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November 9, 2024

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PJM Seeking Expedited Approval of Energy Efficiency Changes

VALLEY FORGE, Pa. — PJM presented the Markets and Reliability Committee with an expedited proposal to revise how it measures and verifies the capacity contribution of energy efficiency (EE) resources, drawing alarm bells from market participants that the RTO is moving too fast and making changes outside the stakeholder process. 

The proposed changes shown during the Feb. 22 MRC meeting would focus on how a baseline estimate of energy consumption is determined to measure the load reduction provided by an EE installation. It would require that the providers use the most recent relevant Technical Reference Manual (TRM) published within the past three years when conducting studies of current baseline load or use meter data if standards are not available or applicable. It also would have to be demonstratable that the project was initiated with the goal of wholesale market participation and the equipment being replaced was fully operational and would have continued to be in use. 

EE providers also would be required to demonstrate that the installation of the more efficient technology was completed and that they had exclusive rights with end users to enter the installation into the capacity market to prevent double counting. 

Pete Langbein, PJM’s manager of demand side response operations, said staff saw value in seeking improvements to the EE measurement and verification processes prior to the next Base Residual Auction, scheduled for June 2024. The proposal was brought under an issue charge at the Market Implementation Committee to broadly look at EE participation in the capacity market and consider if any changes are needed ahead of the next auction. (See “Stakeholders Begin Review of Energy Efficiency Resources,” PJM MIC Briefs: Dec. 6, 2023.) 

Equipment replacements that go beyond the standards outlined in TRMs would continue to qualify as EE, but the amount of compensation they receive might change under the proposal, Langbein said. 

Several stakeholders argued PJM is bypassing the stakeholder process by introducing a proposal at the MRC without first going through the typical package formation and endorsement process at the MIC. PJM first presented the changes during a Feb. 21 MIC special session. 

Luke Fishback, of Affirmed Energy, said the MIC issue charge was brought in part to ensure the definition of EE resources in the manuals reflects tariff language, an effort he does not believe would be advanced by PJM’s proposal. He argued the redlines are hasty and would introduce conflicts between the manuals and governing documents. 

Requiring EE providers to enter into contracts with each end user to guarantee that installations are participating in only one program would add a substantial barrier to participation, Fishback said. He agreed with PJM that it’s critical that double counting be prevented, but he said more stakeholder deliberation is needed to find a workable solution, particularly given how little time there is because contracts need to be finalized ahead of the next capacity auction. 

Several market participants and state regulators, plus Independent Market Monitor Joseph Bowring, argued the language requiring that installations be dependent on capacity market revenues is unverifiable and questioned what evidence PJM would find acceptable. 

Angela Fox, Affirmed Energy’s chief markets officer, said requiring end-use customer information could conflict with privacy laws and obstruct program participation. 

Exelon Director of RTO Relations Alex Stern said it’s important that states be informed of the changes being recommended and how they may impact any EE programs in their states. State-sponsored programs may find they are no longer eligible for capacity market revenues, which may impact the ability to continue to offer EE benefits to low-income consumers if those programs use wholesale market revenues to offset the cost to taxpayers. 

Asim Haque, PJM senior vice president of governmental and member services, said staff are scheduling a briefing with the states to discuss the changes. 

Without a full stakeholder process during the formation of the proposal, CPower Senior Vice President of Regulatory and Government Affairs Ken Schisler said the changes have not been vetted by members and they are not addressing a problem that has previously been articulated. He presented a proposal built off PJM’s redlines which he argued would resolve many of the issues stakeholders identified with the changes. 

The CPower proposal would eliminate the requirement that projects be tied to capacity market participation, the end-use consumer data collection language and the three-year requirement for TRMs — instead using the most recent manual. 

Highlighting the challenges with PJM’s proposal, Schisler gave the example of an EE project to replace insulation in the home of an individual with a respiratory illness. He argued the dual benefits of reducing electric heating load paired with reducing health risks that may be present could make it difficult to show the causal link between the project and capacity market revenues that PJM’s language would require. 

He also stated many of the TRMs in use would be deemed ineligible due to the age of their last update, which would constrain the ability to administer EE programs in many states under PJM’s proposal. 

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SPP Markets+ Stakeholders Prep Tariff for Approval

Potential participants in SPP’s Markets+ day-ahead offering endorsed another batch of tariff revisions in preparation for a March filing at FERC. 

During a Markets+ Participants Executive Committee meeting Feb. 20, stakeholders approved dozens of pages of revisions related to market monitoring, state greenhouse gas emission programs and transmission usage. Assuming the entire tariff package is approved in March by the Markets+ independent panel of SPP directors and the RTO’s board, it will be submitted to FERC. 

MPEC Vice Chair Brian Cole, with Arizona Public Service, praised the “amazing effort” by all involved in the tariff’s development, which began in August 2022. “To get to where we are is amazing. I know we’ve got a long way to go, but to get to a tariff filing is really great,” he said. 

The various revisions were approved unanimously against some abstentions. However, a motion to endorse the updated tariff as approved by MPEC and move it to the governing process’ next step for filing at FERC drew four no votes from Western Resources Advocates, the Natural Resources Defense Council, the Sierra Club and the NW Energy Coalition. 

“It’s not us saying we do not believe in Markets+,” said Kylah McNabb, speaking for the NRDC. “It’s a product that should go forward. It just needs more work before filing at FERC.” 

“Procedurally, we need this vote to move it forward to [the Interim Markets+ Independent Panel],” SPP’s Carrie Simpson, director of western services development, said. “We’ve got the pieces. This is the full package. We need endorsement to get to IMIP.” 

“The tariff is notably incomplete. More time is needed,” agreed WRA’s Vijay Satyal, deputy director of regional markets. 

McNabb pointed to MPEC’s discussion over the remaining tariff revisions to the greenhouse gas (GHG) market’s design. PowerEx’s Mark Holman suggested language assigning resources to load was “watered down” and asked to strengthen an action item directing the Markets+ Development Working Group (MDWG) and SPP staff to evaluate tools for monitoring and tracking GHG programs. 

“We’d like to strengthen it if other participants are supportive because we feel there needs to be a strong push coming out of this phase to develop the ability to attribute resources to load and have the comprehensive reporting that I think ourselves and others have envisioned,” Holman said. 

MPEC approved the action item and revisions related to the assignment of resources to load and GHG market design settlements.  

SPP staff is surveying Markets+ participants on WRA’s suggestion for an external market monitoring consultant over a three-year period before and after the market’s deployment and to gauge their appetite for a hybrid market monitoring option that could cost an additional $2.5 million. The advocacy group pointed to tariff language that would expand the monitoring structure to include an external adviser to SPP’s Market Monitoring Unit, given the market’s new design approach. 

WRA has suggested the developmental phase of the market should include guidance on “areas of focus” by the external consultant. Satyal used a seams and joint operating agreement with CAISO’s Extended Day-Ahead Market (EDAM) as a relevant example. 

“The WRA simply feels this is an insurance policy,” he said. 

The IMIP meets virtually March 1. It will take up the tariff package and hear any appeals. Assuming IMIP’s approval, the tariff will be considered by the board during a March 25 conference call. 

SPP is hoping for FERC approval in October or November and work to begin on Markets+’s implementation early in 2025. That would put the RTO a year behind CAISO’s EDAM, the other competing market offering in the West. The commission approved the EDAM filing in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.) 

Under SPP’s current timeline, shortened by three months, Markets+ would go live before summer 2027. 

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Québec, New England See Shifting Role for Canadian Hydropower

With the days of endless cheap hydropower in Québec coming to an end, and the Northeastern U.S. hoping to rapidly scale up intermittent renewables, the two regions may be forced to fundamentally reconsider the role of hydropower on the grid. 

Power has historically flowed south, and just a decade ago, government-owned corporation Hydro-Québec actively sought two contracts to send large quantities of power to the U.S. It eventually reached deals with Massachusetts and New York that led to a pair of major new transmission projects: the 1,200-MW New England Clean Energy Connect (NECEC) and the 1,250-MW Champlain Hudson Power Express (CHPE). 

NECEC and CHPE are aiming to be in service by 2025 and 2026, respectively, and are tied to long-term supply contracts that will ensure that baseload power will flow from Québec to the Northeast well into the 2040s. 

At the same time, increasing power demand in Québec has forced Hydro-Québec to re-evaluate the role of hydropower going forward while spurring concerns in the U.S. that it will not have enough power to fulfill the contracts. 

While Hydro-Québec has maintained that it will be able to meet the NECEC and CHPE contracts, the corporation acknowledges that a paradigm shift is on the horizon for its hydro fleet. 

“When you look forward, we don’t have more surpluses that we could do another two [contracts] tomorrow — not like that, not in that same fashion,” Serge Abergel, COO of Hydro-Québec’s U.S. operations, told RTO Insider. 

Instead, the company is eyeing a long-term change in the role hydropower plays on the grid, transitioning from baseload to a long-duration storage resource that can help balance and firm up the growing amount of wind and solar resources. 

“We’re at a point in time where the traditional way of how we’ve been doing things in the past — sending [from] north to south large blocks of energy 24/7 — is completely changing,” Abergel said. The proliferation of intermittent renewables “will create a very strong need for a balancing resource, and that’s where our hydropower will be able to play a different role.” 

Enough Energy, or Enough Capacity?

In 2021, a group of MIT-affiliated researchers published a study modeling the optimal configuration of a high-renewables grid in 2050, aimed at better understanding the role of large Canadian hydro resources. 

The researchers initially expected to find hydropower to be “this very flexible baseload resource, something like nuclear, but even more flexible,” co-author Emil Dimanchev told RTO Insider. 

“But what we found from our modeling was something very different,” Dimanchev said; “specifically, the fact that if the system was operated optimally, the best thing to do would be to do a two-way trading of electricity,” with Canadian hydro operating “more as a battery rather than this flexible source of energy.” 

The modeling found that increasing the transmission capacity between Québec and New England would help expedite the decarbonization of the power sector while reducing the need to overbuild intermittent renewables. The analysis also found that Québec did not need to add any hydropower for it to play a substantial balancing role, noting that investments in new hydro plants “are deemed uneconomical by our model” compared to investments in new wind and solar. 

“Québec already has this huge battery, so intermittency is not a problem,” Dimanchev said. New wind and solar resources “can be immediately firmed up with existing hydro.” 

To prevent short-term power supply issues, Hydro-Québec is planning to spend $90 billion to $110 billion CAD by 2035 to increase its generating capacity by 8,000 to 9,000 MW, largely through new wind resources, demand reductions, upgrades to existing hydro generators and new hydro facilities. 

The study’s findings also speak to more recent questions of whether Québec has enough power to justify additional transmission projects, Dimanchev said. 

“The question that people are raising now is, ‘Is there enough energy to serve all the contracts and new transmission lines?’” Dimanchev said. “Well, that might be a problem in the short term, but what our study shows is that in the long term, we should think of this resource as a battery, so the question is not so much, is there enough energy, but is there enough transmission capacity to use that battery?” 

The potential of Canadian hydropower as a long-duration storage resource is the basis for another potential transmission line, the Twin States Clean Energy Link, a proposed 1,200-MW two-way connection between New England and Québec. 

Aiming to come online in the early 2030s, the National Grid-led project touts its potential “to balance New England’s renewable resources during times of peak demand, while also sending surplus renewable power generated in New England — such as offshore wind — to Québec when it’s not needed.” 

The project has already received a vote of confidence from the U.S. government: In September, the Department of Energy committed to purchasing a significant portion of the line’s capacity to minimize the project’s overall development risk. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) 

South-of-the-border Constraints

Although added transmission capacity between Québec and New England could help unlock the balancing potential of hydropower, the benefits are largely contingent on reaching a high level of surplus renewables. 

“This doesn’t apply today because we are just in the early stages of this deployment of intermittent renewables,” Hydro-Québec’s Abergel said. However, by 2035, “we believe there’ll be sufficient intermittent resources in the Northeast to start having a viable concept.” 

Reaching a high level of renewable power in New England will require significant investments in local transmission infrastructure to interconnect new solar and wind resources, said Francis Pullaro, executive director of RENEW Northeast. 

“The biggest challenge of getting renewables or land-based wind built in Maine has always been the lack of adequate transmission,” Pullaro said, adding that southern New England also desperately needs transmission upgrades to interconnect large-scale offshore wind projects. 

Regarding the NECEC line, the baseload power it will send could end up undermining the development of wind and solar resources in Maine by using up headroom on the existing system and causing more frequent curtailments of renewables, Pullaro said. 

“If the states are going to be investing in new transmission, another line to Canada shouldn’t be the top priority,” Pullaro added. 

While the New England states have long struggled to reach an agreement on how to allocate costs for new forward-looking transmission projects within the region, Pullaro expressed measured hope about recent discussions among the states, ISO-NE and NEPOOL stakeholders over a new longer-term transmission development process. (See NEPOOL Nears a Vote on Order 2023 Compliance.) 

“I think there’s a lot riding on it,” Pullaro said, adding that for years, “we just haven’t been able to get the region to galvanize around internal transmission to benefit our clean energy buildout. And maybe we’ve finally arrived at the moment where this new process can help.” 

Long-term Contracts

While the contracts for NECEC and CHPE will run for 20 and 25 years, respectively, the need for significant additions of clean balancing resources could arise sooner, assuming the states can overcome significant hurdles related to internal transmission and the deployment of offshore wind. 

“In [the] short term, it might be helpful to have the baseload contract, but I think it’s worth raising the question of whether it can be renegotiated in 10 years, for example, to allow for two-way trading,” Dimanchev said. 

While the current contracts will keep the power flowing north-to-south, the NECEC and CHPE lines will be able to operate bidirectionally, although some system upgrades might be needed to facilitate south-to-north transmission. 

Operating the lines bidirectionally would also require new types of contracts or major changes to the existing contracts. 

“It will involve some way of ensuring that one region commits to selling onto the market when prices are at a certain point, whereas the other region [exports] when prices are below a certain point,” Abergel said. “Developing the business model for this new way of doing things is critical.” 

Abergel added that some regulatory changes may also be needed to enable more efficient two-way power flow, pointing to the “considerable” exit fees that apply to power sent from New England to Québec. 

“We have the contracts that we have right now; we’re committed to them; but when we look to the future, working back and forth with our partners and sending energy over the border when needed really is the wave of the future, and that’s what we’ll be working on,” Abergel said. 

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RTOs Jointly Call for Improved Gas-electric Coordination

The four RTOs released a white paper Feb. 21 calling for improvements to the coordination of the electric and natural gas systems to benefit customers of both. 

ISO-NE, MISO, PJM and SPP jointly produced the paper, which includes recommendations that could be tailored to regional specifics along with a few overarching issues that would benefit from national coordination. While the paper calls for additional changes, the RTOs noted that progress has been made, as the grid’s performance in winter storms this January was notably better than earlier events. 

“These more recent experiences underscore the value of better aligning both the purchase of commodity and delivery of natural gas,” the paper said. “If anything, these most recent positive experiences underscore the value of focusing on additional enhancements — building on the work of each of the regions — to better align these two industries. The initiatives suggested herein aim to enhance that coordination, ultimately benefiting customers in both systems through improved reliability and market efficiency.” 

The paper breaks up its recommendations into three broad buckets: gas market enhancements to improve supply and pricing options to ensure a reliable generation fleet as it rapidly evolves; operational enhancements aimed at specific needs; and regulatory coordination of state and federal authorities to address emergencies. 

The recommendations are aimed at different groups including state regulators, FERC, gas pipelines, gas marketers, generators, the ISO/RTOs, the North American Energy Standards Board, the Pipeline and Hazardous Materials Safety Administration, and state and federal lawmakers. 

The report calls for changes like increased transparency in secondary natural gas markets overseen by the states; enhancing weekend and holiday gas supply and liquidity (both from pipelines and any excess sold by local distribution companies); developing additional reserve products in the electricity markets; and addressing emergency authority to address shortfalls either through the Defense Production Act or new legislation. 

The RTOs also call for “targeted permitting reforms,” which have been a hot topic on Capitol Hill for more than a year. 

“However, permitting reforms for transmission versus pipelines are being considered in separate silos that largely ignore the interdependent nature of these two systems,” the paper said. “The electric industry and gas pipeline industry should coordinate so as to better educate policymakers on the interdependencies of these two systems and the need for permitting reform to address these co-dependencies in a comprehensive manner.” 

Targeted expansion of the pipeline system is needed for reliability, the paper said, but faces challenges because of environmental regulations, permitting complexities and local opposition to siting. 

“While the joint RTOs support targeted expansion of the pipeline system, we believe that in the interim, increased reliability of the electric system can be achieved from optimizing both the operation of the existing infrastructure and the liquidity of gas markets,” the paper said. 

Much of the coordination with the gas industry involves working with pipelines; their main trade group, the Interstate Natural Gas Association of America, said it was still reviewing the RTO’s proposal and could not offer specific comments. 

“However, natural gas has a critical role in ensuring electric reliability, and INGAA is committed to working with end users, including [local distribution companies] and electric generation customers, to ensure they have the natural gas they need to keep American homes and businesses running, especially during winter storms,” CEO Amy Andryszak said. 

INGAA worked with the Natural Gas Supply Association and the Electric Power Supply Association to craft recommendations to improve coordination of the two industries that were filed before FERC’s technical conference on reliability last year. (See FERC Conference Highlights Challenges of Evolving Grid.) 

Making the gas system more flexible is important to getting more renewables onto the grid, and the RTOs’ suggestions can help that happen, Michael Jacobs, senior energy analyst with the Union of Concerned Scientists, said in an interview. Renewables will make more and more of the generation stack, but natural gas will still be needed to help balance that, absent advancements in other technology. 

“That actually will require a lot of change in the way the gas pipelines and the gas generators do their business,” said Jacobs. “So, I picture a consolidation of gas pipelines, because we won’t need as many. They need to keep pressure in their system, so they need to have some level of utilization. And so, to do that with fewer pipelines can be more viable than doing it with the same number of pipelines we have.” 

He noted that the RTOs’ paper assigns specific policy changes to the entities that would need to make them, something that has not been done in earlier reports. 

“The four RTOs that put this together deserve some credit for saying those things and putting out an actionable document,” he added. “They still have work to do, but they clearly name other organizations that have work to do. And that’s the kind of thing that’s sort of been missing … this kind of public discussion about how to coordinate across these agencies and deal with the authorities that are needed.” 

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MISO, SPP to Conduct Interregional Study in 2024

MISO and SPP have agreed to conduct another coordinated system plan (CSP) study along their seam this year, as their joint operating agreement requires.  

Five previous studies have failed to produce a single interregional joint project over differences in how to allocate costs. The 2022 study focused on solutions that might qualify as targeted market efficiency projects (TMEPs), a construct MISO and PJM use on their seam. However, no projects met the criteria. (See MISO, SPP Fall Short in 5th Try for Interregional Projects.) 

The MISO-SPP joint operating agreement requires a CSP study at least every two years. 

During an Interregional Planning Stakeholder Advisory Committee meeting Feb. 22, several stakeholders offered suggestions on improving the CSP study process. 

“Even if problems are identified, cost allocation ends up disrupting the ability to actually progress to building projects that might address these issues,” Xcel Energy’s Madeleine Balchan said during the conference call. 

Xcel recommended that instead of looking at two different models and then trying to reach agreement with different sets of numbers, the grid operators look at the historical cost to the market of binding transmission lines along the seam. 

“Everybody can agree on the financial costs that have already happened,” Balchan said. 

“I never really could understand why we don’t hold up historical examples and try to figure out a way to learn from them,” North Dakota Public Service Commission analyst Adam Renfandt said. 

Natalie McIntire, representing the Sustainable FERC Project and Natural Resources Defense Council, urged the RTOs to use a more proactive, comprehensive interregional planning process with an agreed-upon single model and common benefit metrics. She called for employing scenario-based planning that addresses “credible ranges” of uncertain future conditions and a 15- to 20-year planning horizon, given the time it takes to develop multistate transmission. 

Missouri Public Service Commission economist Adam McKinnie drew support for his recommended focus in and around Southwest Missouri, home to numerous congestion issues. He suggested a three-way study among SPP, MISO and Associated Electric Cooperative Inc. The cooperative participates in the Southeastern Regional Transmission Planning process but conducts joint planning with SPP. 

“It seems like it would be beneficial if there was some way that we could get all three of those parties to study that area,” American Electric Power’s Jim Jacoby said. “It has had some severe problems that we’ve seen in past winter storms.” 

Ashleigh Moore, with MISO’s planning coordination and strategy team, said the two RTOs’ staffs will use the feedback to determine the CSP’s scope. Future IPSAC meetings will be scheduled to talk through the process. 

Separately, SPP on Feb. 22 filed a new revision request (RR620) to implement cost-allocation policies already approved by the RTO’s Regional State Committee for the Joint Targeted Interconnection Queue (JTIQ) project with MISO. The rule change would memorialize and define how the JTIQ would be deployed and applied once executed and is coordinated with changes to the JOA. 

SPP’s Clint Savoy said once RR620 is filed at FERC, staff will be able to work with MISO on TMEPs projects. 

Comments on RR620 are due by the close of business March 14. 

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Insurer: Majority of BESS Failures are in First Two Years

An insurer specializing in renewable energy infrastructure reports that battery energy storage system (BESS) failures are ramping up with the spread of the technology, and most often occur in new systems. 

It calls for developers and operators to take steps including creating spacing standards for units within a BESS, conducting comprehensive root cause analyses of failures, establishing a liability framework within the market and involving manufacturers through the entire project lifecycle. 

GCube issued the report, “Batteries Not Excluded: Getting the Insurance Market on Board with BESS,” on Feb. 21. CEO Fraser McLachlan said insurers experience uncertainties in supporting coverage for the rapidly expanding market.  

“GCube is a pioneer in the BESS field, and has learnt the hard way, having handled some of the largest losses in the market to date,” he said in the announcement of the report, which is designed to reduce market uncertainty. 

The report draws on details of 63 publicly reported failures. Among the findings: 

    • Systems rated at 5 to 50 MWh accounted for more than half of the failures and those rated at less than 5 MWh accounted for about a third. 
    • Solar-plus-storage installations accounted for 48% of reported failures; while this may be due to the frequency of such pairings, it also may point out challenges and risks created by pairing two complex systems. 
    • Nearly half the reported failures were in South Korea and nearly a third in the United States; this is likely due to the large number of systems in the two countries and the diligent reporting in both. 
    • Systems in their first year of operation accounted for 38% of recorded failures and 21% occurred within the second year. 

This last statistic is a red flag — GCube notes that the BESS failure rate within the initial operation phase is markedly higher than seen in other energy systems. 

“The high incidence of failures within the first two years of operation poses a serious cause for concern, warranting a closer examination of the potential ramifications if this trend continues,” the report warns. 

A report issued earlier in February flagged the same phenomenon from a different perspective: Engineering services firm Clean Energy Associates noted that 18% of its BESS factory quality control audits found issues with thermal management systems and 26% found faults with their fire detection and suppression systems. (See Engineering Firm Finds Quality Problems in BESS Manufacturing.) 

GCube said the risk as BESS systems get progressively larger is that failures will cause progressively larger damage, increasing the losses incurred by developers, operators and insurers. 

The 2012 fire at the First Wind/Xtreme Power wind-storage facility in Hawaii underwritten by GCube resulted in a $27 million loss, and that was only a 15-MW battery bank — a small fraction of the capacity of some of the BESS installations being planned and built. 

“We don’t want to repeat the mistakes of the past of allowing growth in deployment and technological scale to take priority over quality control, and the large-scale losses and market destabilization that result from that,” McLachlan said. 

Energy storage is a linchpin of the clean energy transition, and its rapid buildout reflects this. Batteries vastly outnumber other forms of storage. GCube expects that by the end of this year, BESS will account for as much as 30% of the asset value in its insured portfolio, which now exceeds 100 GW capacity. 

“Among the main challenges of BESS underwriting is the scarcity of data and insights on how BESS works, performs and fails,” McLachlan writes in the introduction to “Batteries Not Excluded.” 

“Consequently, underwriters continue to exercise caution when it comes to BESS technologies. While market data is limited, we must begin harnessing what information is presently available to start unravelling the risks and prospects associated with this nascent technology.” 

Beyond the financial and physical dangers of BESS failures, the sense of unknown danger stokes public opposition to installation of these facilities. (See Battery Storage Developers Bump Against Perception of Risk.)  

Jurisdictions such as New York state are moving to address the threat to public safety and perception by quantifying and reducing those risks as much as possible. (See NY Fire Code Updates Recommended for BESS Facilities.) 

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Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings

Executives focused on Entergy’s booming industrial load growth during a year-end earnings call Feb. 22.  

Entergy CEO Drew Marsh said that Entergy companies signed 61 new electric service agreements in 2023, representing 1.3 GW in capacity. 

“Data centers are a hot topic and, as you know, we’ve seen interest in our service area,” Marsh said, noting Amazon’s $10 billion arrival in Mississippi and Gov. Tate Reeves’ (R) signing bills in late January to authorize the data center investment along with $44 million in state incentives.  

Entergy has framed the Amazon Web Services data centers as a win for the state and touted its role in recruiting the company to the location. 

Marsh predicted “very strong growth” among Entergy companies going forward, due in part to new natural gas, blue hydrogen and EV battery production projects. 

“In addition to the data centers, our growth story continues to develop and diversity,” Marsh said, adding that Entergy has a “unique industrial growth opportunity in front of us.”  

Entergy’s load growth has been responsible in part for an unprecedented number of expedited project requests to MISO for transmission facilities. (See MISO to Re-examine Schedule for Reviewing Expedited Tx Projects.) 

Marsh said Entergy companies are pursuing loans and grants from the U.S. Department of Energy to offset the costs of much-needed grid upgrades. He said Entergy companies have applied for loans totaling $4.7 billion “for a variety of projects related to the clean energy transition” and have submitted eight preliminary proposals under DOE’s Grid Resilience and Innovation Partnership program. 

Entergy plans to invest $20 billion over the next three years to “make our fleet cleaner, to make our system more reliable and resilient,” Marsh said. That amount includes $11 billion in transmission construction, including big-ticket projects from MISO’s 2023 Transmission Expansion Plan. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.) It also includes $8 billion in new generation, including the more-than-$1 billion, 1.2-GW Orange County Power Station in southeast Texas and $2 billion for solar installations. 

Marsh said despite record-breaking heat last summer, Entergy achieved its lowest forced outage rate since 2011. 

“Not only did we meet our customers’ demands, but we also exported power to other utilities in MISO in the moments that mattered,” Marsh said. 

Marsh said Entergy’s year-end earnings of $1.4 billion ($6.77/share) signified “steady, predictable results.” Earnings over 2023 were slightly higher than 2022’s $1.3 billion ($6.42/share).  

Entergy CFO Kimberly Fontan said, “weather was a benefit for the year,” with an exceptionally hot summer boosting financial performance. 

Fontan said 2023’s retail sales volume was relatively flat overall, with industrial growth offset by a decline in residential and commercial demand. 

However, she said, industrial sales were not as “robust” as Entergy anticipated in the fourth quarter, although the utility remains optimistic about growth propelled by large industrial customers specializing in metals, gases and petrochemicals.  

“We continue to be confident in our industrial growth expectations, as sector margins and commodity spreads remain strong. And we continue to grow our backlog of signed electric service agreements,” she said.  

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SCE Sees Wildfire Risk Decline as Load Outlook Improves

Independent measures show Southern California Edison has sharply reduced its financial risk from catastrophic wildfires compared with pre-2018 levels, Pedro Pizarro, CEO of SCE parent Edison International, said during a Feb. 22 earnings call. 

The utility exceeded its own targets for hardening its system against fire risk last year when it installed 1,100 circuit miles of covered conductor across its distribution system, raising the total to 5,850 miles installed over the past five years.  

“We are proud of this progress, which, combined with enhanced vegetation management, asset inspections and other programs, has significantly reduced the need for public safety power shutoffs,” Pizarro said, referring to the fact that the physical measures have meant power shutoffs now account for just 10% of SCE’s fire avoidance, compared with 100% five years ago. 

On the heels of those developments, SCE last year showed an 85 to 88% reduction in its wildfire-related risks compared with pre-2018 levels based on an independent risk model managed by Moody’s RMS, he said. 

The utility in 2023 saw no fire ignitions due to the failure of covered conductor. Last year also marked the fifth straight year with no catastrophic wildfires in its service territory, according to a presentation shown during the call. 

The presentation also noted that SCE expects to have hardened 90% of its distribution lines in high-fire-threat areas (HFRAs) by the end of 2025, prompting one analyst on the call to ask whether the company is preparing to address new areas that emerge as high-risk in the future due to changing climate conditions. 

“Clearly, we continue to monitor how the landscape is changing,” Pizarro said. “We do that in partnership with fire agencies, with [California Office of Energy Infrastructure Safety], so to the extent that additional areas are designated HFRA, high-fire-risk areas, in the future, then we would make sure that we’re using the same standards that we use for high-fire-risk areas today.” 

Electrification to Boost Load, Reduce Energy Costs

Edison expects a significant boost from California’s push to decarbonize its economy, an outlook shared by its neighbor to the north, Pacific Gas and Electric. (See PG&E Foresees Strong Growth from Electrification, Data Centers.) 

“After years of flat demand, SCE is projecting an uptick in electricity usage of about 2% annually over the coming years,” Pizarro said, in line with PG&E’s forecast load growth of 1 to 3% through 2028. 

“As more and more vehicles and buildings are electrified, the electricity demand will increase by 80% over the next 20 years, which will benefit customer affordability through a 40% decrease in their total energy costs across electricity, gasoline, and natural gas,” he said. 

Pizarro said the expansion of high-voltage transmission and local distribution networks will be “critical” to California meeting its climate goals. Edison estimates a 6 to 8% compound annual growth rate in its rate base over the next five years, from $43 billion this year to $55.2 billion in 2028. That growth will be “driven by wildfire mitigation and important grid work to support California’s leading role in clean energy transition,” the company said in its presentation. 

The company also foresees the opportunity to expand its rate base by an additional $2 billion through investments in a “next-generation” enterprise resource planning system, advanced metering infrastructure, and grid reliability and resilience upgrades, as well as another $2 billion in transmission projects subject to FERC approval. 

In January, the California Public Utilities Commission rejected SCE’s 2021 proposal to spend $744 million to install new heat pumps in 250,000 homes in its territory and assist lower-income households with necessary electrical upgrades. The regulator expressed concern about spreading the costs for the program across the utility’s customer base at a time of already high energy costs.   

“A substantial amount of federal, state and ratepayer money is already being spent, and has been allocated for future use, to largely implement the same building electrification efforts in SCE’s proposal,” the commission said in its decision (A2112009). 

“Although the CPUC denied SCE’s building electrification application due to their near-term affordability pressures, it acknowledged SCE’s leadership in proposing programs to accelerate much-needed building decarbonization,” Pizarro said. “The utility will continue to evaluate the results of other building electrification pilots it has in progress and look for different ways to support the state in advancing its clean energy priorities.” 

Edison reported 2023 profits of $1.197 billion ($3.12/share), compared with $612 million ($1.61/share) in 2022. Fourth-quarter earnings came in at $378 million ($0.99/share), compared with $415 million ($1.09/share) a year earlier. 

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PG&E Foresees Strong Growth from Electrification, Data Centers

California’s “leadership in electrification” will be a key driver of Pacific Gas and Electric’s expected customer growth in the coming years, CEO Patti Poppe said Feb. 22 during the utility’s fourth-quarter and year-end earnings call. 

PG&E is forecasting annual load growth of 1 to 3% through 2028, based in large part on expectations for increased electrification and continuing uptake of electric vehicles among its customers, according to slides accompanying the call. 

The utility also foresees strong growth in demand from commercial customers, with service applications from new data centers increasing threefold last year over the previous four years. 

“As we look at the five-year forward load-growth forecasts, the back end of that forecast will reflect the additional data center demand,” Poppe said. “And look, I think we all can agree that the only thing that’s happening with data centers is they need more of them.” 

PG&E estimates $62 billion in capital expenditures over 2024-2028, with the spending supporting “strategic capital investments in electrification, energization, undergrounding and wildfire mitigation,” according to a footnote in the slides. That represents a 20% increase over the utility’s outlook for the 2023-2027 period and translates into a 9.5% compound annual growth rate (CAGR) for its rate base. 

The company also foresees opportunities for an additional $5 billion in spending over the next five years on transportation electrification infrastructure, transmission upgrades, incremental business connections, hydroelectric facilities and storage, and information technology and automation. 

Despite the anticipated sharp growth in spending, Poppe said the company expects to hold customer rate increases to 2 to 4% annually based on new cost-saving measures and the ability to spread costs over the growing load base. 

Poppe attributed the cost-saving to the utility’s adoption of a “lean operating system,” which last year drove a 5.5% reduction in nonfuel operations and maintenance costs after a 10% CAGR in those expenses during the previous five years. 

“As a reminder, several years of doing whatever was necessary to respond to back-to-back crises pushed our capital-to-expense ratio far below the industry average,” she said. “This is where we have a wealth of opportunity and a long runway to drive efficiencies with sustainable savings benefiting both our customers and our investors.” 

Poppe also touted PG&E’s improving record related to wildfire ignitions. 

The utility has been found responsible for its equipment sparking some of the most destructive fires in California’s history, including the deadly 2018 Camp Fire, which burned down most of the rural town of Paradise and killed 85 people. (See Cal Fire Pins Deadly Camp Fire on PGE.) 

PG&E started no “catastrophic” fires in its service territory last year, while tallying 68 reportable ignitions, compared with 91 in 2022, 134 in 2021 and 201 in 2017. Based on the scoring methodology established by the California Public Utilities Commission, the utility’s wildfire risk fell by 94%. 

“While we’re extremely pleased with these results, our team certainly isn’t stopping here. We see further opportunities to drive overall wildfire risk reduction beyond the 94% achieved in 2023 as we continue with additional system hardening and deployment of new technologies,” Poppe said. 

PG&E last year undergrounded 364 miles of distribution lines at a cost of just under $3 million per mile, bettering targets of 350 miles at $3.3 million per mile. Poppe said the work will help prevent public safety power shutoffs and other outages for 15,000 customers in areas of high fire risk. 

The utility expects to underground around 250 miles of lines this year, part of a plan to bury 10,000 miles of lines — or about 8% of its distribution system, Poppe noted. 

Pacific Generation a ‘Great Transaction’

PG&E is still awaiting the CPUC’s decision on the proposed spinoff and sale of a minority stake in Pacific Generation, a standalone subsidiary that would control 5.6 GW of generating capacity, including more than 1.3 GW of battery and pumped storage. FERC last year approved the plan, which would raise an estimated $3.4 billion for PG&E. (See FERC Approves PG&E’s Proposal to Spin off Generation.) 

“We think this a great transaction for customers,” PG&E CFO Carolyn Burke said, adding that the advantageous financing costs stemming from the spinoff will also improve the utility’s balance sheet and lower overall costs for utility customers. 

Both Burke and Poppe emphasized during the call that PG&E would not be seeking to raise money from equity markets this year because the company’s current stock price makes other financing options more “favorable.” 

PG&E reported earnings sat at the top end of previous estimates. The company made $2.242 billion last year ($1.05/share), compared with $1.8 billion ($0.85/share) in 2022. Fourth-quarter earnings per share jumped to 84 cents from 24 cents a year earlier. 

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Dominion Sells 50% of Coastal Virginia Offshore Wind to Stonepeak

Dominion Energy on Feb. 22 reported earnings of $2 billion in 2023 and announced that it has closed on an equity partner for its Coastal Virginia Offshore Wind (CVOW) project. 

The utility is selling a 50% noncontrolling interest in CVOW to Stonepeak through the formation of a new public utility subsidiary, under Virginia’s jurisdiction, that will own the project, while Dominion will continue to construct and eventually operate the wind farm on its own. 

“The Coastal Virginia Offshore Wind project continues to proceed on time and on budget and consistent with our previously communicated timing and cost expectations,” CEO Robert Blue said. “A competitive partnership process attracted high-quality interest, resulting in a compelling partner for CVOW. Stonepeak is one of the world’s largest infrastructure investors, with more than $61 billion in assets under management and an extensive track record of investment in large and complex energy infrastructure projects, including offshore wind. Their significant financial participation will benefit both our project and our customers.” 

The deal includes a number of provisions in which Stonepeak would share in any cost overruns, but Blue told investors on a conference call that he expects Dominion will complete CVOW on time and on budget. 

“We’ve been very clear with our team, and with our suppliers and partners, that delivery of an on-budget project is the expectation,” Blue said. 

Dominion posted a video highlighting the work it and suppliers have done on the project so far, with some monopiles being delivered to Virginia while construction continues on other components elsewhere, he added. 

The company has already invested $3 billion in the project, and it plans to put in another $3 billion before the end of the year. A little more than 92% of the project’s costs are now fixed, and the firm expects its final cost will be $9.8 billion. 

Stonepeak will pay Dominion about $2.9 billion once the deal closes to cover its pro rata share of investments so far, but the deal will have it invest about $4.9 billion assuming the cost is on budget. The investment firm could be on the hook for more, but its pro rata share of costs goes down the more costs overrun Dominion’s estimates, while the utility would wind up with a greater share of CVOW if costs are higher than expected. 

The deal has to get approval from the Virginia State Corporation Commission (SCC) and the North Carolina Utilities Commission. 

“It will be a public utility in Virginia and be entitled to recover its prudently incurred costs of constructing and operating the project under the existing offshore wind rider in Virginia,” Blue said. 

While last year Dominion was focused on getting a bill through the legislature that changed how Virginia regulates its business, this legislative session has been slow when it comes to electric power issues, Blue said. One exception was the legislature finally naming two new members to the SCC, which had been short staffed for years. (See Virginia State Corporation Commission Finally Gets All Seats Filled.) 

“They have extensive experience in both government and the private sector,” Blue said. “And we look forward to working cooperatively with these well qualified new members.” 

Dominion is going to be back before its investors shortly, with an investors day scheduled for March 1, at which it will present a “comprehensive strategic and financial update” and conclude the business review it has been working on for months.