A California electric resource portfolio that incorporates 63 GW of clean energy and new storage by 2035 has received approval from state regulators and will be sent to CAISO for use in its 2025/26 transmission planning process.
The California Public Utilities Commission voted 4-0 on Feb. 20 to approve the portfolio, which as modeled reaches 99% clean energy serving retail load by 2035. The portfolio projects a decrease in natural gas generation in the CAISO system, with a 71% drop from 2026 to 2035 and an 80% reduction by 2040.
“This is an extremely promising glimpse of a possible future,” Commissioner John Reynolds said before the vote.
The electric resource portfolio is an annual exercise for the CPUC, which described it as a “key input” into CAISO’s transmission planning. In addition to a “base case” portfolio, the commission approved a “sensitivity portfolio” that incorporates a larger amount of long-lead time resources, such as geothermal energy, offshore wind and long-duration energy storage.
Wind Study
The commission’s decision also asks CAISO to study “but not yet trigger the investment in new transmission to support some out-of-state wind and Northern California wind” outside of the CAISO balancing authority area.
The decision noted that the amount of out-of-state wind on new transmission in the 2025/26 portfolio has increased to 9 GW in 2035, up from 6 GW in 2034 in last year’s portfolio. Sources of out-of-state wind include New Mexico and Wyoming.
“The new amounts, if fully developed, will require additional transmission beyond those projects that are already approved and in development, including SunZia, SWIP-North and TransWest,” the CPUC said in its decision.
The additional transmission could be “complex to accomplish” and “require regional cooperation,” the decision said.
Another issue discussed in the decision is the deliverability of energy from offshore wind (OSW) along the Northern California coast. Most deliverability on existing Northern California transmission has been allocated to resources now in the interconnection queue, the CPUC said, pointing to battery storage projects in particular.
“If … CAISO does not reserve some deliverability for OSW and ensure there is adequate transmission available for that deliverability, it will all be used by the storage in the queue,” the CPUC said. But adding transmission for OSW runs the risk of overbuilding “at considerable cost,” if all the resources are not developed.
The decision directs CPUC staff to work with CAISO to identify storage projects with transmission plan deliverability that could have the biggest impact on OSW in the area.
Building the Portfolio
The CPUC built its electric resource portfolio using information from 2022 integrated resource plans filed by utilities under its jurisdiction, plus additional identified resources.
The base case is “reliability- and policy-driven,” according to the CPUC. For example, it factors in a greenhouse gas emissions target for the electricity sector of 25 million metric tons (MMT) by 2035.
And the two study years for the base case portfolio, 2035 and 2040, satisfy the 0.1 loss of load expectation (LOLE) standard. The process also includes busbar mapping, which identifies locations of electricity generation and storage.
Along with its base case portfolio, the CPUC also typically develops a sensitivity portfolio as a “reasonable alternative” for CAISO to evaluate.
Last year’s sensitivity case was a high natural gas retirement scenario, which the CPUC said was “designed to assist in planning for the potential future retirement of fossil-fueled resources.”
SPP has promoted Felek Abbas to senior vice president and chief technology and security officer, combining his current duties as CSO with responsibility for information technology and corporate facilities.
Abbas joined SPP in January 2024 as vice president and CSO, overseeing SPP’s cyber and physical security, emergency management and business continuity. He takes over the IT responsibilities of Sam Ellis, who retired in February.
“Given the rapidly increasing changes and risks confronting our industry, it’s essential we have the very best leading our pursuit of transformative technology,” said incoming SPP CEO Lanny Nickell.
Abbas has more than 30 years of electric industry experience in cybersecurity, engineering, consulting, risk management, audit and compliance. Previously, he was senior manager of cybersecurity for power and utilities at Ernst & Young. Abbas also has served as a NERC critical infrastructure protection compliance adviser and auditor.
VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed a proposal to rework how demand response (DR) resources are modeled in PJM’s effective load carrying capability (ELCC) framework, most significantly by replacing the availability window with round-the-clock profiling of DR load.
The proposal received 74% sector-weighted support and was approved by the Members Committee Feb. 20 as part of its consent agenda. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)
The revisions to the Reliability Assurance Agreement and Manual 20A are envisioned to more accurately align the capability of DR resources with the times reliability risks are most pronounced, particularly in the winter when a greater share of risks lie outside the 6-9 a.m. seasonal availability window. PJM’s Pat Bruno said about 17% of loss of load hours fall outside the availability window, having a significant impact on DR accreditation.
The package also would redefine the winter peak load (WPL) for DR participants to be measured at a set hour PJM believes best reflects the resource class’s overall ability to match system needs. Because individual resources’ WPL are measured at their highest point, regardless of time, adding them up to form a class-wide peak load would overstate the amount of curtailment capability there is, because those peaks would not necessarily coincide.
The third component would model the expected curtailment capability each DR resource is expected to provide by hour to reflect lower potential overnight in the ELCC and risk modeling analyses.
Bruno said the proposal would improve reliability, increase DR parity with generation by recognizing capability in all hours, capture more load and reduction capability, and improve the incentives for curtailment service providers to sign up customers that have more capability to curtail throughout the day.
The proposal targets implementation in the 2027/28 Base Residual Auction (BRA), which DR providers and consumer advocates argued waits too long to unlock the resource’s potential to mitigate tightening supply and demand in the capacity market. An alternative would have made the changes effective for the 2026/27 BRA. But some stakeholders argued that would complicate planning parameters and rules already subject to many changes with just months before the auction is set to be run in July. Bruno said PJM preferred the alternative to realize the reliability and risk modeling benefits sooner.
Calpine’s David “Scarp” Scarpignato said any change to the timeline on which planning parameters would be published would disrupt the ability for load serving entities to engage in bilateral transactions ahead of the auction, noting that the “R” in BRA stands for residual in recognition of its role in procuring capacity not secured through those trades.
“Even when it’s in our financial interest, we don’t always propose moving these parameters around,” he said. “You’re screwing up the market when you’re moving these timelines around like people are talking about.”
Had the alternative been endorsed, Bruno said PJM would have sought expedited treatment at FERC to minimize any impact on the planning parameters. Were that not granted, he said PJM could either publish two sets of parameters with and without the changes or delay publishing specific parameters that could be impacted by the filing. Those parameters are the installed reserve margin, forecast pool requirement, accredited unforced capacity factor, RTO-wide reliability requirement, and the capacity emergency transfer objective.
CPower’s Aaron Breidenbaugh said the proposal goes beyond paper changes to the amount of capacity DR could provide. Eliminating the availability window would require participating consumers to be ready to curtail at any time, he said, including hours they are not accustomed to thinking about.
“There’s going to be a lot of effort to try to accommodate that, but that’s exactly where the reliability benefit comes from,” he said.
Susan Bruce, representing the PJM Industrial Customer Coalition, said the 74% support for the package undercounted support for the actual changes proposed. Because the MRC votes on the main motion first and alternatives are considered only if that fails, she said some consumers voted in opposition in an effort to have an opportunity to vote on the faster implementation included in the alternate.
Market Monitor Joe Bowring opposed the PJM proposal. He noted that PJM does not use DR’s actual performance during the same critical hours that are used for all other capacity resources.
“The experience with DR during Winter Storm Elliott demonstrated that customer loads were already very low when DR was called and that DR provided only a very limited response,” he said in an email to RTO Insider. “PJM is crediting DR with an ELCC higher than gas fired combined cycles because PJM is assuming a response that is not supported by the data. PJM treats DR as an emergency only resource unlike all other capacity resources.
“PJM does not know the nodal location of DR. PJM simply ignores increases in DR load above WPL for DR when it is called. PJM fails to apply the same DR ELCC method for the summer as it proposes to apply in the winter. There is no reason to make an expedited and inadequately supported change to the DR ELCC while ignoring other ELCC issues. All ELCC issues are interdependent and should be part of an overall review,”
Bowring said the Monitor estimated that DR resources would be paid about an additional $235 million under the new ELCC if the next auction clears at the maximum price, an increase of about 36%. He agreed with PJM’s proposed use of a single coincident peak hour, elimination of the aggregate scaling factor and expansion of the performance obligation to all hours of the year.
FERC has approved CAISO’s proposal for implementing the Extended Day-Ahead Market (EDAM) “access charge” within its own balancing authority area.
Approved by FERC in June 2024, the access charge is a market mechanism designed to allow transmission owners (TOs) to recover revenue shortfalls they incur from transitioning their assets into EDAM, such as the loss of revenues stemming from reduced sales of short-term transmission service in the West’s existing bilateral electricity market. (See FERC Approves EDAM Tx Revenue Recovery Plan.)
The access charge framework is available to all EDAM participants. But because EDAM is not a full RTO, each participating entity is responsible for developing its own rules for implementing the mechanism within its BAA and filing the related tariff revisions with FERC. For that reason, the commission’s Feb. 20 order covers only CAISO and the treatment of the ISO’s participating transmission owners (PTOs) (ER25-437).
The EDAM access charge framework approved by commission in 2024 comprises a “three-component rate structure.”
Component 1 allows a TO to recover revenue shortfalls related to the transition from bilateral market transmission service to day-ahead market service, including market transfers that displace revenues expected from sales of short-duration non-firm and firm point-to-point transmission service.
Component 2 allows a TO recover a portion of the costs not reflected in the three-year “lookback” associated with the first component. That can include revenue shortfalls “from foregone sales of non-firm and short-term firm transmission service over certain new network upgrades and associated with the release of transmission capacity resulting from the expiration of EDAM legacy contracts,” FERC’s June 2024 order noted.
Component 3 enables a TO to recoup sales losses attributable to wheeling through an EDAM BAA or the CAISO BAA in excess of the total net EDAM transfer of the BAA, with costs based on the transmission used to wheel energy completely through the TO’s system.
CAISO-specific Elements
CAISO’s specific application of the access charge must differ from that of other EDAM participants because the ISO already is functioning with an organized day-ahead market, so its PTOs will not be transitioning out of the bilateral market upon launch.
The CAISO proposal contains some standard elements of the approved access charge framework, such as a provision allowing the ISO’s PTOs to conduct an annual EDAM access charge “true-up” process to ensure they are compensated when other EDAM BAAs benefit from using the PTOs’ systems for transfers.
The proposal also stipulates that each CAISO PTO will use the three-component rate structure to establish its EDAM recoverable revenue requirement within its existing high- and low-voltage transmission revenue requirement. The aggregate of those estimates will make up the “EDAM recoverable revenue” for the entire CAISO BAA, the ISO said.
But because CAISO already has a day-ahead market, application of the three recovery components will differ from other EDAM participants.
For example, in non-CAISO BAAs, Component 1 is intended to capture an “approximation” of transmission services displaced by EDAM transfers — such as firm or non-firm point-to-point transmission services. But those services don’t exist in the ISO. Instead, a similar displacement will occur in CAISO when scheduling points at the ISO’s border are converted into internal interties in EDAM.
As CAISO explained in its filing, the wheel access charge (WAC) revenues that ISO PTOs historically have collected at those scheduling points no longer will accrue when those points become EDAM internal interties. To compensate for that lost revenue, CAISO proposed to allow each PTO to include within its Component 1 estimate the “appropriate portion” of historical WAC revenue for each scheduling point that corresponds with an EDAM internal intertie, subject to a true-up calculation.
“CAISO states that this is the equivalent of the limit equation established for the EDAM transmission owners under the accepted EDAM framework, but reflects the unique situation of the PTOs in CAISO,” FERC noted in its order, which accepted the ISO’s treatment of all three rate components with no requested changes.
“We find that CAISO’s proposal is appropriately tailored to the unique circumstances of the PTOs, which differ from that of EDAM transmission owners,” the commission wrote. “For instance, because the specific types of transmission service that Component 1 revenues are intended to capture do not exist in CAISO, we find reasonable CAISO’s proposal to enable each PTO to include within Component 1 of its EDAM recoverable revenue requirement the appropriate portion of the historical wheeling access charge revenue forgone for each scheduling point that corresponds with an EDAM internal intertie.”
The commission also approved CAISO’s proposal to allocate any EDAM access charges assessed to the CAISO BAA by other EDAM entities back to CAISO scheduling coordinators based on their share of gross load in the ISO.
“We find that the proposed approach allocates costs at least roughly commensurate with estimated benefits, because it allocates EDAM transmission costs to beneficiaries within the CAISO BAA in proportion to their benefit from EDAM,” the commission wrote.
Energy efficiency upgrades in the commercial and industrial sector have made LED lighting so common that additional upgrades require more than just swapping old bulbs for new technology, according to a report DNV released Feb. 20.
DNV worked with 12 power industry participants from around the country and interviewed 112 program implementers, vendors, manufacturers and lighting contractors to develop a bottom-up stock turnover model for its study, according to the report.
“Lighting has long been a staple of energy efficiency programs, providing a low-cost and -effort means to reduce energy consumption for homes and businesses. However, the widespread availability and adoption of LEDs has eroded these savings potential,” DNV’s Richard Barnes said in a statement. “This study outlines new ways that lighting can be used to provide customers and utilities with deeper energy savings while using established and effective utility energy programs.”
The C&I lighting market has reached the “late majority stage” on average around North America, representing 60% of lighting fixtures and 75% of national sales.
“While a large number of facilities across North America still have legacy technologies in place, upgrading lighting in those facilities will require program adaptations to target smaller buildings in harder-to-reach communities where much of the remaining potential lies,” the report says.
Outside of getting to those lagging areas, the report lists six areas that utilities and efficiency programs should focus on to get more efficiency as the market becomes saturated with LEDs.
The first is to replace older LEDs with newer, more efficient models that produce more lumens per watt; that would save 1.28 million MWh. The data show a 20% efficiency improvement between baseline LEDs now and the most efficient products over the next five years.
Advanced lighting controls, including network lighting and luminaire-level lighting without networking, would save 1.9 million MWh. The savings tend to be bigger in larger buildings with larger lighting demand.
While past efforts have focused on switching out the lights themselves with LEDs, swapping out the entire ceiling grid with new products could save 545,381 MWh. Such complete redesigns typically require hiring a “lighting designer,” and the feasibility depends on customer-to-customer, site-specific conditions.
“This differs from a one-for-one replacement of fixtures which often requires much less labor but cannot realize as much savings due to the persistence of improper lighting levels which only redesign can address,” the report said.
Another option is to make it so lighting can also be used for demand management by installing controls that can dim or turn off lights based on grid conditions and power prices, which would save more money than megawatt-hours.
Deploying UV lighting technology would help to sterilize the air in commercial buildings, which would lead to savings from HVAC systems.
Finally, the report recommends tunable lighting that allows modulations to the spectral output or color temperature independently from the total lumen output of lights. That offers potential health benefits from human-occupied buildings and can achieve savings in the afternoon and evening hours. It also can benefit marijuana grow houses, the report says.
The Texas Supreme Court heard oral arguments Feb. 19 from distribution utilities seeking to dismiss what may be the final lawsuit stemming from the deadly February 2021 winter storm, also known as Winter Storm Uri.
At issue is whether another Texas court should have dismissed the plaintiffs’ claims of gross negligence and intentional nuisance on the part of the utilities, Oncor, CenterPoint Energy and AEP Texas (24-0424).
More than 1,000 plaintiffs from across Texas alleged various claims against the companies that included negligence, gross negligence and nuisance following the storm, which is thought to have killed more than 200 people. Their cases were consolidated into a multidistrict litigation court, meaning they can be heard at once.
The utilities contend the claims are barred by ERCOT’s protocols governing their operations. A Texas trial court dismissed some claims but refused to dismiss those of negligence, gross negligence and nuisance. The 14th Court of Appeals in April 2024 granted mandamus relief in part, ordering dismissal of the negligence and strict-liability nuisance claims. However, it allowed the more severe gross negligence and intentional nuisance claims to proceed.
The plaintiffs’ attorney, Ann Saucer with the Nachawati Law Group, argued that the utilities failed to roll the outages during Uri, when ERCOT was desperately trying to stabilize the grid after it lost much of its gas generation. Instead, some customers were left without power for up to 80 hours.
Vinson & Elkins’ Michael Heidler, representing the utilities, said the plaintiffs “misunderstand” how ERCOT’s load-shed protocols work. He said utilities were told to avoid shedding load on lines equipped with underfrequency load-shedding circuits, which trip off if the frequency drops.
“When we get into load shedding or manual load shed, and the load shed obligation is sufficiently large, it becomes difficult, if not impossible, to rotate out the remaining load in a way that’s safe to the grid and complies with ERCOT’s load-shed protocol,” he told the court. “One of the things complainants say … is when we left certain neighborhoods on for the entirety of the load-shed event where, while others were subjected to load shedding, that’s exactly what ERCOT protocols require. We do have duties. We have regulatory duties.”
Heidler noted that the protocols require utilities to maintain power to hospitals and other critical infrastructure, law enforcement and nuclear plants.
The justices appeared skeptical of the plaintiffs’ arguments that the utilities intentionally kept the lights on in some neighborhoods at the expense of others.
Justice Brett Busby | Supreme Court of Texas
“They did that because they were consciously indifferent to people freezing to death,” Saucer alleged. “The only way that I’ve heard that these defendants are defending this is to just simply deny the truth of the petitions. I haven’t heard them actually say, ‘We thought everyone was going to be OK if we left them in this cold without power for two days.’”
“I think what they’re saying is, ‘We didn’t have a choice,’” said Justice Brett Busby, who directed most of the questions to the legal counsels.
“There is no proof of that,” Saucer countered.
“That does seem to be what they’re saying,” Busby responded. “Maybe on summary judgment, if we get that far, both sides would have some evidence of that. But it doesn’t sound like they’re saying, ‘We don’t have any excuse for this.’ … They’re saying, ‘We’re required by the Nodal [Protocols].’”
The Supreme Court last year overruled an appeals court in saying ERCOT and the Public Utility Commission were within the law when they raised wholesale prices to more than 300 times above normal during Uri. (See Texas Supreme Court Rules for ERCOT, PUC During Uri.)
A decision is not expected to be rendered for several months, but the high court normally issues judgments on all proceedings it takes up. Its current term ends in late June.
NEW ORLEANS — Speaking at an annual conference, MISO and SPP executives promised to open their queues’ floodgates.
Generation developers, however, laid out why generation construction remains tricky. And data center developers kept up calls for quick additions.
At the Gulf Coast Power Association’s MISO-SPP conference Feb. 19-20, SPP Vice President of Engineering Casey Cathey likened interconnection queue improvements to family reunions, where everyone agrees it needs to happen, but no one knows “the timing, where to go, who to pay and who has the power.”
During a panel on queue improvements dubbed “It’s a Cluster,” Cathey said SPP first must clear its queue backlog, where it has squeezed seven years of project cycles into three years of processing. SPP then hopes to introduce a consolidated planning process that would marry transmission planning with generator interconnection.
Cathey said SPP wants interconnection customers to know their total costs at the beginning of the queue, though he said it’s incumbent on developers to arrive having done substantial leg work on their projects.
SPP has more than 100 GW in its interconnection queue. Cathey estimates just 40% of the projects are viable, with only a quarter of those projects’ installed capacities ultimately being accredited.
Vice President of System Planning Aubrey Johnson said MISO has “been in some form of generator interconnection reform” over his seven years there. He said MISO believes its planned, backbone transmission projects will pare down network upgrade costs.
MISO’s queue contains 313 GW across 1,710 generation projects. The grid operator awaits about 57 GW of approved generation to come online. Johnson said about 27 GW of the delayed projects are more than two years behind stated commercial operation dates.
Johnson said in the 2025/26 capacity auction, MISO could be 2.7 GW short of meeting its planning reserve margin. He said risk is “knocking at” MISO’s door while construction timetables stretch out.
“We have a clear and present question today of how we’re going to meet the calls of our load-serving entities who have all this load coming on,” Johnson said. He said MISO’s plan to introduce a fast lane for certain projects that have regulator support and its efforts to automate studies with tech startup Pearl Street should help.
EDP Renewables’ David Mindham asked how the RTOs plan to handle the issue that load-serving entities likely will be favored in their respective expedited lanes over independent power producers.
Johnson stressed that the fast lane will be limited to a few queue cycles and then discontinued.
“This is in a box. This is not how we see life going on,” Johnson said. He added that he and his team are caught between the immediate reliability danger that necessitates MISO’s accelerated — albeit temporary — queue processing for select projects and achieving an automated study process that produces speedy study results for all interconnection customers.
Johnson said it would be beneficial if the U.S. Department of Energy would invoke the Defense Production Act to speed up the manufacture of transformers.
When asked what advice he had for interconnection customers, Johnson didn’t mince words.
“The first is: Build. Build,” he emphasized. “The second is: We’re getting faster. Get ready.”
SPP CFO David Kelley said if he could snap his fingers and fix anything in SPP, he’d be able to “press a button” to get instant study results on the precise level of transmission and generation development needed while those projects overcome challenges of permitting and siting and “getting hands on equipment.”
“Technology is moving so fast around us,” Kelley said, presenting a challenge for an industry “not known for” keeping up with technology.
Kelley said MISO and SPP alike are making concerted efforts to partner with technology companies and recruit those with skillsets in automation and AI for their operations.
Kelley borrowed a line from SPP CEO Barbara Sugg, who was unable to attend the conference, to sum up the zeitgeist. “What got us here won’t get us there,” he said.
‘Delayed, Delayed, Delayed’
“I think we have an energy scarcity five to 10 years out, and we have no path to build energy resources, it seems like. All the renewables we thought were going to come online are delayed, delayed, delayed,” said Colton Kennedy, Omaha Public Power District director of energy portfolio planning. He added that the firm supply from small modular reactors isn’t on the horizon at least until 2035, if one is optimistic.
Kennedy said resource planning has become knottier because developers aren’t sure what the future accreditation of their resources will be, since the overall energy mix influences those values. He said RTOs might consider levying the costs for ramping on those responsible for the needs, whether that be wind generation that dips or load that ratchets up suddenly.
Pattern Energy Vice President of Origination Holly Adams said RTOs’ current five- to six-year wait time in the queue isn’t “palatable” to generation developers. She also said the now-unstable status of tax credits, permitting reform and tariffs under the new presidential administration makes development an increasingly riskier proposition.
Adams added that severe weather episodes are causing insurance rates to skyrocket, with developers confronted with spending more to insure their projects.
More Expensive RA
Julien Dumoulin-Smith, a managing director at Jefferies, said it’s a reality that the price point of resource adequacy will continue to rise with inflation. He said many in the industry failed to appreciate the “writing on the wall’ a few years ago as labor costs and the capital costs of equipment began to rise.
“That’s the reality on the ground,” Dumoulin-Smith said. He estimated that the industry is at the beginning of an inflationary cycle and equipment will trend higher.
Electric Power Research Institute’s Justin Sharp said the industry needs more multidisciplinary expertise to understand how extreme weather conditions set off interconnected consequences in a shifting energy mix. He said it’s concerning the industry doesn’t fully grasp its evolving resource adequacy risk.
“I’ve got a presentation that I’ve given many places that basically says, ‘We’re flying blind,’” Sharp said, calling for “high-quality ground truth data” from generation owners.
Adams said that because no one really knows what technology will be developed over the next 20 years, generation should be judged by objective measurements like ramp rates instead of lumping generation types like natural gas together.
“It is not inconceivable, but it’s inevitable that we’re going to have eight- to 10-hour batteries,” Dumoulin-Smith added.
Dumoulin-Smith added that there’s a “serious discrepancy” between the energy delivery that data centers want and what utilities tell them is possible. He said that tension should create opportunities for independent power producers, arguing that’s what they were made for.
Dumoulin-Smith predicted that data center developers will push the envelope of what’s possible through innovation. He asked the audience rhetorically what’s going to happen when utilities cannot announce another coal plant extension or when they hit their limit on adding gas plants.
Organization of MISO States Executive Director Tricia DeBleeckere said while natural gas is helpful, there’s a limit to how many new gas plants can be built. She said utilities must be creative to source new capacity.
Adams said data centers require a 99.9% capacity factor that’s possible only with access to a wholesale market, possibly through future HVDC lines.
Louisiana Public Service Commissioner Mike Francis said he remains confident that natural gas buildout is the best bet for his state. He said that’s evidenced by Meta selecting Louisiana for a campus and striking a deal for a trio of gas plants with Entergy. (See Entergy La. Confirms Meta Data Center Behind 3 Proposed Gas Plants.)
“We have a lot of gas in the ground, it’s God-given, and we need to use it,” he said. “Let’s go back and open the doors on that fuel supply.”
“Data center, data center, data center — and crypto mining. That’s all we’re talking about in Oklahoma,” Oklahoma Corporation Commission Chair Kim David said.
David said though some data center developers are weighing building gas plants behind the meter, Oklahoma needs to make sure the data boom is regulated and doesn’t become the “Wild West.”
She said even if data center developers are successful in building their own plants behind the grid, they inevitably will want to interconnect to sell excess power. She said it’s a challenge to quell an attitude of manifest destiny from her legislature, governor’s office and data center developers.
“We’re all dealing with that type of mentality. But they don’t realize that we’re all connected. They’re not on an island just by themselves. If they want to be, great. … But that’s not how it’s going to happen,” she said, predicting that data centers will want backup wholesale power when their own plants inevitably experience outages.
David said in the meantime, her state is seeking the most reliable and cheapest mix of energy. She told the audience not to count out coal yet, noting that SPP on Feb. 19 likely met an all-time peak winter demand with coal’s help.
David said she hopes federal environmental regulations around natural gas “loosen up” so more plants can be built. But she said to get accredited capacity built to meet resource adequacy targets, grid operators’ interconnection queues must be efficient in getting resources connected.
‘Fits and Starts’
While many panelists said the past is no indication for the future grid, Grid United CEO Michael Skelly argued the industry can look back on the power industry’s trajectory of the past 140 years to get a general picture of how the grid stands to evolve now.
He said it’s “worth remembering” that it took John F. Kennedy’s presidential leadership to accomplish the Pacific DC Intertie. He also said the public has Jimmy Carter to thank for wind, hydropower and gas turbine advancements through the Public Utility Regulatory Policies Act.
Skelly said the demand for low-carbon resources won’t recede despite President Trump’s second administration. He said carbon-cutting measures remain priorities across polls.
“Progress in this area, I’ll remind my younger colleagues, is not always linear,” Skelly told the audience.
Skelly took a longer view of the data center issue and asked attendees to consider what happens if the power needs fade after a few decades and utilities are left needing to recoup the cost of expensive assets.
“We need to ask a lot of hard questions about this. I think people are still a little shy on this topic,” he said. Skelly said the “argument isn’t tight as in years past” that consumers should be willing to bear some risk as it was during and after World War II, for instance.
“In any event, we know we’re going to need a lot more grid,” Skelly said. He said the grid of tomorrow will be built in “fits and starts” and spring up organically as it has for decades, not from any centralized plans.
Finally, Skelly appealed to companies to consider hiring recently purged Department of Energy employees.
“There really is a great pool of talent in the Grid Deployment Office, so keep an eye out for them on LinkedIn,” he said.
Others treated data center load growth as more concrete and lasting.
“It’s a staggering amount of power being asked from the grid,” said Phillip Sandino, a senior vice president at Tract Capital Management, a firm specializing in master planning data center locations.
Sandino said complicating matters, local governments and regulators are becoming more antagonistic to ever-larger data center campuses.
“You all know that, because it’s not like they’re throwing rose petals in front of you to develop,” Sandino addressed the generation and transmission developers in the crowd.
“The growth we’re seeing is beyond anything I’ve seen in my career… I can’t overstate how big a deal this is,” Entergy Louisiana CEO Phillip May said. He likened today’s levels of load growth to the 1940s and 1950s when the U.S. economy swapped war production with post-war consumerism and housing. However, May said he and his team are careful not to accept new customers that ultimately will burden ratepayers.
Silicon Ranch Vice President of Interconnection and Policy Myra Sinnott said hyperscalers, regulators, utilities and grid operators should “open the channels of communication” where they can so everyone has a better understanding of what’s to come.
“A lot of these large load developers are desperate for power,” Sinnott said. She said grid operators and utilities should find creative ways to work faster within the confines of existing rules.
Meta Energy Manager Paul Kelly said when Meta is looking for a site, it’s looking for a utility that conveys confidence and can move fast to serve new load.
Amazon Manager of Energy Policy Ray Fakhoury said siting data facilities has shifted recently from tech companies selecting locations to letting power providers direct them to appropriate locations. He said Amazon has a preference to be in front of the meter.
Chris Matos, of Google’s energy market development division, conceded that data centers need non-interruptible sources, a challenge as the industry struggles to add accredited capacity.
“The buzzword is AI, but these data centers are cloud computing for the most part,” Matos said, adding that when data centers are interrupted, essential services like hospital records and financial markets are endangered.
MISO Executive Director of Markets Innovation and Strategy Zak Joundi said exploding data center demand doesn’t change MISO’s playbook for handling the energy transition. But, he said, it does have MISO doubling down on some of its recent projects, including a new availability-based generation accreditation, an expedited lane in its interconnection queue and more visibility into its risk profile. He said MISO already was modeling and preparing for a complex system with the energy transition before large loads began lining up to connect.
“You have a velocity aspect, you have a magnitude aspect added to the equation,” Joundi said. “But there is no indication we have big gaps.”
SPP Director of System and Resource Planning Natasha Henderson said SPP’s planned expedited queue lane and its provisional load study process — where the RTO forecasts future demand to plan grid upgrades — should help SPP better respond to load growth.
“We need to continue to add tools, add processes,” she said of the path ahead.
Henderson also said there’s no question SPP will need long-duration storage to navigate windless and cloudy periods.
“You can look at CAISO and where they’re going and where they’ve been,” she said.
Interregional Tx as Insurance
Liz Salerno, a principal at consulting firm GQS New Energy Strategies, said the time is right for FERC to make an interregional planning rule. She said expanded transfer capability is an insurance policy against system collapse, though she acknowledged that cost allocation between regions will be a rocky endeavor at best.
Salerno said the good planning FERC’s Order 1920 prescribes will prevent the industry from playing “Whac-A-Mole” with reliability issues, and FERC should do the same on an interregional scale.
“One storm. One storm pays for itself,” she said. “All the dominos are lined up for FERC to act on this.”
MISO’s Laura Rauch agreed on the insurance characterization of interregional projects but said it’s a challenge to get separate regions to agree on a risk tolerance for interregional projects “without resorting to the bare minimum.” She said MISO’s interregional planning strives to land on “shared truths” between geographies even though “everyone’s crystal ball is cracked and cloudy.”
Karen Onaran, CEO of industrial trade association ELCON, said when FERC staff drafted Order 1920, they likely didn’t realize load growth was set to surge. She said the commission’s emphasis on 20-year planning makes even more sense as load additions pile up.
“We can no longer rely on historical numbers to plan the grid of the future,” Onaran said.
Onaran urged stakeholders to “lower their temperature” on cost allocation and not get so hung up on whether every last mile of line benefits their territories. She said interregional transmission planning doesn’t further one state’s sustainability goals at the expense of ratepayers in another state.
The language for the proposed California bill to implement “Step 2” of the West-Wide Governance Pathways Initiative became public late Feb. 20, revealing the conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent regional organization (RO) if lawmakers vote to approve the legislation.
Introduced by Sens. Josh Becker and Henry Stern, SB 540 — or the Pathways bill — seeks to amend sections of the California Public Utilities Code to enable California entities to join an energy marketplace governed by an independent RO. Ultimately, the RO would take over governance of CAISO’s Western energy markets to make CAISO markets more attractive for entities outside of California and allow stakeholders to tap into a broader market of electricity resources.
Before CAISO can hand over the reins, the bill requires the RO to fulfill 12 requirements. The bill’s text focuses on ensuring the RO’s independence and maintaining the authority of each state with a power entity in the market “to set its own procurement, environmental, reliability and other public interest policies.”
For example, the RO must engage with states, local power authorities and federal power marketing administrations before filing tariff changes with FERC. The RO’s governing board also must seek input from a body of state regulators “to receive the views of state regulators,” according to the bill.
The legislation also requires the RO to ensure public interest protections, including making funding available for a consumer advocate organization and maintaining an office of public participation.
The bill is the result of the Pathways Initiative, which aims to expand CAISO’s Western Energy Imbalance Market (WEIM) and the soon-to-be-implemented Extended Day-Ahead Market (EDAM) by shifting governance of the markets from the ISO to the proposed independent RO.
Previous efforts to expand markets in the West have failed, partly due to non-Californian entities expressing concerns about a market governed by CAISO, whose Board of Governors is appointed by the California governor. The Pathways bill strives to solve this issue.
Lincoln Davies, professor of law and executive director of energy, resource and environment programs at the University of Utah S.J. Quinney College of Law, told RTO Insider the bill “marks a monumental moment for California and all of the West.”
“It is an important departure from prior efforts, each of which failed,” Davies said. “Rather than islanding California from other states, the bill advances core Western values that were absent in past efforts — collaboration among stakeholders, respect for each state’s right to self-govern, and imagination and innovation. This new market would look different from any other market in the U.S., and that’s exactly how it should be. The West is unique. Its markets should be, too.”
The Northwest Energy Coalition (NWEC) said a West-wide energy market is the most efficient way to meet energy needs, ensure affordability and tackle extreme weather events.
“That is why we have committed so many resources to the Pathways Initiative to help create an independent regional organization to run the combined Extended Day-Ahead and Western Energy Imbalance Market,” NWEC stated. “This bill would pave the way for shared governance across all Western states in this region-wide energy market. We hope this bill passes quickly so that all utilities in the West join the EDAM energy market.”
The effort comes as the region prepares for the launch of EDAM and some entities already have committed to the market. But SPP’s Markets+ also has gained significant traction by positioning itself as offering independent governance from the get-go.
A study by The Brattle Group suggests California ratepayers could save $790 million a year under an EDAM that includes nearly every Western balancing authority except for Western Area Power Administration entities already engaged with SPP markets, Public Service Co. of Colorado (PSCo) and the Imperial Irrigation District.
But California likely would see significantly lower benefits than the top end — $182 million — in what will be the most likely outcome in the West — the “Split Market” case, where Markets+ consists of Powerex, the Bonneville Power Administration and most Washington utilities, NorthWestern Energy, PSCo, Arizona’s utilities and El Paso Electric, according to the Brattle study.
ERCOT staff Feb. 20 said they plan to gain permission from their Board of Directors to use 15 mobile generators as an alternative to relying on two 1960s-era gas units to resolve reliability needs in the San Antonio area.
Nathan Bigbee, ERCOT’s chief regulatory counsel, told the Texas Public Utility Commission that the generators, which are capable of a combined 480 MW of capacity, are more “cost effective” than extending reliability-must-run contracts with Braunig Units 1 and 2, owned by San Antonio’s municipal utility, CPS Energy. The aging units together have a maximum summer rating of 392 MW.
“Our calculation suggests there’s a 15% greater cost-benefit [ratio for] the [mobile] units over the Braunig units based on the fact that they have a shorter start-up time, a slightly better shift factor, and shorter up and down times. We see those as being a net reliability benefit for the grid,” Bigbee told commissioners.
The generators in question, along with several smaller ones, were leased from LifeCycle Power in 2021 by Houston’s CenterPoint Energy for $800 million. However, the larger units have sat unused, despite outages after Hurricane Beryl that lasted more than a week.
The board is holding a special meeting Feb. 25 to consider the mobile generators’ use and a preliminary exit strategy. (See “Staff Still Looking at Braunig,” ERCOT Board of Directors Briefs: Feb. 3-4, 2025.)
Bigbee said CenterPoint has agreed to make the generators available for ERCOT’s use. The grid operator will not compensate CenterPoint but will cover LifeCycle’s costs to move the generators to San Antonio.
LifeCycle has estimated it will cost $26 million to move the generators, while CPS has projected costs of $27 million to connect them to substations. ERCOT says the cost estimates are subject to change.
The latest estimate from CPS to prepare Braunig Units 1 and 2 for continued operation is $54 million. It projects all-in costs, which include an incentive factor and fuel expenses, will run $60 million.
Bigbee said the generators are a “lower-risk solution” compared to extending RMRs for Units 1 and 2. The units would need to go through an inspection before continuing operations. That could reveal additional repairs that need to be made, he said.
“There’s a lot of cost upside risk there that we would have to deal with and potential outage delay risk that could further exacerbate the reliability issues, and so, we see the LifeCycle option as being a win-win in that respect,” Bigbee said.
The municipality told the grid operator in 2024 that it planned to retire the Braunig units in March 2025. However, ERCOT said the plant’s units were needed to address transmission constraints and congestion in the San Antonio area until several transmission projects can be completed. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
ERCOT has extended an RMR contract through 2027 to CPS for Braunig Unit 3, which has a 412-MW summer rating.
The grid operator also is working with CPS, AEP Texas and South Texas Electric Cooperative on accelerating the transmission projects south of San Antonio intended to resolve the region’s congestion issues. A rebuild of a second 345-kV circuit is scheduled to be completed in May 2029, but Bigbee said preliminary discussions have indicated the work could be pushed up to January 2027.
“That could resolve some significant reliability issues in the future,” he said. “The earlier we can get those lines in service, the better we believe that the cost-benefit analysis will show that that’s easily a cost-beneficial move.”
California state lawmakers on Feb. 20 introduced a much-anticipated bill to implement “Step 2” of the West-Wide Governance Pathways Initiative, marking a significant step toward the creation of a new independent “regional organization” (RO) to oversee governance of CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.
California Democratic Sens. Henry Stern and Josh Becker introduced SB 540, also known as the Pathways Initiative, saying in a news release that the bill “establishes an innovative framework for regional energy cooperation while preserving California’s authority over key aspects of its electricity system and climate goals.”
The bill language will become public Feb. 21.
“As we move toward achieving California’s 100% clean energy goals, we must look at all possible solutions to reduce costs, improve reliability and cut emissions,” Becker said in the news release. “Pathways strikes that balance by unlocking the benefits of a regional energy market while safeguarding California’s critical public policy priorities. It offers a win-win scenario for California — achieving cleaner energy, more reliable power and real savings for ratepayers.”
The Pathways bill would allow CAISO and California utilities to enter energy markets governed by a new RO if the RO meets certain criteria. CAISO would maintain its role as a California-governed balancing authority “so that California and CAISO retain control over procurement, environmental, reliability and other public policies,” according to a fact sheet.
The bill aims to expand CAISO’s Western energy markets and allow stakeholders to tap into a wider market of electricity resources while ensuring California does not have influence over participating states’ public policies. It strives to solve governance issues that have hampered similar market initiatives in the past.
“SB 540 will ensure that we reach our climate goals in the most cost effective and reliable manner possible by tapping into a much wider set of Western resources — lowering energy bills, improving grid reliability and reducing pollution in front-line communities, while also retaining control of our procurement, environmental, reliability and other public policies,” the fact sheet stated.
The Pathways news release included comments from several backers of the bill who expressed their support.
“Enhanced coordination among Western states will bring benefits to Californians and increase the amount of clean, affordable electricity for the region,” Victoria Rome, California government affairs director at the Natural Resources Defense Council, said. “SB 540 takes the next important step toward a more resilient and reliable clean energy future for all westerners.”
Leah Rubin Shen, managing director for the West at Advanced Energy United, said in a separate statement that the bill “lays out a forward-thinking strategy for regional energy collaboration that will help contain costs for California ratepayers while keeping the lights on. The Pathways Launch Committee has worked hard to ensure that all stakeholders have a seat at the table, state interests are preserved, and the reliability and cost-saving benefits of sharing resources across the West can be fully leveraged.”
