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 can also 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 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 must also 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 have already committed to the market. But SPP’s Markets+ has also 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 last year that it planned to retire the Braunig units this March. 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 already extended an RMR contract through 2027 to CPS for Braunig Unit 3, which has a 412-MW summer rating.
The grid operator is also 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.”
FERC on Feb. 20 denied without prejudice LS Power’s two petitions to recover costs in case it must abandon development of a 285-mile transmission line designed to deliver Idaho wind power to California, saying the developer failed to adequately show the project’s benefits.
The commission’s order covers the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV line being developed by LS Power subsidiary Great Basin Transmission at an estimated cost of $1 billion.
In July, Great Basin petitioned FERC for authorization to recover 100% of the costs if the project is abandoned due to events beyond its control. The developer also asked for an order allowing it to create a regulatory asset to defer recovery of pre-commercial costs “in which it will book costs for the project, incurred to date and going forward, that cannot be capitalized and would otherwise be expensed,” according to the FERC order.
However, the commission denied the request for declaratory order, finding Great Basin failed to meet the necessary criteria under FERC Order 679, which requires transmission incentive applicants to demonstrate that a project will ensure reliability or reduce costs associated with transmission congestion.
“We find that, based on the record in this proceeding, Great Basin has not demonstrated that the project qualifies for the rebuttable presumption at this time because the project cannot be said to have ‘result[ed] from a fair and open regional planning process that considers and evaluates projects for reliability and/or congestion,”’ the order stated.
FERC approved a development agreement for the line between CAISO and LS Power on Jan. 21. The project, which will be jointly funded by CAISO and Idaho Power, will span northern Nevada and southern Idaho and link up with NV Energy’s One Nevada (ON) line to the south, providing 2,070 MW of transfer capacity southbound and 1,920 MW northbound. (See FERC Approves CAISO’s SWIP-North Development Agreement.)
Great Basin argued in its petition that it qualifies for the incentives under Order 679 because CAISO properly evaluated the benefits of the project in the ISO’s 2022/23 transmission planning process and the subsequent 2022/23 transmission plan.
FERC disagreed, saying that although CAISO discussed “potential benefits” of SWIP-North, the ISO did not “make any definitive findings and instead only recommended continuing its initial assessments,” according to the order.
“[T]here is insufficient basis in the record to demonstrate that CAISO fully considered and evaluated Great Basin’s Project for reliability and/or congestion relief through a fair and open regional transmission planning process leading to any of those conditional approvals,” FERC stated.
The commission denied the request without prejudice, giving Great Basin another chance to demonstrate the project fulfills FERC’s requirements for transmission incentives.
CAISO has agreed to fund about 77% of the project, equal to Great Basin’s ownership share, in exchange for operational control of the company’s entitlements on the line, which will equate to 1,117.5 MW of southbound capacity and 1,072.5 MW of northbound capacity, with the balance in both directions being allocated to NV Energy. (See CAISO Board Approves Moving Forward with SWIP-N Tx Line.)
In addition to facilitating transfers into California, the line offers Idaho wind power resources access to wholesale electricity markets in the Desert Southwest through the Desert Link line connected to the southern end of the ON line.
CAISO’s Board of Governors approved the development agreement during an October 2024 meeting despite opposition from some Idaho residents concerned about the path of the line.
In its filing with FERC, CAISO said it needed to pursue SWIP-North to support the California Public Utilities Commission’s resource planning portfolio calling for California load-serving entities to procure 1,000 MW of wind generation from Idaho. The ISO noted the proposed line is the only active project that would help fulfill that objective, making it the most timely and cost-effective option. The project is expected to commence operation in 2028.
Two top Bonneville Power Administration executives — including COO Joel Cook — are among the approximately 200 agency staff who accepted the Trump administration’s “deferred resignation” offer made to the entire federal workforce last month, BPA confirmed to RTO Insider Feb. 20.
The resignations of Cook and Senior Vice President of Transmission Richard Shaheen are the latest in a series of unsettling developments at the federal power agency and — now — its sister agency in Northwest hydroelectric dam operations, the U.S. Army Corps of Engineers (USACE).
BPA is responsible for operating about 75% of the transmission in the Northwest and marketing output from the region’s extensive network of federally owned hydro projects, most of which are managed and maintained by USACE.
During a quarterly business review call Feb. 13, BPA Administrator John Hairston said about 200 agency employees — or 6% of the workforce — had accepted the administration’s buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20. (See BPA Committed to Trump’s Energy Goals, Hairston Says.)
Scott Simms, executive director of the Public Power Council, told RTO Insider that he estimates BPA faces a loss of about 400 staff, which includes resignations and the firing of “probationary” employees. (Under federal hiring rules, “probationary” status applies to both recent hires and those who have transferred into new positions within the past year, including those receiving a promotion.)
But Simms also pointed to a parallel development at USACE, which some industry stakeholders thought might be protected from Trump’s cutbacks because of its association with the military. He said “multiple informed sources” have told him the agency has about 2,000 probationary employees nationwide, including 500 to 600 workers in the Northwest who hold jobs that require extensive technical training — such as dam operator.
“We’re still gathering data,” Simms said.
Impact Uncertain
BPA could not confirm a timeline for the departure of the two executives or of other staffers who accepted the resignation offer. The departures come just weeks before the agency is expected to release a draft decision on whether to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market.
Cook was appointed COO in April 2021 after having served as BPA’s senior vice president of power services since 2017. Cook previously held executive and management roles at Talen Energy, PPL EnergyPlus and Montana Power, according to his LinkedIn profile.
“As the head of power services, Joel has been on the front lines of our cost-control efforts,” Hairston said in a statement announcing Cook’s appointment in 2021. “His leadership and experience will serve the agency and our utility customers well as we explore new energy markets and look for opportunities to maximize the value of the federal power and transmission systems.”
Shaheen has served in his current role since 2014, after joining BPA in 2013 as vice president of engineering and technical services. According to his LinkedIn profile, he previously worked in various positions at Florida Power and Light for 25 years.
Shaheen has overseen BPA’s increasingly overburdened transmission planning processes, with the agency now confronting more than 65 GW in transmission service requests, up from 5.9 GW in 2021. He recently told stakeholders the agency had to pause certain planning processes because they had been “crippled” by the volume of interconnection requests. (See BPA Halts Some Tx Planning Processes Amid Surge of Service Requests.)
Shaheen also has managed BPA’s Evolving Grid Project, which the agency launched in April 2023 to address Oregon and Washington clean energy targets, renewable resource additions and the increased electrification of transportation, industry and buildings — as well as the growing need to harden the grid in the face of extreme weather events. (See Stakeholders Seek More Details on BPA’s ‘Evolving Grid’ Projects.)
In a letter dated Feb. 14, Oregon’s Democratic U.S. Sens. Jeff Merkley and Ron Wyden warned President Donald Trump that moves by his unofficial Department of Government Efficiency, led by billionaire Elon Musk, could result in the “imminent departure” of 20% of BPA’s workforce. The senators said the development poses “a direct and immediate threat to the reliability of the electrical grid that serves millions of American families and businesses” in the Northwest. (See Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA.)
FERC voted unanimously at its open meeting Feb. 20 to launch a review of data center co-location issues in PJM that will look into whether the RTO’s tariff needs to be revised to ensure grid reliability and fair costs to customers (EL25-49, AD24-11).
The commission’s order focuses on PJM because it has seen a larger number of proceedings on the issue, as it is home to the largest data center market in the world and a large number of nuclear power plants interested in such contracts.
“Co-location arrangements are a fairly new phenomenon that entail huge ramifications for grid reliability and consumer costs,” FERC Chair Mark Christie said in a statement. “Given these ramifications, the commission truly needs to ‘get it right’ when it comes to evaluating co-location issues.”
FERC gave PJM and its transmission owners just 30 days to determine whether the RTO’s tariff needs updates to accommodate co-location arrangements. The commission found the tariff may be unjust or unreasonable because it does not have such rules.
The commission is taking comments on the broader issues, and it will incorporate the record from the technical conference and related complaints. Parties have 30 days to file comments and another 30 to file replies.
Without a common understanding of entities’ responsibilities, FERC is concerned that the arrangements could be developed in a way that is not fair for other customers.
“We are especially concerned that the absence of tariff provisions creates the potential that participants in a co-location arrangement may not be required to pay for wholesale services that they receive,” FERC said.
The issues with co-location fall under both FERC and state jurisdiction, with the commission having to ensure that rates for the wholesale sale of transmission of electricity, as well as practices directly affecting such sales, are just and reasonable and not unduly discriminatory or preferential. States have the oversight of retail sales not in interstate commerce, as well as facilities used for the generation and distribution of electricity.
“The boundaries between federal and state jurisdiction are not hermetically sealed,” FERC said. “The application of these principles to the issue of co-location will often depend heavily on the specific facts and circumstances presented in particular situations.”
With co-location, some basic principles on that split will apply across all the contracts. States will keep exclusive jurisdiction over retail sales, which means they decide which entities are legally permitted to provide electricity to retail customers and how the costs of providing wholesale power are recovered from retail customers.
FERC has exclusive authority over the rates, terms and conditions for the sales from generating resources used to serve co-located loads, as well as practices directly affecting such sales. FERC also has jurisdiction over any transmission service used to serve co-location arrangements.
The commission seeks comments on jurisdictional issues, including when large loads are interconnected to the transmission system in interstate commerce and what evidence FERC should use to determine that.
Another issue FERC wants commenters to address is how such co-location arrangements have raised concerns around reliability and resource adequacy. NERC testified that 1,550 MW of voltage-sensitive load (data centers) disconnected from the system in a recent fault.
If the co-location arrangements proliferate, it could have major impacts on PJM’s grid, which was often designed around nuclear plants, as the RTO’s Independent Market Monitor testified. Taking the capacity out of the markets could also cause prices to spike for other customers, as the IMM and the Illinois Attorney General’s Office testified.
“That being said, we recognize, as does PJM, that these concerns are not necessarily unique to co-location arrangements and that significant load growth more generally may raise many of the same concerns,” FERC said.
Exelon Co-location Tariff Rejected
In a related order, FERC rejected a series of filings made by Exelon’s utilities, all PJM members, that tried to set up rules for any co-locations in its territory (ER24-2888, et al.). Exelon in 2022 spun off Constellation Energy, which now owns the largest nuclear fleet in the country, but most of that is connected to transmission lines the original company owns.
FERC found that the tariff revisions fall outside any individual utility’s tariff because they impermissibly alter the definition of load in PJM’s tariff.
The order drew a concurrence from Commissioner Willie Phillips, who as chair voted to approve the Susquehanna proposal. The majority in that order had not wanted to set policy by precedent, but Phillips felt that approval would not have limited FERC’s flexibility going forward.
This time, while he sided with the majority to reject Exelon’s filings, he noted that they raise real issues, including ensuring that co-located loads pay their fair share of costs, but they will be examined in the rulemaking proceeding, he noted.
A bipartisan consensus has emerged that data centers and the artificial intelligence applications they enable are national interest resources with profound implications for both national security and economic growth, Phillips said.
“I believe that this commission, in cooperation with our federal, state and local partners, should take all reasonable steps within our authority to support their development,” he added. “I view today’s orders as a down payment on this important national investment.”
Speaking during Southern Co.’s quarterly earnings call Feb. 20, CEO Chris Womack called 2024 “an outstanding year … both operationally and financially” that left the company “incredibly well positioned” to maintain reliable service for its customers.
The company reported net income of $534 million ($0.49/share) in the fourth quarter of 2024 and full-year net income of $4.4 billion ($4.02/share). This represents a drop from the $855 million reported in the final quarter of 2023, but a significant rise in terms of full-year net income from 2023, when the company reported $4 billion.
Operating revenue for the fourth quarter came to $6.3 billion, up from $6 billion for the same period the year before. For the full year, operating revenue grew from $25.3 billion in 2023 to $26.7 billion for 2024.
The primary drivers of the year-over-year growth came from the performance of the company’s electric utilities, with Southern noting that retail electricity sales grew 1% — although this figure was adjusted to account for the impact of Hurricane Helene in September 2024.
The company added 57,000 residential customers in 2024, the highest annual addition on record and more than a quarter of the 200,000 added in the region since 2020. Despite the growth in customers, residential electricity sales fell over the 12-month period by 0.5%; the difference was made up, however, by growth on the commercial and industrial side, with sales in each category rising by 2.2% and 0.7% respectively.
The commercial sales growth was supported by continuing rising demand by data centers and other large loads, with data center electric usage up 17% over the prior year. This represents a continued trend: Southern’s leaders reported strong growth among data center customers in the first quarter of 2024. (See Southern Credits Strong Southeast Economy for Earnings Growth.)
“Our objective is to serve as much of this growing electric load as we can sustainably serve,” Womack said. “The vertically integrated, state-regulated service territories that we are privileged to serve are proving well suited to attracting these large-load customers, and thanks to integrated resource plans and the other orderly processes inherent in our regulated frameworks, our market is also perhaps proven to be better suited than the unregulated markets at effectively deploying new resources to serve them.”
CFO Dan Tucker said Southern expected “strong fundamentals … to support our long-term growth,” setting adjusted EPS guidance for 2025 of between $4.20 and $4.30. At the same time, he acknowledged that the likelihood of higher interest rates could “be a partially offsetting factor.”
Tucker and Womack also highlighted the company’s plans to invest $63 billion in its businesses over the next four years; $50.3 billion of this figure is slated for the company’s regulated electric utilities, with $9.2 billion aimed at the regulated gas utilities and $3.3 billion for interstate gas pipelines, solar construction and maintenance on existing assets.
