Search
December 7, 2025

Posted on

FPL Leading Southeast in Solar Buildout, SACE Report Finds

Solar power generation will expand strongly but not uniformly in the Southeast through the rest of the decade, the Southern Alliance for Clean Energy said in its annual solar report.

The seven-state region ended 2024 with 27.84 GW of installed capacity in areas outside PJM and MISO territory and is expected to reach approximately 54 GW in 2030, SACE reported.

“We are very bullish on solar power; have been for a long time,” SACE Executive Director Stephen Smith said during an Oct. 29 webinar, “and as you’ll see in this report, we’re beginning to see that some states are really starting to make big bets in solar and break away and make it a workhorse technology that we think is necessary.”

“Solar in the Southeast” shows Florida leading the region’s buildout, with nearly 14 GW installed in 2024 and 29.5 GW expected by 2030. It says the steady growth in the Carolinas and Georgia is driven by the large projects of just a few major utilities. And it says Tennessee, Alabama and Mississippi bring up the rear, at least in part from the Tennessee Valley Authority’s challenging requirements for solar additions.

“There’s actually several utility-scale projects that are coming online from TVA in the next couple of years,” Senior Energy Policy Manager Heather Pohnan said. “However, the historical lack of ambition from the utilities that operate in these states really makes it difficult to keep pace with the rest of the region.”

The bulk of installed solar capacity is in utility-scale projects, and three utilities accounted for much of the 27.84 GW: FPL (8.38 GW), Duke Energy (8.22 GW) and Southern Co. (4.04 GW).

FPL also has the biggest ambitions among utilities studied, as judged by their integrated resource plans: 8.5 GW of new solar by 2030, or 64% of its planned capacity additions. The next-largest planned solar additions are TVA’s 2.83 GW, which would be 32% of its total. Least ambitious are Alabama Power and Santee Cooper, which plan solar to be just 9 and 7%, respectively.

Florida dominates and is expected to continue dominating installed solar capacity in the Southeast United States. | Southern Alliance for Clean Energy

The SACE report adds a caveat about TVA’s stated intentions: President Donald Trump has purged its board of directors and nominated new members who could change the solar plans. (See Trump’s TVA Nominees Reject Privatization.) Those nominees are before the full Senate after being advanced by the Environment and Public Works Committee on Oct. 29.

Speakers in the webinar praised FPL for its strong solar ambitions and track record in meeting them. SACE Clean Energy and Equity Director Stacey Washington pointed to FPL’s goal of 17,500 MW.

“This is a large goal, but FPL has demonstrated that it is capable of adding a lot of solar to the grid at a steady pace. With 2,250 MW coming online in 2024, FPL has established a process to source and build utility-scale solar at a fast pace.”

An audience member at the webinar questioned why praise was being showered on FPL.

“Let’s just be really clear,” Smith said: “Florida Power & Light has laid down the most ambitious solar deployment program of any utility in the Southeast, by far, and … probably one of the most ambitious programs of any utility across the United States.

“It needs to be recognized,” he said, “and it needs to be called out, and we need to hold other utilities accountable, because this utility is actually moving away from fossil gas. They’re still highly dependent on it, but you’re actually seeing the reductions. You’re seeing the deployment.

“What we don’t have is — in Georgia and in the Carolinas, and definitely at TVA — a real commitment to this technology.”

There are practical impediments to solar deployment, such as transmission constraints and disappearing federal subsidies.

“Transmission has become a roadblock to solar; in many places, it’s quite significant. In other places, it’s just a matter of time, it seems,” said SACE Research Director Maggie Shober.

Washington recited the list of 2025 federal program cuts and tax credit phaseouts and said distributed solar would feel the impact before utility-scale solar.

Distributed solar already has a difficult path in the Southeast, Shober said, even with FPL. There is a bias toward utility-scale, she said, and there is not a good net-metering program that can make small-scale solar more attractive.

“I think the utility business model in our region is set up that utilities are inherently against rooftop solar and customer-based solar,” she said, “not because they don’t like it, but just because it’s not in their financial interest to encourage it, and so they are setting up as many roadblocks as they can.”

Smith said electricity costs are rising to the point of an affordability crisis, so the industry should focus on the capacity it can add in the least time at the lowest cost: solar and storage.

He also put in a plug for utilities and regulators to embrace energy-efficiency programs. “The greenest electron [and] most cost-effective electron is the one that you never use.”

SACE drew data for the report from the utilities’ integrated resource plans and U.S. Energy Information Administration reports on currently operating utility-scale and distributed solar resources.

Posted on

ISO-NE Talks Order 2023 Updates at NEPOOL Transmission Committee

Proposed tariff changes, intended to update how ISO-NE assigns capacity rights to resources not subject to its interconnection processes, were introduced at the NEPOOL Transmission Committee meeting Oct. 28.

Alex Rost, director of transmission services, said ISO-NE proposes to “formalize the concept of equivalent capacity network resource capability (CNRC) and address how equivalent CNRC is established, managed and reduced.”

CNRC values define the capacity interconnection rights of resources that are subject to ISO-NE’s interconnection procedures. Before FERC Order 2023, resources established CNRC by obtaining capacity supply obligations (CSOs). In the new interconnection framework, those resources gain CIRs via the cluster study processes.

The Order 2023 changes have created a need “to clarify how equivalent CNRC is assigned, managed and reduced” under the new interconnection framework, Rost said.

Resources not subject to the RTO’s interconnection procedures that could receive equivalent CNRC values include those connected to the distribution system, aggregations of distributed resources and active demand resources, he noted.

“For consistency with resources subject to the ISO interconnection procedures, the process to establish equivalent CNRC … should be supported by clear and trackable commitments related to a resource achieving commercial operation,” Rost said.

To establish equivalent CNRC, resources would need to prove their deliverability in an “all-or-nothing deliverability analysis screen,” which would be coordinated with the similar deliverability analyses performed in ISO-NE interconnection cluster studies.

Deliverability analyses for resources seeking equivalent CNRC would be performed “right after the conclusion of a cluster study” and would be adjusted “as needed” following cluster restudies, Rost said.

After proving deliverability, resources could achieve equivalent CNRC by obtaining a CSO or by “locking-in” equivalent CNRC prior to participating in a capacity auction, Rost said.

The rules for the CSO pathway to achieving equivalent CNRC would be “very similar to the pre-Order No. 2023 approach used to establish CNRC,” Rost noted. CNRC values would “equal the highest amount of CSO obtained in a capacity market activity,” with seasonal adjustments to account for varying winter or summer capabilities.

To achieve equivalent CNRC prior to auction participation, developers would need a commercial operations date within the following two years and would need to demonstrate adequate financial commitment to the resource.

For resources following this path, ISO-NE would rely on winter and summer qualified capacity estimates “consistent with capacity market qualification.”

“‘Locked-in’ equivalent CNRC must be assigned to a specific project and will be withdrawn if the specific project has its interconnection agreement (or equivalent) terminated or fails to achieve commercial operation within two years from the date that equivalent CNRC is requested,” Rost said.

ISO-NE plans to maintain its existing methods for reducing or retiring equivalent CNRC; resources could request deactivation or would be automatically retired if they are inactive for three years.

Rost said the RTO plans to implement the changes prior to the 2026 interim Reconfiguration Auction qualification process. ISO-NE will discuss the proposal with stakeholders in the coming months and is targeting a TC vote in January.

Posted on

PJM Asks FERC to Deny Demand Response Metering Data Complaint

PJM told FERC that a complaint seeking to use statistics to estimate customers’ demand response when accessing meter data is not practical (EL26-4).

Curtailment service providers Voltus and Mission:data filed the complaint against PJM, but the issues are all tied to state regulators — or relevant electric retail regulatory authorities (RERRAs) — who have the authority over end-use customers’ smart meters and the data they use, the RTO told FERC on Oct. 28.

“There is considerable history behind why RERRAs put limitations on the release of customer data without customer consent, and those restrictions are embedded in many cases in state law or state regulations as a consumer protection measure given widespread evidence of the misuse of customer data,” PJM said. “Complainants ask this commission to circumvent all of those state laws and regulations by instead amending PJM’s tariff to decrease the accuracy associated with the accounting of and compensation for residential customer demand response data.”

Fixing the state-level issue through a degradation of the information PJM gets on DR shows that FERC is not the proper venue to deal with the issue, the RTO argued, especially as Voltus and Mission:data have not exhausted the options available to them in state regulatory proceedings.

“The complainants effectively ask this commission to circumvent the states’ jurisdiction over retail data access issues by requiring PJM to allow for less accurate data for interval metered residential demand response customers without even showing any attempt to work with the RERRAs on this issue,” the RTO told FERC.

FERC examined the issue in 2023, when it rejected a similar complaint from CPower over lack of evidence that customer data were not widely available. Voltus and Mission:data offered some specific information on how difficult it was to get data from mass market customers at specific utilities. (See Voltus, Mission:data Seek Changes to PJM Data Requirements for DR.) PJM rules require actual meter data in all cases except when a residential customer does not have an installed interval meter.

“For residential customers that do not already have interval meters installed to measure their actual use as it changes by interval, the CSP may rely on a statistical estimate derived from sampling the usage of customers that do have interval metering,” PJM said. “This reduces the barriers to entry for such residential customers to participate as demand response in PJM’s markets, as it allows CSPs to facilitate their participation while only incurring the cost of installing interval meters for a representative sample of residential customers without interval metering.”

None of the evidence offered about difficulties at specific utilities shows that Voltus and Mission:data tried to get rules changed in state proceedings, PJM said. It is also unclear how the RTO could enforce the standard that statistical modeling is allowed when metering data is difficult to obtain, it argued.

“It is reasonable that CSPs may have to conduct some level of administrative work in registering residential demand response customers, and the complaint offers no clear criterion by which PJM could determine whether interval metered data is ‘not reasonably available,’” the RTO said.

Granting the complaint would lead to widespread use of statistical modeling, which is less accurate than the actual metering data required today, PJM said.

PJM’s Independent Market Monitor also took issue with the complainants’ proposed remedy.

“Using statistical sampling when actual interval meter data is available would unjustly and unreasonably degrade PJM’s ability to accurately measure the megawatts of capacity actually available and the actual performance of that capacity and therefore degrade PJM’s ability to maintain resource adequacy and to correctly determine efficient capacity market prices through supply and demand in the market,” the Monitor told FERC. “In addition, such treatment would introduce undue discrimination in favor of the demand response resources that do not use available meter data, which is what all other capacity resources are required to use.”

DR has to be timely and verifiable because knowing exactly when and how much load is cut is critical to reliably operating the grid and accurately compensating, the Monitor argued.

“If load reductions are only measured on coarse intervals or through statistical sampling, it is not possible to verify that the defined reduction can occur and did occur when dispatched and thereby to count on it for reliability and compensate it appropriately,” it said. “The public interest in system reliability and efficiency justifies the metering requirement for participants seeking to sell demand response.”

Exelon argued that the complaint misconstrues utility data practices, which are required by state regulations.

The company’s utilities “adhere to state laws and regulations to safeguard customer data, including complying with critical energy/electric infrastructure information (CEII), which includes sensitive grid and infrastructure data,” Exelon told FERC. “Furthermore, where the complaint objects to CSPs’ limited access to tools available for licensed retail electric suppliers, the complaint is in fact taking issue with state laws, regulations and fundamental elements of restructuring that require such limitations.”

Voltus and Mission:data were not without their supporters, which included CPower.

“PJM’s present rules have erected an impenetrable barrier to curtailment service providers seeking to enroll residential customers in demand response programs,” the company said. “CPower has experienced identical unreasonable barriers, both before and since CPower filed a similar unsuccessful complaint in 2023.”

Posted on

Stakeholder Forum: Connecticut’s Regulatory Drama Keeps Exploding

By Bryson Hull

One of the foundational lessons of journalism holding the powerful to account is the downfall of President Richard Nixon, who resigned rather than face impeachment after reporting uncovered evidence he’d lied about Watergate. No one ever called Nixon “probably the best president.”

Yet after Connecticut’s chief utility regulator, Marissa Gillett, resigned while facing an impeachment hearing, we are reading fans of her advocacy calling her “probably the best regulator in the country.”

Gillett’s exit tracks President Nixon’s — and the lesson that the cover-up is worse than the lie is being proven again because certain journalists are doing their job.

The hagiography of Gillett as a superior, ground-breaking regulator flies in the face of the circumstances of her exit, and unfolding evidence that the Public Utilities Regulatory Authority (PURA) under Gillett hid public records that would have proved clear bias in an agency that is quasi-judicial in mission and by statute.

Here are the facts. Gillett, a lawyer, denied under oath before the Connecticut General Assembly that she restricted her fellow commissioners’ access to PURA staff. Stunningly, a printed color copy of an email laying out those restrictions appeared in The Hartford Courant, which had requested it under Connecticut’s Freedom of Information Act.

This prompted a call for her impeachment by the Republican minority, and agreement by the Democratic Speaker of the House to entertain that request for what would have been the first such hearing in Connecticut in two decades.

Bryson Hull

House Minority Leader Vincent Candelora wrote in his letter seeking an impeachment inquiry that “in direct contradiction to Ms. Gillett’s sworn testimony during her confirmation hearing, she did in fact issue a directive to the other commissioners of the Authority that restricted access to support staff.”

I was aware from PURA sources over a year ago that the email and directive existed, yet it was not produced by the agency until there was no choice. Unfortunately for PURA’s leadership, a sitting commissioner had kept a hard copy — who handed it over to the attorney general’s office.

What followed was stunning sequence of events: The attorney general’s office, defending PURA in a lawsuit over two rate cases filed by two of the state’s natural gas utilities, capitulated and offered to give the utilities the legal relief they sought by sending the cases back to PURA with Gillett recused.

Subsequently, the presiding judge admonished both PURA’s general counsel and the attorney general’s office for failing to produce the documents they knew existed. PURA on Oct. 27, in another attempt to settle the case, admitted Gillett violated the law.

At the center of this case was the utilities’ assertion that Gillett was biased, which arose from a previous scandal in which Gillett denied authoring an opinion article signed by the chairs of Connecticut’s Energy and Technology Committee, PURA’s committee of jurisdiction.

Months of litigation over two utilities’ rate cases had come to hinge on whether Gillett was involved in writing a December 2024 op-ed under the names of two legislators to whom she is inarguably close. The litigation revealed more cover-up attempts in apparent contravention of state law, such as her decision in November 2023 to set her phone to auto-delete text messages after just 30 days.

The opinion article accused Connecticut’s utilities of paying credit ratings agencies to lower their credit ratings — after all five of them had their ratings slashed because of PURA’s aggressive, erratic cuts to rate requests. This prompted Bank of America to say Connecticut had “probably” the “worst regulatory environment in the country” and Moody’s to declare it “the least credit supportive utility regulatory environment” in the U.S.

The opinion article is an example of inartful blame-shifting, because its premise is utterly absurd to anyone with even a passing understanding of how federally regulated credit ratings agencies work — never mind the Enron-level legal exposure both the ratings agency and the company involved would face.

None of this came about because of some “escalating conflict” with utilities: all of it was the unforced error of Gillett and a few high-ranking PURA officials, combined with their later attempts to lie and cover it up. By turning regulation away from collaboration and into an adversarial process, the regulated companies have no choice but to press their case.

There is likely to be no let-up on that front, especially in light of new allegations of a cover-up. PURA’s executive secretary wrote a letter on Oct. 6 outlining orders he’d been given by PURA’s general counsel to deny that adverse public records existed. PURA declined to comment because of an ongoing personnel investigation, a Oct. 28 report in The Hartford Courant says.

Alas, Gillett — emboldened by her allies in the legislature and the governor’s office — which for six years refused to appoint PURA’s statutorily required five commissioners lest Gillett’s power be diluted — acted with perceived impunity and got caught because of journalistic vigilance.

Seeking a fresh start without the embarrassment of an actual investigation, Gov. Ned Lamont (D) on Oct. 20 appointed four new PURA commissioners and named Thomas Wiehl, formerly of the Connecticut Office of Consumer Counsel, as chair. With PURA at a full complement of five commissioners with diverse expertise, Wiehl signaled in his first press conference that he will emphasize collaboration and return PURA to its traditional role as a professional, impartial regulator.

For PURA to succeed, an honest, thorough accounting of the Gillett era is required. Since collaboration is at the core of smoothly functioning regulation, trust with the regulated companies and the ultimate end users — the people of the state of Connecticut bearing some of the nation’s highest retail electricity rates — must be rebuilt.

This is not just to ensure that Connecticut’s regulation is proper, reasonable and working in the interest of the people, but to ensure that PURA’s record under Gillett is not portrayed as a model of propriety or best practices in the national conversation about the future of regulation.

The facts speak otherwise, thanks to good, old-fashioned journalism that uncovered a record riddled with deceptions. If Gillett is the nation’s best regulator, the U.S. is in real trouble. Let Connecticut’s embarrassing regulatory saga be a lesson for other jurisdictions on what not to do.

Bryson Hull, Consumer Energy Alliance’s deputy Northeast director, is a former journalist who has written about energy issues since being hired to cover Enron Corp. a year before its then-record bankruptcy.

Posted on

MISO Requests Nearly $450M Budget for 2026

DETROIT — MISO said its 2026 budget requires an increase of more than 11% over 2025’s.

MISO plans to allot itself $448.4 million in operating expenses and project investments in 2026, up 11.2% from 2025’s $403.3 million budget, CFO Melissa Brown told the Board of Directors’ Audit and Finance Committee on Oct. 29.

The RTO said it would increase its administrative fee from 51 cents/MWh in 2025 to 54 cents/MWh in 2026.

Brown told the committee that modern systems are more expensive to implement and maintain, and MISO needs to spend more to complete the switch from its legacy software to newer technology.

“That’s kind of the balancing act we’re in right now,” Brown said.

The committee voted unanimously to recommend the budget. The full board will vote on whether to approve the draft 2026 spending amounts at its year-end meeting Dec. 11 in Indianapolis.

Brown said the budget may be reduced by that time, with MISO shedding about $2 million to $3 million in project investments.

MISO now experiences more volatility in its financial estimates for its major projects, Brown said, including evolving design work on new initiatives such as planning for large loads, rolling out ambient-adjusted ratings for transmission lines, working on the interconnection queue fast lane and getting the regular queue down to a single-year process.

The RTO also plans to hire 28 staff members for new positions in 2026, spread across operations, planning and cybersecurity.

Brown said MISO’s capital investments will jump to $32.4 million in 2026 — up $2 million — mainly from an upgrade to its headquarters-based control room in Carmel, Ind. Brown said the control room hasn’t had an overhaul since its inception.

“To say that it is overdue is probably an understatement,” Brown said during MISO’s last Board Week in Detroit in September.

The stakeholder-led Finance Subcommittee has endorsed the budget.

“MISO has taken a conversative approach with the budget and not yet factored potential load growth from data centers and other new load activity, which could reduce MISO rates,” subcommittee Chair Mitch Myhre, of Alliant Energy, said of the RTO’s 2026 financial plans at the Advisory Committee’s meeting Oct. 28. If MISO collects more from members because of more load being served, it could lower the rate it charges members. But Myhre said the “dynamic environment” today means no one quite knows how much load upsurge to expect.

Posted on

U.S., Westinghouse Partner for $80B in Nuclear Construction

The U.S. has entered a strategic partnership to pursue construction of at least $80 billion worth of Westinghouse nuclear reactors nationwide.

Cameco Corp. and Brookfield Asset Management, the two owners of Westinghouse Electric Co., announced the agreement Oct. 28.

The company announcements were missing some specifics, and the Trump administration did not make its own announcement. But piecing together the information available, it appears the U.S. has agreed to use tools at its disposal to facilitate construction of reactors and then help pay for them, possibly with Japanese investments, in return for a share of profits and a potential ownership share.

The partnership provides for the U.S. government to arrange financing and facilitate the permitting and approvals for new Westinghouse reactors to be built in the U.S., including near-term financing of long lead-time items.

Among many other things in his series of nuclear executive orders May 23, President Donald Trump ordered that 10 new large reactors be designed and under construction by 2030.

The 1.1-GW Westinghouse AP1000 reactor at the center of the Oct. 28 announcement would fit the bill, as it is a proven design intended for modular construction and is being used in multiple projects under way worldwide.

But the company announcement did not specifically say the $80 billion or more would be directed to AP1000 construction or say where the money would come from.

The Brookfield announcement said:

“The partnership contains profit sharing mechanisms that provide for all parties, including the American people, once certain thresholds are met, to participate in the long-term financial and strategic value that will be created within Westinghouse by the growth of nuclear energy and advancement of investment into AI capabilities in the United States.”

This sentence was omitted from the Cameco announcement, which contained much more specific information:

“Under the new strategic partnership, the U.S. government will be granted a participation interest which, once vested, will entitle it to receive 20% of any cash distributions in excess of $17.5 billion made by Westinghouse after the granting of the participation interest. For the participation interest to vest, the U.S. government must make a final investment decision and enter into definitive agreements to complete the construction of new Westinghouse nuclear reactors in the U.S. with an aggregate value of at least $80 billion.

“Additionally, in recognition of the anticipated acceleration of long-term value creation that the U.S. government is expected to help unlock by deploying its financial, regulatory, policy and diplomatic tools to support the objectives of the partnership, if, on or prior to January 2029 the participation interest has vested, and if the valuation in an initial public offering (IPO) of Westinghouse is expected to be $30 billion or more at that time, the U.S. government will be entitled to require an IPO.

“Immediately prior to, or in connection with the IPO, the participation interest will directly or indirectly convert into a warrant, with a five-year term, to purchase equity securities equivalent to 20% of the public value of the IPO entity at the time of exercise after deducting $17.5 billion from the public value.”

Support from Japan Investment

The details of the binding term sheet announced Oct. 28 are expected to be replaced with definitive agreements reached through negotiation, Cameco said.

The Brookfield announcement quoted U.S. Energy Secretary Chris Wright and U.S. Commerce Secretary Howard Lutnick cheering the strategic agreement. But neither Energy nor Commerce made any announcement or offered any detail about the agreement.

The White House offered the clearest insight into the finances later Oct. 28, with an announcement from Trump’s ongoing diplomatic tour of Asia, saying that as part of its July agreement to invest $550 billion in the U.S., Japan now has agreed to invest up to $332 billion in critical U.S. energy infrastructure, including Westinghouse AP1000 reactors, GE Vernova small modular reactors and several other types of equipment from other companies.

All of this would fit with Trump’s push for U.S. energy dominance, in part with a massive increase in nuclear generating capacity, and his vision of a revitalized U.S. industrial base.

Until recently, U.S. nuclear energy development had stalled because of the high cost and long timeline for construction. Part of the problem was there have been so many different designs in the U.S. and so few new plants were being built that economies of scale and institutional knowledge were not being developed for construction.

The Plant Vogtle units 3 and 4 expansion in Georgia, for example, was completed years behind schedule and vastly over-budget and helped run Westinghouse into bankruptcy court in 2017.

But Plant Vogtle was the first of its kind in a generation — subsequent efforts are expected to proceed more smoothly. Even Vogtle Unit 4 was faster to completion than Unit 3.

A U.S. Department of Energy report in June noted that the second series of AP1000 reactor construction in China is reaching milestones much more quickly than the first series and predicted that time and cost savings also would accrue in the U.S. if a steady stream of AP1000 reactors are built.

As the demand for nuclear power grows nationwide and worldwide, Westinghouse is presenting the AP1000 as the solution to these first-of-a-kind challenges, offering modular construction in a shorter time frame with simpler design, fewer components, smaller amounts of material and a compacted footprint.

Two AP1000s are in operation at Plant Vogtle and four in China, Westinghouse reports, and 32 are contracted or under construction worldwide.

The AP1000 is not one of the cutting-edge Gen IV reactors in the midst of intense research and design, but rather an advanced evolution of traditional models — a Gen III+, as Westinghouse calls it.

Posted on

FERC CIP Audits Find Ongoing Cloud Issues

Electric utilities trying to use cloud services to enhance their business continue to face “challenges” complying with NERC’s Critical Infrastructure Protection (CIP) standards, FERC staff said in a report on the commission’s 2025 audits for CIP compliance.

The authors of the 2025 Lessons Learned from Commission-led CIP Reliability Audits report also highlighted issues arising from entities’ failure to ensure CIP compliance from third-party contractors and to consider distributed energy resources and distribution-connected generation when categorizing their control centers.

FERC has conducted CIP audits since 2016 for each fiscal year, which runs from Oct. 1 to Sept. 30 of the following year. During the fiscal year, staff from FERC, NERC and the regional entities conduct audits with select utilities, comprising “data requests and reviews, webinars and teleconferences, and virtual and on-site visits.” The visits include interviews with entities’ subject matter experts, employees and managers; demonstrations of operating practices and procedures; and field inspections of high-, medium- or low-impact cyber assets.

As in previous years, details of the audits, such as how many audits were performed and which utilities were visited, were not disclosed in the report. The authors wrote that “while most of the [entities’] cybersecurity protection processes and procedures … met the mandatory requirements of the [CIP] standards, potential noncompliance and security risks remained.”

The warnings about cloud services came in a discussion of two instances where entities used cloud services to perform the functions of electronic access control or monitoring systems (EACMS) and physical access control systems (PACS). FERC staff observed that the CIP standards were originally “developed prior to the advent of cloud services [when] registered entities housed their cyber assets and cyber systems on premises.”

While efforts are underway to incorporate cloud technology into the CIP standards through Project 2023-09 (Risk management for third-party cloud services), the standards as they currently stand “simply do not contemplate cloud services,” the authors wrote. This fact creates “challenges demonstrating CIP compliance” for entities trying to use such services.

For example, FERC staff observed that CIP-004-7 (Cybersecurity – personnel and training) requires entities to conduct and demonstrate personnel risk assessments, including identity verification and background checks, for all individuals with electronic or physical access to grid-connected cyber systems. However, if cloud services are used, then this category would include employees of the cloud service provider, and entities may not be able to conduct investigations into such people.

CIP-010-4 (Cybersecurity – configuration change management and vulnerability assessments) presents another challenge, the authors wrote, because it “requires the development, maintenance and documentation of a baseline [system] configuration,” including multiple levels of hardware and software. This would be difficult to produce in a cloud system, where hardware and system-level configurations are often abstracted, and the integrity and source of software can be hard to verify.

To address these risks, FERC staff said entities should ensure that their high- and medium-impact cyber systems do not use cloud services. Low-impact systems may use cloud services, but entities should monitor their status and be prepared to mitigate compliance risk associated with the cloud if the impact rating changes.

Third-party Compliance Outsourcing Risks

Third parties were also mentioned in another section of the report that discussed utilities’ use of outside entities to help meet their compliance duties. Staff wrote that auditors “observed several instances where registered entities did not perform due diligence when relying on third parties.”

In one case, auditors saw that a utility did not properly oversee a firewall update that it contracted to a third party, and that party did not complete the task. This left unnecessary inbound and outbound electronic access within the entity’s firewall, a violation of CIP-003-8 (Cybersecurity – security management controls).

Another entity contracted with a vendor to install, test and maintain a cloud-based PACS, including the recurring 24-month testing required by CIP-006-6 (Cybersecurity – physical security of BES cyber systems). However, the vendor did not conduct the testing, and the utility lacked oversight controls to tell whether the vendor had done so.

Finally, a utility hired a third party to conduct vulnerability scanning, review scanned results and prioritize mitigation plans as part of the vulnerability assessment required by CIP-010-4. However, the entity did not participate in all phases of these activities. FERC staff did not indicate whether the third party failed to perform these tasks but observed that by failing to participate, the entity was already in violation of the standard.

Staff said that entities could mitigate the risk posed by outsourcing compliance functions to third parties by implementing compensating controls such as contractual agreements, internal controls to provide oversight, and ensuring third-party staff, infrastructure and data are located within the continental U.S.

DER Classification Oversights

The last issue flagged in the report had to do with the impact rating assigned by utilities to control centers as required by CIP-002-5.1a (Cybersecurity – BES cyber system categorization). Auditors found that some entities “failed to consider DERs and distribution-connected generation in their calculations” of the impact rating of a control center performing generator operator functions.

This oversight meant that operators lacked insight into the true level of generation on their systems, FERC staff wrote, especially because in some cases DERs — though small individually — accounted for large amounts of generation in the aggregate. Failing to properly categorize these systems meant entities might not apply the proper controls.

FERC staff recommended that entities “assess and document generation resources holistically, including DERs,” and ensure that they are assigned the impact rating commensurate with their true capacity.

Posted on

‘Aggressive’ EDAM Schedule ‘Going Smoothly’ for PacifiCorp, PGE

PacifiCorp and Portland General Electric remain on track to join CAISO’s Extended Day-Ahead Market (EDAM) on their planned entry dates, although the schedule remains “very tight and very aggressive,” CAISO executives said during a stakeholder meeting.

“Things are going very smoothly,” CAISO Chief Information and Technology Officer Khaled Abdul-Rahman said during the Oct. 27 Western Energy Markets Regional Issues Forum (RIF) meeting. “We are going to be in market simulation for [PacifiCorp] until mid-January 2026, and our go-live is scheduled for May 1, 2026.”

PacifiCorp’s systems are being tested in EDAM’s market simulation phase, which is a critical step to ensure market features, rule changes and system upgrades are working as designed, CAISO said in a document on the subject.

CAISO in 2025 has held workshops to show how more complicated parts of EDAM will work, such as scheduling at interties, Abdul-Rahman said, and the ISO plans to hold more elaborate workshops on the subject in November.

“We have to make sure our existing market participants are comfortable with the changes,” Abdul-Rahman said. “And in terms of post-market implementation, the main challenge is preparing settlement data … this is the area that we are focusing on a lot because there are a lot of changes.”

CAISO is working specifically on implementation challenges associated with congestion revenue allocation, although these challenges are “not impacting our plan” to begin EDAM in 2026, Abdul-Rahman said. (See CAISO’s EDAM Scores Simultaneous Wins at FERC.)

While EDAM’s market simulation phase continues, PacifiCorp is transitioning from a five-day per week operation to a seven-day per week operation, Paul Wood, PacifiCorp director of portfolio optimization, said at the meeting.

“The big thing to stress is that there has to be a lot of continuous training, testing and development,” Wood said. “Getting employees trained to participate in the EDAM market while continuing to perform daily jobs is [important]. There’s been a lot of training for employees to get their tools ready for a total change … on May 1.”

Ensuring vendors and consultants are involved early helps clear up assumptions before they become problems, Wood added. And flexibility through the transition to EDAM is key, since market rules and designs will shift, he said.

PGE is on track to begin its EDAM market simulation phase in March 2026, complete the phase by June 2026, and then enter the EDAM on Oct. 1, 2026.

RIF Transition Update

RIF committee members proposed to move forward with the transition of the RIF into the Stakeholder Representatives Committee (SRC) to be established for the Regional Organization for Western Energy being developed by the West-Wide Governance Pathways Initiative, which eventually will assume governance of the EDAM and Western Energy Imbalance Market (WEIM). (See Pathways Co-chair Maps out ‘Enhanced’ Stakeholder Process for Western Markets.)

The timing and implementation approach for the transition need to be determined, and existing functions of the RIF need to continue in the meantime, committee members said. (See Pathways Initiative Clarifies Near-term Division of Labor with CAISO.)

One stakeholder asked the RIF committee to discuss the advantages of starting the SRC directly after ending the RIF, rather than including a transitional phase, so “folks can stand up and walk from one room to the other.”

Lindsey Schlekeway, NV Energy market policy manager and WEIM entity sector liaison, said many RIF stakeholders are the same stakeholders who will be in the SRC, so if “we can’t find a clear method for the transition, a lot of duplicative work would occur.”

“This is going to be a huge effort in order to stand up this new stakeholder committee, so we are just trying to find the most efficient and streamlined path,” Schlekeway said.

Posted on

Pathways Co-chair Maps out ‘Enhanced’ Stakeholder Process for Western Markets

The West-Wide Governance Pathways Initiative’s Launch Committee Co-Chair Pam Sporborg said the stakeholder process of the new regional organization that will oversee CAISO’s energy markets is an evolution of the ISO’s Regional Issues Forum (RIF).

The RIF is a space for the power industry to discuss issues related to the ISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). However, following the passage of AB 825 in California, CAISO will hand over responsibility for the markets to the independent Regional Organization for Western Energy (ROWE), which is being designed by the Pathways Initiative’s Launch Committee. The handover is scheduled for early 2028. (See Newsom Signs Calif. Pathways Bill into Law.)

Speaking at the RIF on Oct. 27, Sporborg, director of transmission and markets at Portland General Electric, said the Pathways Initiative’s Stakeholder Representatives Committee (SRC), which will provide advisory support to ROWE’s board, builds on the RIF’s success, praising the forum as enabling “more in-depth dialog on the stakeholder process and the evolution of the market.”

“We … see the Stakeholder Representatives Committee as this incremental evolution beyond the RIF sector liaison role with an expanded number of sectors that I think add some granularity and new voices into the process,” Sporborg said.

“We have more of an opportunity to really have additional engagement in each of the policy development processes,” Sporborg said. She added that there is an “opportunity to bring … members of each sector into that policy development process to ensure that as the market evolves, it’s really evolving at the direction of stakeholders.”

She noted the sectors will be involved in market development by providing SRC members with more say on proposals through an enhanced voting process, comment engagement, analysis and other opportunities.

Sporborg explained the enhanced voting approach, saying stakeholders will submit indicative votes throughout the policymaking process to ensure concerns are being addressed and to provide more analysis on proposals rather than SRC members simply voting “support, oppose or neutral.”

The Launch Committee is considering a remand process to allow entities to refine unpopular proposals. This would apply to final proposals prior to an initiative being sent to the ROWE board.

“We want to enhance the way these votes get shared with the board, so that there would be some opportunity to identify … more analytics behind that support, oppose or neutral vote to help the board understand if there’s opposition in a particular sector,” Sporborg said. “For example, do all small utilities oppose a proposal, or does this have significant opposition in the IPP sector? We want to be able to have that kind of analytic show through the tabulated voting.”

Already, the Launch Committee has announced that representatives from nine sectors will advise on the nomination of members to ROWE’s initial board. (See Pathways to Engage Broad Set of Stakeholders to Select Independent RO Board.)

Those entities include:

    • EDAM entities
    • WEIM entities
    • ISO-participating transmission owners
    • Non-IOU load-serving entities serving load from WEIM or EDAM
    • Public interest organizations
    • Independent power producers, independent transmission developers and marketers
    • Consumer advocates
    • Large commercial and industrial customers
    • Distributed energy resources

Sporborg said the Launch Committee envisions a “hybrid structure” that brings together staff expertise and stakeholder input, “where you get the ability to execute quickly and to drive forward through a staff-driven process. But by bringing more of the voice of the stakeholder into that process, we can have more of a stakeholder-driven policy evolution.”

Posted on

Load Growth Requires Holistic Interconnection Reform, Experts Say

Holistic reform to interconnection barriers is essential to meeting rapidly growing power demand across the country, experts emphasized at a recent webinar.

Panelists at the Resources for the Future webinar on Oct. 27 discussed underlying challenges of interconnection, along with reform efforts underway throughout the U.S.

As demand for new generation accelerates, “we need all hands on deck,” said Sarah Toth Kotwis, senior associate at the nonprofit think-tank RMI.

“We are in a really crucial time,” said Joe Rand, energy policy researcher at the Lawrence Berkeley National Laboratory. “If we don’t have transmission and headroom to connect that new supply, we’re simply not going to be able to do it.”

Rand said queue backlogs ballooned in recent years, though some declines in queue capacity occurred between 2023 and 2024. He noted that interconnection requests generally have low completion rates; Berkeley Lab data indicate that only about 13% of the capacity entering interconnection queues achieves commercial operation.

The core issues of interconnection are long wait times and high costs, Toth Kotwis said. To address these issues in the short-term, grid operators should focus on process changes to connect projects as quickly and cheaply as possible, while focusing long-term efforts on “proactive transmission planning that optimizes planning throughout the system.”

Aubrey Johnson, vice president of system planning and competitive transmission at MISO, said the RTO’s queue saw major growth starting in 2021. He said MISO has been actively pursuing interconnection improvements to keep up with increasing interconnection requests.

“A lot of what FERC Order 2023 has done, MISO had already been in the process of doing,” Johnson said. “We’ve been doing [cluster studies] since back in 2019.”

FERC Order 2023 directs grid operators to adopt first-ready, first-served cluster study processes and require generators to meet significant site control and financial requirements.

“What we’ve found out from the cluster study is: it has the ability for us to be faster, but it actually does not necessarily get us to be faster because of all the restudies that end up happening,” he noted.

More projects joining the queue has caused queue cycles to take longer, causing delays to the start of subsequent queue cycles, Johnson said. He added that MISO has struggled with high dropout rates, with only about 20% of the projects that enter MISO’s queue signing generator interconnection agreements.

“Time will tell” how the increased cost requirements and withdrawal penalties mandated by Order 2023 will affect completion rates, but these reforms should affect the volume of projects entering queues, Johnson said.

Johnson added that forward-looking transmission planning efforts, such as MISO’s Long-Range Transmission Planning initiative and MISO and SPP’s Joint Targeted Interconnection Queue process, should help lower interconnection costs and increase project viability.

Rand of the Berkeley Lab said the requirements of Order 2023 should reduce the number of speculative projects in the queue.

“In 2024, we did see just unprecedented levels of withdrawals,” Rand said. “I think a lot of older, nonviable projects are really starting to pull the plug as they see these reforms being implemented.”

While reducing the number of nonviable projects should help, developers have a different perspective on so-called speculative projects, Rand said.

“I think they would say that none of their projects are speculative per se; they would happily build any of these if the interconnection costs were reasonable to them, and, of course, if the other factors like permitting and offtake agreements lined up,” he said.

Rand said the Order 2023 reforms have not solved the fundamental issue of price transparency that motivates developers to submit a high volume of requests.

“From a developer standpoint, they don’t have another way to identify what the interconnection cost requirements are going to be for that particular project until they get in the queue,” he said.

In PJM, projects with network upgrade costs higher than $100,000/MW “are over 50% more likely to drop out before the third study than projects that don’t have that,” said Sarah Johnston, associate professor at the University of Calgary.

“Presumably this is new information, because otherwise they wouldn’t want to plan the project and go through the process,” Johnston said. “And so, it does speak to how having this up-front certainty could help in getting some generators out of the queue.”

Speakers emphasized that resource development challenges are not limited to interconnection barriers, and noted that permitting, supply chain and contracting issues frequently prevent development after resources sign interconnection agreements.

Toth Kotwis said some of the issues projects face after achieving an interconnection agreement can be attributed to how long the study process takes.

“Projects that are connecting now, in 2025, to PJM’s grid have been waiting in the queues for eight years on average,” Toth Kotwis said. “So much has changed in the last eight years … of course it’s a struggle to get built, because we’re in a new reality of supply chain constraints and global geopolitics making everything more difficult.”

Johnson of MISO said he’s confident RTOs across the country are making significant progress toward addressing interconnection barriers, but that the industry should “be giving the same level of attention” to helping projects with signed interconnection agreements reach commercial operation.

He said there are more than 60 GW of projects with signed agreements in MISO alone, more than half of which have been delayed beyond their planned in-service date.

“Across the organized markets, there’s over 260 GW of signed [generator interconnection agreements] today that know what their upgrade costs are, that supposedly would be viable projects, but most often are not getting built,” Johnson said.