic Development (GO-Biz) also is a plaintiff, on behalf of ARCHES H2 LLC.

ARCHES — Alliance for Renewable Clean Hydrogen Energy Systems — is one of seven regional hydrogen hubs created amid a Biden-era push to develop hydrogen as an energy sector; it was focused on building a green hydrogen ecosystem in California.

ARCHES H2 LLC was the biggest loser in the October 2025 tranche of DOE grant terminations, at $1.2 billion.

ARCHES CEO Angelina Galiteva decried the termination when it went public Oct. 1, but said the initiative would continue to advance in collaboration with state leaders and the private sector. However, a month later, ARCHES said it would pause hydrogen hub activities due to the federal funding cuts and hand administrative oversight to GO-Biz and the University of California.

It has laid off its entire full-time staff, according to California’s lawsuit.

GO-Biz demanded on Jan. 15 that ARCHES file a lawsuit seeking to remedy harms from the grant termination; the ARCHES board of directors replied that pursuing litigation would be in its best interest but it lacked the financial resources to do so because of the DOE grant termination.

All told, the October grant terminations totaled nearly $2 billion in California.

California’s Feb. 18 lawsuit lists much smaller sums for the 12 other states affected by the DOE grant terminations.

Trump and Calif. Gov. Gavin Newsom (D) snipe at each other often and hard, and the lawsuit hints at that relationship.

“In early October, as the administration sought a cudgel to wield in budget negotiations, defendants deployed this unlawful policy as an opportunistic way to hurt the administration’s political enemies and those associated with them,” the introduction to the complaint reads.

The specific complaints in the California lawsuit are similar to those in the St. Paul case: violation of the separation of powers between Congress and the president, violations of the Administrative Procedures Act, ultra vires action by federal officials, violation of the First Amendment by retaliating against free speech and violation of the Fifth Amendment right to equal protection.

The plaintiffs ask that the DOE memo on which the grant terminations were based be declared unlawful; seek a permanent ban on any future action based on the memo; and ask for reversal of the grant terminations.

They also want a declaratory judgment that the defendants may not terminate or abandon awards based on policy preferences or geographical location.

And they ask for an injunction reinstating the cooperative agreement DOE terminated with ARCHES as it terminated the hub’s grant.

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FERC Denies Rehearing Requests on Constellation-Calpine Merger

FERC upheld its approval of Constellation Energy’s purchase of Calpine while also addressing arguments that consumer and environmental groups made in requesting rehearing in an order issued Feb. 19 (EC25-43).

In a joint request, Public Citizen, PennFuture, Clean Air Council and the Citizens Utility Board argued FERC should have gone beyond its standard review practices to review the merger, especially its effects on PJM. The Pennsylvania Office of Consumer Advocate also filed a request, arguing FERC should have reviewed the merger’s impact on the state’s retail power market.

The commission disagreed with the groups’ claim that it had failed to examine any risks to the market, such as withholding, beyond its normal screens. FERC does so automatically if the combined firms’ generation fails market power screens.

“The commission does not automatically examine whether a proposed transaction will enhance an applicant’s ability and incentive to withhold output when a proposed transaction passes the horizontal competitive analysis screen required by our regulations,” FERC said.

The groups argued that a 2012 order on FERC’s merger policies indicated the commission would go beyond market power screens, but FERC said the context of that was in the event of a screen failure. “Thus, a single sentence in the 2012 order reaffirming commission policy, which affirmed existing commission policy, did not announce a new practice that goes beyond what is set forth in decades of precedent, including Order No. 642, the supplemental policy statement and orders issued subsequent to the 2012 order reaffirming commission policy.”

But FERC said it agreed with the groups that a merger passing a screen does not stymie the commission’s further review, prevent intervenors from raising concerns or relieve merging parties from showing the deal is consistent with the public interest.

“We note that, despite the proposed transaction, with the mitigation plan, not failing the competitive analysis screen, the commission in the merger order still addressed [the groups’] arguments regarding applicants’ alleged incentive and ability to withhold supply in PJM markets,” FERC said.

It noted that in its original order, it had approved an agreement between Constellation and PJM’s Independent Market Monitor to cap the company’s capacity market bids through the 2035/36 delivery year. “The price cap would apply to both the ‘ability’ and ‘incentive’ units owned by Constellation, which should prevent Constellation from engaging in a profitable withholding strategy,” it said.

The groups were also worried that the deal would make it more profitable for Constellation to withdraw its nuclear plants from PJM to serve data centers in co-location arrangements because the absorption of Calpine’s fleet would leave it with more generation that would benefit from resulting higher power prices. But FERC did not agree with those arguments, saying the group failed to provide enough evidence.

Constellation is considering such deals, but nothing in the case showed the merger would make them more likely to happen, FERC said.

“Concerns about data center transactions, the rules governing them and their potential impact on wholesale markets like PJM are outside the scope of this proceeding,” FERC said.

The Pennsylvania Consumer Advocate’s rehearing request was focused on the state’s default service auctions, in which utilities procure supply for customers who do not shop with competitive suppliers.

The merger proceeding never identified Pennsylvania as a submarket, so FERC said it was appropriate to not review the deal’s impact on default service there. Intervenors can suggest new submarkets, but to be successful, they must show such submarkets are frequently cut off because of transmission constraints, which the state advocate did not.

FERC also noted that it would have reviewed the merger’s impact on Pennsylvania’s retail market had the state’s Public Utility Commission requested it to do so.

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Edison Earnings Rise Despite Eaton Fire Uncertainties

Edison International earnings rose nearly 32% in 2025 despite the uncertainty swirling around its Southern California Edison subsidiary, which has been implicated in sparking the January 2025 Eaton Fire that killed 19 people and destroyed more than 9,000 structures in the Los Angeles area.

Edison’s 2025 earnings came in at $2.5 billion ($6.55/share), compared with $1.9 billion ($4.93/share) in 2024.

Q4 core earnings were $717 million ($1.86/share), up from $405 million ($1.05/share) in the same period a year earlier.

Earnings increased primarily due to cost recoveries associated with the Woolsey Fire settlement agreement and approval of the IOU’s 2025 general rate case, Edison said in a news release.

But the company is currently unable to reasonably estimate a range of potential losses stemming from the Eaton Fire, CEO Pedro Pizarro said during a Feb. 18 earnings call.

An investigation into the cause of the fire is ongoing. An idle, de-energized SCE transmission facility has been identified as the likely source of the ignition of the fire. (See SCE Probes Link Between Equipment and Eaton Fire.)

“SCE is not aware of evidence pointing to another possible source of ignition,” Pizarro said. “Absent additional evidence, SCE believes that it is likely that its equipment could have been associated with the ignition.”

“We continue to believe SCE will be able to make a good-faith showing that its actions were those of a reasonable utility operator, so that gives us a lot of comfort,” Pizarro said.

“Can you confirm for me whether the out-of-service transmission tower in Eaton was grounded or not?” said Aidan Kelly, research analyst with JPMorganChase, on the call.

“We have shared before that transmission line — the idle line — was grounded at both ends,” Pizarro said. “[But] we have photographic evidence that at the far end of the line that showed some anomalies, some potential issues, with that grounding.”

SCE started a wildfire recovery compensation program for victims of the fire, with more than 2,300 claims submitted. About 18,000 properties are eligible for the program, Pizarro said.

“You might have multiple claimants per property — for example, if you have multiple tenant property. So we could see a few tens of thousands of claims ultimately if everyone was to participate,” he said.

Nick Campanella, senior research analyst with Barclays, asked: “As you are continuing to get more visibility on the total liability [of the Eaton Fire], when you do you think you’ll have the low end of losses for the total event and what is the complicating factor at this point?”

“In terms of when we’d be able to estimate, we really don’t have an estimate because a lot depends on the pace of this” claims and investigation process, Pizarro said.

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PJM’s Reliability Backstop Auction: Fixing Half the Problem

By Tom Rutigliano

PJM’s resource adequacy woes have taken on an air of inevitability. PJM warned of impending shortfalls three years ago, and since then we’ve all been watching it like a slow-motion train crash. Consumer demand for power feels unstoppable, but supply is frozen, unable to respond. Interconnection queue reform, record high prices and special purpose fast tracks have all so far been unable to deliver the new capacity the region needs.

Now PJM, with prompting from 13 governors, is trying another solution: the “Reliability Backstop Auction.” While details still are being negotiated, this boils down to throwing money at new power plants. But it’s not clear that money is the problem right now — after all, tech companies have famously deep pockets.  (See White House and PJM Governors Call for Backstop Capacity Auction.)

Tom Rutigliano

The backstop auction itself isn’t a bad idea. It recognizes the commonsense fact that financing new power plants is different than covering the operating costs of existing ones. If done right, this offers new supply attractive terms without raising prices for everyone else.

That fixes the worst-of-both-worlds problem we have now: Rates are going up by billions, but that money is going to windfalls for existing power plants instead of investment in new ones. If PJM can design a backstop auction that doesn’t put costs or risk on the public and is open to all technologies on fair terms, they might have a winning formula on their hands.

But even the best auction won’t work unless new power plants can get built, which is still a huge problem. If the many other problems blocking new supply aren’t solved, this new auction could fail. (See Government-proposed ‘Backstop’ Auction to Test PJM Stakeholder Process.)

Disappointing Queue Reform

For many years PJM’s interconnection queue was the problem. But following reforms, PJM’s queue began to approve projects in 2025. What should have been great news turned into disappointment as developers discovered their projects will have to wait four years or more for transmission upgrades.

PJM’s next batch of projects isn’t doing much better — almost a third of the capacity in that group dropped out when they got their first estimate of interconnection costs. The hand-picked “shovel ready” projects in the RRI fast track dropped out at about the same rate.

Behind the queue is a deeper problem: The transmission system isn’t ready to accept tens of gigawatts of new generation. If PJM doesn’t deal with this, there won’t be enough new supply for the Reliability Backstop Auction. This isn’t a problem PJM can build its way out of. At best, the transmission we need can’t be completed for many years, and transmission projects often run into serious obstacles that delay or cancel them.

Instead, PJM needs to embrace solutions that work around the limits of the electrical grid we have. This is a major paradigm shift for Valley Forge; for as long as PJM has been around, it has insisted on “full deliverability,” which means that every generator in PJM must be able to supply power to the entire region, and not be bottled up in a small area.

This made sense in an era of diffuse demand growth, but what we’re seeing now is generators built to supply individual data centers in specific locations. If PJM recognizes this, and the generators and data centers accept the risk that comes with not being fully integrated into the larger grid, we could unlock gigawatts of faster supply.

Expand the Co-location Model

This already has begun. FERC recently approved an SPP proposal along similar lines, and, spurred by a recent FERC order, PJM has come up with some innovative solutions for generators located next to data centers. For the most part, these are variations on the idea of partial and/or as-available service rather than “full service all the time.”

This is a great start. PJM now needs to expand this model and open opportunities for new supply sited where the transmission system can deliver its power to particular customers. Imagine a storage development a few counties away from a data center that charges when there’s spare grid capacity and discharges to offset any overloads the data center would place on the interstate grid. If carefully sited, an arrangement like that brings the storage online years earlier by avoiding transmission upgrades.

Old approaches are just not up to the task of powering the data center boom. We don’t have and can’t build an electrical grid that ships power from distant fossil plants. Now is the time for bold innovation around carefully sited projects, especially energy storage, that can quickly work with and around the limits of the current grid. Without changes in how PJM interconnects new supply, no auction will be successful, no matter how well designed.

Tom Rutigliano is senior advocate for climate and energy at the Natural Resources Defense Council.

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CPUC President Alice Reynolds Out, Joins CAISO Board

California Public Utilities Commission President Alice Reynolds is leaving the CPUC and joining CAISO’s Board of Governors after more than four years at the helm of the state’s utility regulator.

Gov. Gavin Newsom (D) appointed CPUC Commissioner John Reynolds (no relation to Alice Reynolds) to the top spot at the agency.

John Reynolds will “build on” Newsom’s effort to lower utility bills, ensure that wildfire safety spending delivers real value, and hold utilities accountable for safe, reliable and affordable service, the governor’s office said in a Feb. 18 news release.

Newsom appointed Alice Reynolds as CPUC president in 2021 following on her role as senior adviser on energy for his office from 2019 to 2021. She previously was senior adviser for climate, energy and the environment for the office of Gov. Jerry Brown (D) from 2017 to 2019.

“It has been the honor of a lifetime to serve the people of California as the president of the Public Utilities Commission,” Alice Reynolds said in the release. “I look forward to continuing to carry out the vision of a safe, clean, reliable, affordable electricity system that benefits all Californians, and I leave knowing that the commission is in good hands.”

Alice Reynolds plans to leave the CPUC in late February to join the CAISO board.

In 2024, she appeared before state lawmakers to pitch a set of proposed CAISO governance changes being developed by the West-Wide Governance Pathways Initiative. (See California Energy Officials Pitch Pathways Plan to State Senators.)

Electricity markets in the West are “very fragmented,” she said to the lawmakers at the time. “So, this effort is really thinking about the benefits of a larger market, meaning, think about a market with a footprint that is larger than any one weather event.”

Energy Affordability Highlighted Again

Front and center at the CPUC is energy affordability.

John Reynolds will lead the effort to align infrastructure investments with affordability goals, and ensure utilities deliver results for ratepayers — without slowing California’s clean energy progress, Newsom’s office said in the release.

His appointment “underscores a renewed focus on cutting costs and improving performance as extreme heat, wildfire risk, and upgrades to the electric grid drive new demands on the system,” Newsom’s office said.

“I look forward to continuing the state’s work to drive towards more affordable utility services while supporting safe and reliable infrastructure that delivers on our ambitious climate agenda,” John Reynolds said.

Christine Harada will join the CPUC as a commissioner. Harada is undersecretary of the California Government Operations Agency and previously was senior adviser at the U.S. Office of Management and Budget from 2023 to 2025.

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FERC Approves Transmission Deals Between ComEd and Data Centers

FERC approved four transmission security agreements between Exelon’s Commonwealth Edison and new data center customers in Illinois, laying out conditions for their transmission service.

All four orders, issued Feb. 17, included two identical concurrences: one from Commissioner Judy Chang, and a joint concurrence from FERC Chair Laura Swett and Commissioner David LaCerte apparently in response to Chang’s.

The customers include Karis Critical, for a data center in DeKalb (ER26-853); Aligned Data Centers, for a facility in Coal City (ER26-838); Monarch Rock Air, for a facility in Rockford (ER26-839); and Red Energy Partners, for a data center in DeKalb (ER26-841).

The deals all cover the terms of ComEd’s provision of retail service to the data centers; they had to be submitted to FERC for approval because they include the construction and operation of transmission facilities. They include provisions seeking to ensure the data centers pay for those investments even if their development is delayed; they use less power than planned; or they shut down earlier than expected.

To submit a commentary on this topic, email forum@rtoinsider.com.

FERC approved the proposal under the Mobile-Sierra public interest standard of review, which holds that the terms of arms-length contract negotiations are presumed just and reasonable, absent a showing they are contrary to the public interest.

The entire commission agreed that the deals offer protections for other customers that would not otherwise exist and that the Illinois Commerce Commission can use its authority to place additional conditions protecting other retail customers.

But in her concurrence, Chang noted that using Mobile-Sierra means FERC has not independently assessed the deals against its just-and-reasonable standard. She referenced her concurrence on a similar deal FERC approved for another Exelon subsidiary, PECO Energy, in November. (See FERC Approves PECO-Amazon Transmission Agreement for Pa. Data Center.)

“I write separately to reinforce my concern that reliance on bilaterally negotiated agreements, particularly ones shielded from meaningful commission review by the Mobile-Sierra presumption, may not be sufficient to ensure that customers are protected against unjust cost shifts from new large loads,” Chang said.

The commitments are better than not having an agreement, Chang acknowledged, and they reflect a meaningful revenue contribution to transmission costs that other customers would otherwise have to pay.

“However, there is a need to protect other customers from potential unjustified cost shifts, and neither the terms of the agreement nor ComEd demonstrate how these commitments achieve that higher and more essential standard,” Chang said. “So, while the commission properly accepts the agreement under the Mobile-Sierra framework, that acceptance does not necessarily protect other customers.”

When utilities must expand their transmission systems to offer new service, it can lead to an increase in rolled-in embedded cost rates. To protect wholesale customers, FERC allows transmission providers to charge the higher of the rolled-in embedded cost of the expanded system, or the incremental costs of the expansion itself, but not the sum of the two.

“Today’s order conforms to this line of precedent by acknowledging ComEd’s intention to seek rolled-in rate treatment to recover the costs of serving these new customers,” Swett and LaCerte wrote. “The commission will always reject a rate that seriously harms the consuming public.”

In the PECO concurrence, Chang suggested that FERC could apply “the higher” policy to large loads interconnecting directly to the grid. But that would first require the incremental costs of the upgrades to be quantified, “an exercise that notably has not been conducted and reflected in” the four ComEd agreements, she wrote.

“In fact, the agreement does not identify any specific upgrades needed to interconnect the data center,” Chang said. “Instead, it contemplates that, if the large load that materializes through this agreement triggers transmission upgrades on ComEd’s system, the costs of those system upgrades would be added to ComEd’s transmission revenue requirements and thereby rolled into transmission rates that all customers pay.”

That doesn’t necessarily mean rates for other customers will rise, she noted, but they certainly could.

“The commission and our state counterparts must not let the commission’s acceptance of the agreement and others like it dissuade us from taking additional action to protect customers where we think it is necessary,” Chang said. “Instead, absent some demonstration that the agreement and similar arrangements provide the necessary level of consumer protection, they should be treated simply as one piece of a broader package of federal and state measures to protect customers, rather than the primary or exclusive means to do so.”

For FERC’s part, Chang suggested assessing how to develop customer protection frameworks that can complement and supplement ongoing efforts at the state level.

Swett and LaCerte noted that Mobile-Sierra is just a presumption that presents a higher legal bar to overturning contracts, but that can be done if one “seriously harms the public interest.”

“The Mobile-Sierra presumption is not a straw man behind which the commission hides to evade its statutory duty of ensuring that the American consumer pays just and reasonable rates,” they wrote.

If the circumstances demonstrate serious harm to the public interest, especially other ratepayers, then FERC has a statutory responsibility to act, which could include overcoming the Mobile-Sierra presumptions.

“As we head down the road where it appears that agreements similar to those approved today may become more common, we also would like to clarify that the commission’s existing transmission policy ‘endorses transmission pricing flexibility,’ not a linear analysis,” they said.

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Members Seek Clarity on NERC Standard Committee’s Future

NERC’s Standards Committee members had many questions about organizational changes that will likely lead to their committee’s disbanding, with leaders promising answers as soon as they are available.

The SC gathered for its monthly conference call Feb. 18, a week after NERC’s quarterly Board of Trustees meeting in Savannah, Ga., where trustees agreed to adopt the final recommendations of the Modernization of Standards Processes and Procedures Task Force (MSPPTF). (See NERC Board Accepts MSPPTF Recommendations.)

Under the task force’s recommendations, the Reliability and Security Technical Committee would conduct a biannual review of standard initiation requests to determine whether a new standard was needed. Standard proposals would be handed to a new subcommittee of the Reliability Issues Steering Committee, which would consult with industry to determine a plan for development.

A new pool of on-staff subject matter experts would work with NERC staff to develop a draft standard, which would be posted for stakeholder comment and then revised by a project team. Industry stakeholders then would vote on the standard in a confirmation ballot.

Chair Todd Bennett of Associated Electric Cooperative, who was at the board meeting, discussed with SC members what he knew of NERC’s future steps, but acknowledged that beyond the goal of having the new process in place by the end of 2027, few details of the implementation plan had been worked out. He confirmed this goal included “sunsetting” the SC and revising the charters of the RSTC and RISC, and said the two processes likely would run side-by-side while NERC staff worked out the kinks.

Jennie Wike of Tacoma Public Utilities asked when the SME pool would be formed and if there would be any impacts to existing standard drafting teams. NERC Manager of Standards Development Alison Oswald said there were “quite a few steps to put in place before that can happen.”

Vicki O’Leary of Eversource observed that half the SC members’ terms will expire at the end of 2026, and asked whether NERC would hold an election to fill those vacancies.

Oswald said NERC “had not specifically thought about” that question but said she “could foresee that we would continue on the normal path as is.”

Bennett added that his preference depended on the timeline for the SC’s disbandment. If the committee is dissolved in early 2027, he said, he would prefer “just to keep the same committee … and engaged members that we have.” But if it will last longer, he said it might be better to hold formal elections.

Standards Actions

Along with the MSPPTF updates, the committee had a full slate of standards actions to consider.

A proposal to supplement the SDT for Project 2023-09 (Risk management for third-party cloud services) led the agenda. Manager of Standards Development Jordan Mallory explained that the project — which NERC considers high priority “due to increasing threats to the electric system” — recently lost three of the original 13 SDT members.

Although NERC typically considers 10 members to be sufficient for an SDT, Mallory said because the project is expected to modify a large number of Critical Infrastructure Protection standards, the team believes it will need a larger-than-usual number of members.

NERC staff recommended that the SC approve the solicitation of nominees from industry to bring the team back to full strength. Members approved the proposal unanimously.

Another proposal to replace three departing SDT members — this time for Project 2022-05 (Modifications to CIP-008 reporting threshold) — also gained approval from SC members, though not without some discussion. In this case, NERC already had processed 10 nominations from industry and chosen three candidates to recommend to the committee for approval.

Keith Jonassen of ISO-NE suggested approving one of the remaining nominees as well, arguing that the individual, who was not identified during the meeting would add needed balance to the team by representing ISOs and RTOs. Mallory replied that NERC felt the three chosen “were the top contenders,” adding that in any case, the person in question had expressed a lack of interest in serving on the team. Jonassen’s motion to add the extra nominee was rejected and the original slate passed.

Members also approved proposals to draft Canadian-specific revisions to NERC’s cold weather standard EOP-012-3 (Extreme cold weather preparedness and operations), to modify PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources) and to update requirements for supply chain risk management.

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Report Touts U.S. Sustainable Energy Despite Volatile Policies

The annual status report from the Business Council for Sustainable Energy (BCSE) finds sustainable energy met rising U.S. power demands in 2025 despite the far-reaching policy shifts roiling the sector.

The report also flags this policy uncertainty — along with the slow pace of permitting and interconnection — as a potential barrier to meeting the sharply higher power demand expected in coming years.

The “2026 Sustainable Energy in America Factbook,” prepared by BloombergNEF and published Feb. 18 by BCSE, is the 14th of its kind. It comes at a tumultuous time for the U.S. electricity sector: The Trump administration is executing a sharp shift in strategy while power demand has begun significant growth after more than a decade of minimal increases.

BCSE and BloombergNEF frame this as a time to recommit to sustainable energy.

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“These fast-moving dynamics provide an opportunity to accelerate investment into a broad portfolio of sustainable energy technologies,” BCSE President Lisa Jacobson said in a news release. “This diverse set of resources will allow the U.S. economy to prosper, boost national security and economic competitiveness, and deliver reliable and affordable energy for all Americans.”

Ethan Zindler, BloombergNEF’s head of country and policy research, said: “As demand from energy-hungry data centers continues to grow, we’ll likely continue to see upward pressure on power prices. The need to expand supply from sustainable energy sources has never been clearer.”

This emphasis on sustainable energy would be at direct odds with Trump administration policies under many definitions of “sustainable.” But BCSE defines natural gas as sustainable, aligning it with one of President Donald Trump’s priorities: boosting the U.S. natural gas sector. The industry trade group American Gas Association is a BCSE member and helped sponsor the factbook, as did other notable members of the natural gas sector.

The factbook is the latest in a sea of analyses, opinions and invectives that have attributed demand growth to data centers. The authors stop short of blaming data centers for rising electricity prices, a primary line of criticism.

Instead, they acknowledge that data centers — particularly for AI applications — have become central to power planning and are poised to be the dominant force behind rising power demand.

Their power consumption was 18% higher in 2025 than in 2024 and has risen more than 150% over the past five years, the authors write. Data center load reached 23 GW installed and 48 GW under construction or committed to construction with land, power and permits secured. Early-stage announcements — a less certain prospect — combined for 165 GW of potential additional load.

The evolution of the U.S. power generation mix is tracked over 13 years. | BloombergNEF

Meanwhile, a record 1.6 million electric vehicles were sold in the U.S. in 2025 as consumers rushed to qualify for federal tax credits about to expire. This also drove grid investment.

“The need for electricity infrastructure is growing rapidly with rising EV sales and the AI data center buildout,” said Trina White, BloombergNEF’s senior associate for North American energy transition. “This is creating some supply chain bottlenecks while raising the costs for key grid equipment.”

But the same federal policy changes and regulatory obstacles influencing the power sector also crimp the ability or willingness of some private-sector businesses to respond, BCSE said.

Eighty-seven new tariff and trade policies were announced in 2025, the authors said, eroding the stability and confidence needed to attract investment in the clean-tech sector.

“Businesses are ready to deploy solutions to meet energy demand, but they need certainty that policies and permits will not change once commitments to long-term energy sector investments have been made,” Jacobson said.

Key Takeaways

Some details about the U.S. energy landscape in 2025, as excerpted from the new BCSE factbook:

    • A total of 54 GW of new utility-scale generation and storage capacity was commissioned in 2025, the most in more than two decades; 90% of it was wind, solar and storage.
    • New gas generation more than doubled from record-low 2024 additions but still totaled only 5 GW.
    • New corporate zero-carbon energy procurements totaled a record 29.5 GW.
    • The One Big Beautiful Bill Act accelerated the phaseout of key tax credits for clean energy development and cut federal subsidies for clean-tech manufacturing.
    • Permitting setbacks and outright interference were dealt to solar, onshore wind and particularly offshore wind.
    • As it was hampering other forms of clean energy, the Trump administration boosted support for nuclear generation, geothermal and hydropower technologies.
    • Overall energy transition investment grew 3.5% to $378 billion.
    • Greenhouse gas emissions from the power sector rose 3.6% as coal-fired generation increased.
    • Overall energy costs for consumers, a metric that is taking a prominent role in policymaking and political rhetoric, actually fell 0.2 percentage points to 3.66% of personal expenditures, due to lower gasoline prices; however, natural gas and electricity rose from 1.6% to 1.62%, a reversal from recent years.
    • Energy consumed to produce electricity rose 2% to 33.4 quadrillion BTU but still was well below the peak of 38.5 quadrillion in 2007, reflecting improvements in energy efficiency and productivity.
    • Interconnection requests to the seven ISOs and RTOs reached a combined 377 GW, the largest component being storage and the largest number of requests being submitted to ERCOT, followed by MISO and PJM.

The factbook was commissioned by BCSE and supported by contributions from a diverse group of sponsors including Amazon, American Clean Power, JPMorganChase, Schneider Electric, the Polyisocyanurate Insulation Manufacturers Association and Sempra.