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November 5, 2024

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SPP Board of Directors/MC Briefs: May 7, 2024

CEO Sugg Warns of ‘Serious Challenges’ Facing the Region

AURORA, Colo. — SPP CEO Barbara Sugg warned the RTO’s Board of Directors and stakeholders last week that the grid operator faces new and stronger headwinds, even as it met its corporate goals’ first-quarter milestones. 

In delivering her president’s report to open the May 7 quarterly meeting, she said, “I tell people all the time what a great time [it is] to be in the electric utility industry, but it’s not without challenges.” 

Sugg then listed those challenges: “significant” load growth in recent years and more “unprecedented” growth in the foreseeable future; still more variable energy resources in the generation fleet and interconnection queue; the transition to clean energy resources outpacing the technologies needed to support them for reliability; performance issues with traditional resources that have historically been “extremely dependable and responsive”; transmission constraints; struggling to get new transmission built in a timely fashion; and a backlog of generators with interconnection agreements that are not yet online. 

“And if that wasn’t enough, extreme weather events are becoming more the norm than the exception,” Sugg said. “I say all this to say that what got us here will not get us there. 

“We’re facing serious challenges in the region. We must continue to work together to not only understand these challenges, but remain committed to resolving them.”

SPP’s corporate goals are tied to its strategic plan. Mitigating resource adequacy risks is tied for the No. 1 goal with cybersecurity, and no wonder: The grid operator has issued five resource or conservative operations advisories since early March, the latest because of threats from solar storms. 

The RTO’s other goals are enhancing extreme weather event readiness, optimizing the generator interconnection queue’s processing, advancing innovative transmission policies and continuing the western expansion. 

“A vital element of these goals is to focus on affordability,” Sugg said. “We are still looking for opportunities to increase value and decrease costs. … We are below budget so far this year. I’m knocking on wood in large part due to process improvements and exceptional negotiating skills. Of course, there are always things that come up throughout the year that may or may not have been on our radar or in our budget, but we’re keeping a focus on affordability.” 

As if to emphasize the complexities ahead for SPP, the U.S. Department of Energy on May 8 released a list of 10 proposed transmission corridors that could be eligible for a share of $2 billion in federal loans and special permitting under FERC’s backstop siting authority. (See related story, On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

Most of the National Interest Electric Transmission Corridors (NIETCs) lie squarely in SPP’s current and planned footprints. They include the 645-mile Delta Plains and 780-mile Midwest-Plains corridors, both of which would link with MISO. The Northern Plains corridor could solve congestion issues in the Dakotas and Nebraska, while two more in New Mexico and Colorado could improve ties between the two major interconnections. 

FERC on May 13 will unveil its plan to accelerate long-distance transmission line development to meet rising power demand and bring a backlog of planned clean energy projects to the grid. 

Apparently, it’s nothing SPP can’t handle. The grid operator says it will evaluate the order, DOE’s NIETC notice and other “pertinent” rulings in coordination with its members and the Regional State Committee, which comprises state regulators.

“SPP is hopeful these initiatives will align with our strategic goals to continue removing the generator interconnection backlog and developing a long-range consolidated planning process,” spokesperson Meghan Sever said. 

SPP’s current and proposed RTO footprints. | SPP

Bylaw Changes for RTO West

SPP’s membership unanimously approved recommended bylaw changes from the Corporate Governance Committee related to the RTO’s western expansion and board compensation during a special member meeting. 

The CGC said the revisions to SPP’s bylaws and its membership are necessary to expand the RTO into the Western Interconnection. They include increasing the Strategic Planning Committee’s membership, considering diversity between the two interconnections when selecting organizational group participants and expanding terms specific to the Western Area Power Administration’s Upper Great Plains to the agency’s other regions. 

Separately, the board approved a package of 16 tariff revisions that include establishing a Western balancing authority area and managing transactions across the DC ties’ 510 MW of bidirectional capacity between the two interconnections. Settlements will be based on transmission service reservations during the market’s first four years. After that, they will be based on transmission congestion rights. 

“We will use a single-market optimization using these DC ties to bring value across both the West and the East, with the goal to bring price convergence across the DC ties,” said Bruce Rew, SPP’s senior vice president of operations. 

Lloyd Linke, WAPA-UGP’s regional manager, abstained from the Members Committee’s unanimous vote, saying he “fully supports” the changes but that the agency wants to keep its options open in addressing potential protests at FERC. 

American Electric Power, Evergy and the Natural Resources Defense Council’s Sustainable FERC Project also abstained. 

SPP has been working since 2020 with Western parties, some already members in the East, interested in joining the RTO: Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power, Municipal Energy Agency of Nebraska, Platte River Power Authority, Tri-State Generation and Transmission Association, and three WAPA divisions. 

The prospective members would add Utah and Arizona to SPP’s 15-state footprint. 

SPP’s RTO West is a “true expansion,” in the words of board Chair John Cupparo. Markets+ is a contract service funded by its participants. RTO West is targeted to go live in April 2026. 

The approved bylaw changes for directors’ compensation will increase their annual retainer from $95,000 to $125,000. The CGC said the increase keeps SPP’s board compensation competitive and helps attract top talent. 

The committee said it slightly modified the compensation framework to eliminate fees paid for special board assignments, board advisory or liaison support, assigned meetings, and the board/committee meeting fee. Board members will receive additional fees for participating on nine committees and task forces, increasing their compensation by 6 to 15%. 

Sugg said the board’s total 2024 compensation of $1.54 million is 11% above forecast. She said a compensation consulting firm recommended an even greater increase. 

“You all are very well aware and witness on a near-daily basis just how engaged the board is and how collaborative they are and working with all of you,” she told stakeholders. 

The CGC will again review the compensation policy in 2025, Sugg said. 

SPP, SPS Reviewing April Outage

Sugg told the board and MC that SPP is reviewing a small, local load-shed event in New Mexico and will bring a full report to the Markets and Operations Policy Committee’s meeting in July. 

The April 28 outage lasted for about two hours and represented about 3% of the area’s load. Southwestern Public Service, the local transmission owner, said about 1,000 customers were without power. 

“As with all operational events, we take these very seriously and are working through the after-action steps,” Sugg said. She said SPP and SPS staff, along with the Operating Reliability Working Group, are involved in the review. 

SPS said in a statement it was directed to reduce load to address voltage issues in the southern portion of its service territory.

“The specific drivers behind this event and steps to minimize recurrence remain a topic of discussion between SPS and [SPP],” it said. 

2023 Annual Report Released

SPP has released its 2023 annual report highlighting the previous year’s accomplishments, which resulted in $3.6 billion in benefits to its members and a 20:1 cost-to-benefit ratio. Sugg said lower gas prices, “substantial” load growth and an increase in wind energy were the primary drivers. 

Using a calculation vetted several years ago by stakeholders, the grid operator found members realized $2.25 billion in benefits from the markets and a combined $1.88 billion from transmission and operations and reliability. That was partially offset by $524.6 million in the transmission revenue requirement’s costs. 

“We certainly are delivering significant value to the region,” Sugg said. 

Dowling, Janssen Leave SPP

Midwest Energy’s Bill Dowling (left) and Kelson Energy’s Rob Janssen share a final moment together after their last board meeting. | © RTO Insider LLC

Sugg led standing ovations for Midwest Energy’s Bill Dowling and Kelson Energy’s Rob Janssen, who were both attending their last board meeting. 

Dowling has announced his retirement, and Janssen’s company is selling off its interest in Dogwood Energy, a 665-MW gas-fired generator in Oklahoma that serves as its only resource in SPP. 

“Lots of people come and go from this committee, but we would be remiss if we didn’t stop and recognize the fixtures, those people that really helped us become the organization that we are,” Sugg said. “We’ll miss both Bill and Rob.” 

Dowling and Janssen have both served as MOPC’s chair and spent more than 20 years on the MC. Dowling was also a founding member of the Regional Tariff Working Group. 

“I asked [Bill] if I could blame him for the 8,000 pages in our tariff, and he said, ‘No. Only the first 3,000 pages,’” Sugg said. 

Board Approves RSC Revisions

The board and MC approved three RSC revision requests that commissioners previously endorsed unanimously — as they did for all seven of their voting items — during their May 6 meeting: 

    • RR607 implements policy changes to the safe harbor provisions approved last October to provide more flexibility for market participants. The measure replaces the original 125% peak load criterion to not exceed the transmission customer’s projected system peak responsibility multiplied by the higher of 125% or the sum of 110% and the current planning reserve margin percentage. The policy reflects SPP’s recent establishment of a PRM. 
    • RR605 defines an authorized outage, adds requirements for resources’ availability during both the summer and winter seasons (unless on an authorized outage), and helps load-responsible entities and generation owners better understand when to submit RA capacity when providing workbooks to meet the RA requirement. 
    • RR616 ensures any outage not approved by the SPP balancing authority and not an outside management control event is accounted for in performance-based accreditation. Three renewable energy interests abstained from the MC advisory vote, with the Sustainable FERC Project’s Christy Walsh expressing concerns over SPP’s “piecemeal” approach to RA that could lead to additional tariff filings at the commission. 

The board’s consent agenda resulted in the approval of the 18-person industry expert pool that will judge bids for competitive projects within the SPP footprint. A panel of three to five experts will be chosen from the pool for each competitive upgrade. Sixteen of the members were renewed, and two new members were added. 

Other items on the consent agenda included: 

    • RR555, which implements two recommendations FERC made to SPP after the 2021 winter storm: that transmission operators and balancing authorities include new guidelines in their emergency operating plans to facilitate rotating load shed and protect critical gas infrastructure. 
    • An out-of-cycle request by Evergy Kansas Central to re-evaluate a 138-kV terminal upgrade near Wichita. 
    • Withdrawing a WAPA-UGP 345/230-kV transformer project in Fort Thompson, S.D. WAPA’s estimate of $59.17 million exceeded the $36.34 million variance bandwidth and would have delivered the project 10 years late. 
    • Approval of a $35.95 million refined cost estimate for SPS’ Potter County 345/230-kV transformer project. SPS’ estimate exceeded the $35.91 threshold, but staff said approving the economic project will allow the company to proceed and economically benefit the region. 
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Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says

The Bonneville Power Administration’s choice of a day-ahead market will not be driven by concerns about the impact of the seams that would divide the two markets proposed for the West, an agency official made clear May 8. 

“Bonneville is very aware that having two markets in the same or neighboring footprints presents seams that need to be managed. We are taking that into account,” Russ Mantifel, BPA director of market initiatives, said during a virtual workshop with stakeholders. “But we think seams are manageable and that the existence of seams does not mean a categorical rejection of us joining Markets+.”  

The workshop was the agency’s sixth such meeting on day-ahead markets and the first since agency staff issued its April 4 recommendation that BPA choose SPP’s Markets+ over CAISO’s Extended Day-Ahead Market (EDAM). (See BPA Staff Recommends Markets+ over EDAM.) 

BPA’s position on seams puts it squarely at odds with EDAM’s most ardent supporters, who contend that a West divided into two markets would hamper the region’s ability to fully tap the “diversity benefit” of its energy resources and varying load patterns. For those stakeholders, a single Western market with no boundaries represents the key reason for advancing toward a more organized electricity market. 

Included in that camp are the industry stakeholders and state energy officials backing the West-Wide Governance Pathways Initiative, an effort to create the governance framework for an independent market that expressly includes the state-run CAISO and builds on the ISO’s market platform.  

“The seams issue is kind of a core question here,” Fred Heutte, a senior policy analyst at the Northwest Energy Coalition (NWEC), said during the workshop. NWEC has been a longtime advocate for a single Western market. 

Heutte asked for BPA’s views on a February study by the Western Power Trading Forum (WPTF) and Portland, Ore.-based Public Generating Pool, which found that a seam between EDAM and Markets+ likely would create challenges beyond those seen at the boundaries of the full RTOs in the Eastern U.S., given that each market still would contain operating seams within them. (See Western Market Seams Issues to Differ from East, Study Finds.)  

Heutte linked his question to a comment in the BPA staff recommendation in favor of Markets+ that referred to the “complexities” of BPA needing to accommodate transmission customers (including Northwest investor-owned utilities) and “preference” customers who are not participating in Markets+ — or, possibly, either market. 

“This is a really unique situation,” Heutte said. 

“I would say for Bonneville, it’s not that unique,” Mantifel responded, noting that BPA for eight years served customers participating in CAISO’s Western Energy Imbalance Market (WEIM) before joining that market in 2022.    

“Just to be clear about this, I believe Bonneville has lived and resolved these seams more than any other entity in the West,” Mantifel said. “We have managed flows on our system for a market that we are not participating in, that we don’t control the redispatch of outside of the coordinated transmission agreements.” 

“The seams are important. We hear the comments about seams. But Bonneville does feel that there’s a way to make this work. We would encourage, we would invite FERC, for example, to get involved and encourage the market operators to work together,” he said. 

‘Profound Difference’

Heutte said there is a “profound difference” between how the real-time — and voluntary — WEIM functions and how transmission must be handled in a day-ahead market, which would require prior commitment of both resources and transmission.  

Heutte encouraged workshop participants to read the SPP-MISO joint operating agreement to get a sense of the complexity of transacting across market seams, calling the document a “sobering read.” Given its role as the major transmission provider in the Northwest, BPA’s positions would be even more complicated if it joins Markets+ while many of its neighbors join EDAM, he said, because both markets effectively would be running on top of its balancing authority area. 

“With all the complexities … [involved] with all the different potential positions of preference customers and transmission customers of Bonneville, this is a very, very complex thing to grapple with. I think it’s really important to understand this is not the same as just merely an extension of EIM,” Heutte said. 

Mantifel said BPA understands that complexity “as well or better than anybody.” The agency has already put a lot of thinking into the issue as an open access transmission provider, he said. 

“We understand the differences, and we do think that there are very feasible methods of reconciling all these things and operating,” he said. “We have done this, we think we can continue to do it, we think we can build on what we’ve done before and make it work.” 

‘Multilateral’ Issue

Lea Fisher, representing the Western Public Agencies Group (WPAG), asked if BPA will address the implication of seams in the business case accompanying its final decision of day-ahead market, “beyond the discussion you’ve included in the staff leaning where you outlined kind of the need to work through seams and some of the history and successfully doing that.” 

Mantifel said the Western Markets Exploratory Group (WMEG) studies prepared for BPA by Environmental+Energy Economics (E3) offer a picture of the economic benefits the agency would realize under multiple market footprints. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.) E3 will provide “additional sensitivities” related to studies based on varying assumptions about transmission rates and “general market friction” at the seams, he said. 

In terms of the “operational nature” of the seams, Mantifel said BPA is “eager” to have discussions with others in the region on the subject but hasn’t “been able to find partners” for such talks. 

“But we will use the best information available, including our own experience, in terms of operationally what we think scenes would look like. That being said, seams are definitively multilateral. Bonneville can’t, on its own, make all the decisions or resolve all seams,” he said. 

Asked what steps BPA has taken to find willing partners for the seams discussion and whether it has reached out to CAISO, the agency told RTO Insider in an email: “The West appears to be on … track for two day-ahead markets to operate concurrently. BPA is just saying the time to consider seams issues in that environment is now. BPA stands ready to work with entities in the regions to dig into the issue.” 

The need to address seams was a topic of discussion at an April 30 meeting of the Markets+ Participants Executive Committee (MPEC). (See SPP’s Stakeholder Process Attracts Markets+ Participants.) 

“It’s not a secret to anyone that the biggest scenario around objection to Markets+ is the seam,” said MPEC Chair Laura Trolese, with The Energy Authority. She said it would “behoove” the committee to start working on ways to reduce “transactional friction” as soon as possible rather than waiting until the end of the year.  

Speaking at that meeting, Carrie Simpson, SPP’s director of seams and Western services, said RTO staff has heard “loud and clear that we want to figure this out.”  

“I think there’s still just confusion on how it works if we do nothing, and so I think starting there can help people identify what friction exists and what friction does not exist,” Simpson said. “It’s a very important issue to address, and so I think we let that [stakeholder] process play out.” 

But some stakeholders think that discussion would be premature before entities in the West decide which day-ahead market to choose. 

“We can’t really tackle this until we know where the boundary is,” WPTF Executive Director Scott Miller said last month at the spring joint meeting of the Committee for Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB). “And so, when we get to that point, I think sometime this year, then we can engage meaningfully in what we can do to manage the seams that are unique to the day-ahead market.” (See Western Officials Get Rundown on ‘Irritating, Inefficient’ Market Seams.) 

During the BPA workshop, Oregon state Rep. Mike Gamba asked what the advantage to the Northwest would be “in BPA being in a different market that outweighs the obvious difficulties resulting in creating an unnecessary seam.” 

Mantifel said that notion assumes the two markets are equal. 

“I would say that what we’re trying to articulate is that Markets+ is a superior option for us, and I think what we’re trying to move away from is the notion that these things are equal and that the only difference is one creates seams and another does not create seams,” he said. 

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MISO, PJM Agree to Perform New Type of Joint Transmission Study

MISO and PJM announced they will embark on a new joint transmission study in the latter half of this year that concentrates on upping their interregional transfer capability.  

The RTOs said they will be on the hunt for “opportunities for near-term transmission enhancements along the seam.” The study would have MISO and PJM conducting joint transmission analysis and coordinated modeling. 

The grid operators said increasing transfer capability between them could help overcome extreme weather and challenges posed by growing shares of intermittent resources in their fleets.  

MISO and PJM said their announcement is driven by a chorus of calls for better interregional planning from the Organization of PJM States (OPSI), the Organization of MISO States (OMS) and the Midwestern Governors Association (MGA). OMS and OPSI sent a joint letter to the RTOs in February calling for more in-depth joint planning. Multiple environmental and consumer advocacy groups also penned their own joint letters asking MISO and PJM to undertake more comprehensive cross-border planning. (See MISO, PJM Stakeholders Call for Interregional Transmission Overhaul.)  

MISO and PJM’s announcement comes as FERC seems close to setting minimum levels of interregional transfer capacity and after the introduction of the BIG WIRES Act in Congress, which also calls for establishing minimum transfer requirements.  

PJM Vice President of Planning Paul McGlynn said PJM looks forward to more planning coordination with MISO. 

“Ensuring a reliable energy transition requires greater interdependence among regions and careful planning. Advancing this enhanced effort will benefit electricity consumers in each region,” McGlynn said in a May 9 press release.  

MISO Vice President of System Planning Aubrey Johnson said MISO and PJM have a long history of working together.  

“[W]e understand the need to explore interregional planning, and with encouragement from OPSI, OMS and MGA, we will conduct a study that will address both near-term needs and create a model for future studies,” he said.  

The newest MISO-PJM study effort is considered separate from their usual interregional planning processes, which include coordinated system plans that can result in larger interregional market efficiency projects or the smaller, quicker targeted market efficiency project (TMEP) portfolios. It’s not clear yet what projects will result, or if MISO and PJM will create a new class of interregional projects following the study.  

“Similar to MISO and SPP’s [Joint Targeted Interconnection Queue studies] as a new venture in interregional planning, this study between PJM and MISO is also a new venture to enhance interregional planning,” MISO and PJM said in a statement to RTO Insider. 

MISO and PJM said they believe the study “will provide a pathway to increase transfers between the two systems through near-term enhancements, working in collaboration with states and members.”  

Historically, the two approved one interregional market efficiency project in 2020 and have approved four sets of the  smaller  TMEPs aimed at relieving congestion since 2017. They haven’t completed an interregional transmission planning study since 2022. 

MISO and PJM’s plans to coordinate their models for this study does not mean they will work from a joint model. The RTOs said their respective subject matter experts will work together “very closely” to line up assumptions to identify transfer needs and fixes that could expand flows between footprints. They said the new study could provide some “future opportunities” for seams modeling improvements. 

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FERC Poised to Overhaul Transmission Planning and Cost Allocation

FERC is taking the rare step of holding a special open meeting May 13, a Monday, to vote on a proposal to overhaul its transmission planning and cost allocation rules (RM21-17). 

The order would mark the first time since Order 1000 was issued more than a decade ago that FERC made universal changes to those rules. If fully approved as issued, the Notice of Proposed Rulemaking, which the commission issued in 2022, would require longer-term planning out to 20 years with multiple scenarios, create a process for states to agree on cost allocation for regional lines and expand the federal right of first refusal (ROFR) after Order 1000 largely eliminated it. 

One of the big issues generating debate around the rule is what FERC might do in terms of setting rules on its own if those state talks on cost allocation fail. Commissioner Mark Christie consistently has said states should not be forced to pay for others’ policies, while supporters of broader cost allocation have said transmission lines can offer broad-enough benefits to warrant wide cost allocation. (See FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming.) 

The ROFR issue also has split the industry between those who argue the move to competition has stifled development and those who maintain that rolling back competition would lead to higher costs for consumers in what promises to be a massive buildout of transmission in the coming decades. (See Pro-competition Group Plans to Sue if FERC Reinstates Federal ROFR.) 

The commission also will vote to update its backstop siting authority, as required by Congress, that would allow it to approve a line in a National Interest Electricity Transmission Corridor when a state denies the application before it (RM22-7). DOE recently announced a preliminary list of NIETCs. (See related story, On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

The planning proposal has drawn support from around the U.S. and across the aisle, such as Kansas Gov. Laura Kelly (D) and a group of House Republicans from New York led by Rep. Andrew Garbarino. 

Less than a week ahead of the meeting, the EFI Foundation, led by former Energy Secretary Ernest Moniz, released a report that endorsed the NOPR’s main proposals. It argued the country is failing to proactively build transmission lines needed to connect new generation to customers, with the problem growing more acute because of new sources of demand. 

“New load that requires new power is growing today, but regional transmission typically takes at least a decade to build,” the paper said. “New power capacity (including all kinds of generator technologies and storage systems) could deploy faster if transmission capital investments could be more quickly planned, agreed upon and constructed by the nation’s regional transmission system operators.” 

FERC’s proposed rule includes many of the best practices that draw on real-world experiences of ISO/RTOs over the past decade, and many have said it should ameliorate the lack of transmission expansion. 

“But some will question whether FERC has the statutory authority to prescribe and direct jurisdictional transmission organizations to enact those reforms, as opposed to simply making suggestions and recommendations,” EFI’s paper said. 

Another school of thought argues FERC has broad authority to require transmission planning and cost allocation, having won the appeals of Order 1000 a decade ago, when a federal court found it had the authority to require transmission planning for needs driven by public policy.

But the EFI report noted the Supreme Court’s composition has changed since then, and its “major questions doctrine” could be a boon to opponents. 

“While never used explicitly in a major opinion, this doctrine suggests that in issues of major national significance, agencies may need to be granted clear statutory authority by Congress rather than relying on interpretations of more general delegated authorities,” the report said. “Through this lens, they may argue that prior legal decisions should be revisited to ensure that regulations are supported by clear congressional authorities.” 

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Brattle Report Details Impact of ‘Lumpy’ Loads on Utility Forecasts

New sources of demand growth such as data centers for artificial intelligence and rising industries are complicating electricity load forecasting, according to a new report released by The Brattle Group on May 8. 

Electricity Demand Growth and Forecasting in a Time of Change provides an overview of several new demand drivers that will affect load growth and patterns in the coming decades and how utilities include them in their forecasts. 

“Currently, there is a wide spectrum among utilities in how they account for these new drivers,” T. Bruce Tsuchida, a Brattle principal and co-author of the report, said in a statement. “The future net load growth spurred by the new drivers is vast, and our analyses suggest that — given this growth, along with the change in load characteristics and other associated uncertainties — the industry will require a revamped approach to load forecasting moving forward.” 

NERC recently raised its compound annual growth rate (CAGR) for load from 0.6% per year to 1.1% per year over the next 10 years, which is higher than at any point in the past decade. FERC Form 714 filings from utilities have shown peak demand growth rates increasing from 2.6% in 2022 to 4.7% in last year’s filings, Brattle’s report said. 

The new demand drivers and their changing nature and flexibility warrant looking at load forecasting from a different perspective, it said. 

“In today’s world, where much of these new demand drivers are policy-driven, the risk of under- versus over-forecasting is asymmetric,” the report said. “With a climate strategy that relies heavily on clean electrification, the cost and long-lasting effects of underforecasting may be much larger than those of overforecasting — while still recognizing that large overforecasts also have accompanying costs.” 

Policies aimed at combating global warming are driving some of the new demand, but in some regions, new data centers are having a major impact on load growth. Data centers use about 19 GW of capacity now, but with a 9% CAGR, the sector is expected to add the equivalent of New York City’s demand over the next five years nationally. 

“The number of data centers is growing rapidly to meet increasing data usage from streaming services, social media, mobile devices and cloud computing, just to name a few,” the report said. “The emerging fields of AI and machine learning require massive computational power and storage, fueling demand for data center infrastructure and, with it, the demand for electricity. These loads tend to run constantly.” 

Cryptocurrency mining uses an estimated 10 GW to 17 GW across the country, and its growth is volatile and based on crypto prices, but it could grow by an additional 8 GW to 15 GW by 2030.  

Type A vs. Type B

However, the biggest potential source for growth this decade, Brattle reports, is hydrogen production, which could increase from just 70 MW to 25 GW of demand by 2030, which works out to 132% growth yearly. 

The load growth drivers can be classified in two basic ways: “Type A” loads that are large and discrete and often characterized by more uncertainty, and “Type B” loads that are comparatively smaller with smoother growth patterns. 

Load growth from electrifying transportation and buildings counts as Type B, but the industry still faces significant uncertainty around its long-term trajectory. 

“Load growth from electrification, which naturally requires replacing existing stocks, takes time to materialize and is usually geographically uneven,” the report said. “This contributes to higher levels of uncertainty in these forecasts.” 

Data centers, new industry, indoor agriculture and cryptocurrency mining are Type A. “These loads are often quite large and lumpy (sometimes as large as an entire city),” the report said. Their expansion is also concentrated in specific areas and their development can move faster than utility or ISO/RTO planning processes. 

The new loads can change suddenly due to shifts in the market or policy and in some cases — such as with cryptomining and indoor agriculture — they can disappear without notice. 

“Some of these loads may be able to provide flexibility, so the conventional assumption that planning requires building enough capacity to serve an inflexible peak load may no longer be true,” the report said. 

Even without local flexibility, efficiency, demand response and distributed energy resources can offset potential load or sales growth. Those demand-side resources can be large and cost effective for freeing up supply increments for high-priority uses. 

Brattle collected load forecasting documents from utilities and ISO/RTOs around the country for the report and found a spectrum of ways entities are dealing with the new drivers of demand. Traditional load forecasting methods assumed that new demand would be inelastic and that future needs could be addressed within a long planning horizon, usually measured in years. 

“One of the first steps planners could take today is to comprehensively assess the various drivers, even if a sophisticated modeling approach is not yet available,” the report said. “The latter should come next after the new load types are better understood.” 

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Republican-led States Sue EPA over Power Plant Emissions Rule

Republican state attorneys general sued EPA on May 9 seeking to stop implementation of the agency’s final rule aimed at slashing greenhouse gas emissions from existing coal plants and new natural gas plants. 

Under the rule released April 25, existing coal-fired power plants nationwide will have to either close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032. New natural gas plants will have until 2035 to similarly cut their emissions, through efficient design, carbon capture or a combination of both. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Natural Gas Plants Exempt.) 

The suit, filed with the D.C. Circuit Court of Appeals, is led by Indiana Attorney General Todd Rokita and West Virginia Attorney General Patrick Morrisey, the latter of whom led states’ successful lawsuit against the Obama administration’s Clean Power Plan. (See Supreme Court Rejects EPA Generation Shifting.) 

“The EPA continues to not fully understand the direction from the Supreme Court; unelected bureaucrats continue their pursuit to legislate rather than rely on elected members of Congress for guidance,” Morrisey said in a statement. “We are confident we will once again prevail in court against this rogue agency.” 

The National Rural Electric Cooperative Association filed its own suit against the rule with the D.C. Circuit the same day. 

“EPA’s power plant rule is unlawful, unreasonable and unachievable. It exceeds EPA’s authority and poses an immediate threat to the American electric grid,” CEO Jim Matheson said. “Reliable electricity is the foundation of the American economy. EPA’s rule recklessly undermines that foundation by forcing the premature closure of power plants that are critical to keeping the lights on — especially as America increasingly relies on electricity to power the economy.” 

Both suits are essentially placeholders, petitioning the court for judicial review and attaching the rule as evidence but making no arguments. They were filed a day after a separate suit — led by Morrisey and North Dakota Attorney General Drew Wrigley, and joined by 21 other Republican-led states — was filed with the D.C. Circuit challenging EPA’s updated implementation of the Mercury and Air Toxics Standards, announced by Administrator Michael Regan at the same time as the power plant rule. 

“The Biden administration pushes a green political agenda with no purpose other than to attack fossil fuels. Make no mistake, this rule intentionally sets impossible standards to destroy the coal industry,” Wrigley said in a statement. “Federal agencies cannot decide on a whim to destroy entire industries. They are only permitted to work within the bounds that Congress set for them.” 

EPA declined to comment on the pending litigation. 

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Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change

FERC on May 6 partially reversed a 2023 order allowing PJM to modify a parameter for the 2024/25 Base Residual Auction (BRA) to avoid a substantial increase in capacity prices in the DPL South transmission zone and instructed the RTO to rerun the third Incremental Auction (IA) (ER23-729-002).  

The order increases the clearing price for the DPL South locational deliverability area (LDA) to $426.17/MW-day, up from $90.64 under the auction results PJM posted in February 2023 using the modified parameter. The LDA with the second-highest price is the DEOK region, which cleared at $96.24/MW-day. 

In a series of notifications to stakeholders following the order, PJM said it will reopen bids for the third IA on May 10 through May 16; the auction was originally administered Feb. 27 through March 4. Market participants’ original sell offers and buy bids will be the default if no changes are submitted, while all bilateral and replacement transactions made since March 4 have been withdrawn by PJM. 

FERC had granted PJM the authority to revise the reliability requirement for the zone, which covers the Delmarva Peninsula, after preliminary analysis of the BRA, held in 2022, showed a nearly fivefold increase in capacity prices because of an unexpected shortfall in offers. The change was made after the auction was run but before the results were published. 

But in March, following challenges by several stakeholders, the 3rd U.S. Circuit Court of Appeals ruled that change constituted retroactive ratemaking, a violation of the Federal Power Act, as well as the filed rate doctrine. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

The RTO had requested that the commission allow it to exclude resources that did not enter into the auction from the zone’s reliability requirement and to add tariff language permitting the parameter to be revised when resources expected to offer into the auction prompt the reliability requirement to increase by more than 1% but ultimately do not submit an offer. The court’s ruling and FERC’s order leave the forward-looking tariff language but require the original reliability requirement to be used for the 2024/25 auction and the third IA. 

PJM filed a petition arguing that the only way forward would be for it to recalculate the BRA results using the unaltered reliability requirement and asked the commission to allow it to rerun the third IA. Several state commissions, consumer advocates and industrial groups jointly protested, making a case that FERC holds remedial authority and could direct PJM to continue using the revised parameter. 

But FERC said the court had tied its hands. 

“We find that the court’s opinion vacating the portion of the commission’s orders allowing PJM to apply the tariff amendments to the 2024/2025 BRA indicates PJM ‘was required to use’ the initial LDA reliability requirement,” FERC said. “In particular we note that, in reaching that result, the court reiterated that ‘the equities play no role in its application of the filed rate doctrine.’ Accordingly, while we acknowledge PJM load parties’ concerns about rerunning auctions and the equities implicated by this proceeding, we find that they cannot change the outcome here.” 

Commissioners Reluctantly Concur

All three sitting commissioners separately expressed dismay with the outcome. 

Chair Willie Phillips criticized the 3rd Circuit’s decision, saying its “broad reading of the filed rate doctrine, and its endorsement of ‘predictability’ as a higher virtue than equity, is beyond troubling and does not represent my views. … One must ask: If the over $100 million result of a ‘faulty assumption’ (and no one in this case argues that it’s not a faulty assumption) is somehow OK, what about a $1 billion faulty assumption, or a $1 trillion faulty assumption? Can we still conclude those are just and reasonable rates?” 

Phillips urged “all stakeholders, including both PJM and the generators that will reap the more than $100 million windfall due to the court’s decision, to take all necessary steps to ensure that we never find ourselves in this position again. That includes putting in place controls to ensure that a similar error does not reoccur and, should it somehow happen again, that PJM or the commission has the authority to correct that error and protect customers from such a manifestly inequitable result. Basic equity, and the public interest, demand nothing less.” 

Commissioner Allison Clements went a step further, saying that the commission could initiate a proceeding under FPA Section 206 to investigate whether RTOs lacking such protections may produce unjust and unreasonable rates. 

“Should PJM and other public utilities fail to affirmatively update their tariffs to provide notice that adjustments can be made, where appropriate, to prevent inequitable outcomes, then it will fall to the commission to cure this failure pursuant to its authority under Section 206 of the Federal Power Act,” she wrote. 

Her criticism of the ruling was also broader, saying that “it is only the latest in a string of unjust outcomes stemming from the courts’ narrow view of [the filed rate] doctrine” and citing a previous case. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.) 

Commissioner Mark Christie said “the complexity of PJM’s capacity market cannot be overstated” and raises the risk of oversights costing consumers. 

He quoted his concurrence from earlier this year in FERC’s approval of PJM’s changes to its capacity market, criticizing it as increasingly incomprehensible: “Perhaps PJM should be required to post a warning to every reader who tries to read and comprehend a detailed explanation of how the capacity market construct works (borrowing from Dante): ‘Abandon all hope, ye who enter here.’” (See FERC Approves 1st PJM Proposal out of CIFP.) 

“The tinkering and complexities here will assuredly impact consumers — who took no part in this tinkering but will surely pay for the complexities by way of what are estimated to be dramatic rate increases,” he said in his latest concurrence. “This … should require each and every one of us who have played some part in the tinkering (regulators, RTOs and market participants alike) to make certain that it is not consumers who must abandon all hope.” 

Consumer Advocate Argues More Could have been Done

Maryland People’s Counsel David Lapp told RTO Insider he believes FERC had the authority to act differently. 

“It’s extraordinary that we have three FERC commissioners … acknowledging that this is unfair to customers and customers are being getting hit with the consequences of this error and yet they are not using their authority to address that problem — and they have remedial authority,” he said. “FERC is responsible for setting just and reasonable rates; we know the rates are not reasonable, and yet customers are being forced to pay those rates.” 

Without the power to resolve market design errors before rates go into effect, Lapp said he is worried similar circumstances could arise again. His office will be exploring tariff amendments that could be offered in the stakeholder process to empower PJM to correct issues before they hit consumers’ bills. 

Lapp noted that the increased capacity costs will go into effect as Maryland ratepayers may be required to pay a share of a $263 million reliability-must-run (RMR) contract to keep the 410-MW Indian River Unit 4 generator online through December 2026. (See PJM Monitor and Consumers Protest Indian River Compensation Settlement.) 

“This specific impact [from the capacity market] appears to be around $5/month, and there are additional impacts from the RMR for the Indian River plant retirement,” he said. “Maryland’s customers as a whole are getting hit very hard as a result of the consequences of this error — this error that everyone acknowledges is an error — but also as well as the planning processes, or lack thereof, at PJM.” 

The Maryland Public Service Commission also criticized the order, arguing it would produce unjust and unreasonable rates, “though we appreciate each of the FERC commissioners’ expressed reluctance to have to approve PJM’s proposal,” spokesperson Tori Leonard wrote in an email. 

“Rates will clearly be unjust and unreasonable. We can only hope this could be rectified somewhat, through the Incremental Auction. That is not to say that our commission is not weighing its legal options on this matter,” Leonard said. 

Independent Market Monitor Joe Bowring said PJM’s effort to revise the reliability requirement may not have run afoul of the filed rate doctrine had PJM not sought to create a new rule enshrined in the tariff. 

“They didn’t have to make it subject to a rule change. … They could have realized they made a mistake, fixed it and posted the correct numbers,” he said. 

Bowring said it’s unlikely that rerunning the third IA will present participants with technical challenges around preparing new offers, which he said will be carefully reviewed to ensure that participants are not taking advantage of insight into how others behaved in the first iteration. 

“It’s hard to predict; as always we don’t want people exercising market power. … It gives you an advantage to know what happened,” he said. 

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Christie, Clements Praise NERC’s Honesty at Board Meeting

FERC Commissioner Mark Christie praised NERC CEO Jim Robb as a “revolutionary” at the organization’s Board of Trustees meeting this week. 

The ERO’s board and Member Representatives Committee met in Washington, D.C., via a hybrid format, with trustees, members and guest speakers (except Christie) attending in person and all others joining by phone or the internet. 

Introducing Christie, Robb called him “a very straight-talking voice for reliability and consumer issues” who has provided “stalwart support of [NERC’s] mission.” Christie returned the compliment in his remarks, recalling his description of Robb at a meeting of the Gulf Coast Power Association this year. 

“I said [that] if you’ve seen Jim Robb, you probably don’t think he’s a revolutionary. But Orwell said that telling the truth in a time of universal deceit is a revolutionary act. And I admire Jim Robb for telling the truth about the challenges that we’re facing in reliability,” Christie said, adding that other stakeholders — including Manu Asthana and John Bear, CEOs of PJM and MISO, respectively — are revolutionaries for the same reason. 

Christie described the power grid as “a huge lake [that] is only six inches deep,” with grid operators responsible for ensuring the depth stays consistent at all times by balancing incoming water (supply) with outgoing water (demand). Citing the growing electric demand from sources such as data centers and artificial intelligence services, he warned that many end customers and government stakeholders still do not understand the complexity of the ongoing move from traditional electric generation to weather-dependent resources like wind and solar. 

“You can’t get away from the reality that with the kind of demand increases that we’re seeing already and that are projected just in the next three [to] five years, there’s going to have to be a substantial increase in generation resources. And at the same time, we’re going in the opposite direction by retiring substantial generation resources that are dispatchable,” Christie said. He asked NERC to “continue to tell the truth,” even though “there are a lot of special interest groups that don’t want to hear it,” because “the truth will track us down.” 

Christie’s fellow Commissioner Allison Clements spoke after him. While she also called on NERC to be an “honest broker,” she added that “the truth requires nuance [in] a time of rapid change.”  

Clements ran down the challenges facing the grid — such as aging infrastructure, growing incidence of extreme weather events, and cyber and physical security threats — but said the changing times present opportunities for NERC and FERC to work together to shape and strengthen the system for the future.  

In the case of generation retirements, for example, she acknowledged Christie’s concerns about the loss of dispatchable generation but pointed out that not all traditional generation is dispatchable, and grid planners can work together to determine which resources can be retired safely. 

Reminding trustees that NERC commands significant respect both in the industry and in policy-making circles because of its reputation for honesty, with lawmakers taking the ERO’s reliability assessments as “gospel,” Clements urged NERC to continue speaking out on the developing challenges to help build momentum for the needed changes. 

“There’s a lot going on, but there’s more to do, and it’s the responsibility of the regulators and [NERC] to … get behind the easier, quicker stuff, and then get up to what’s a little bit harder,” she said.   

New CIP Standards Accepted

The board passed a handful of action items at this week’s meeting. In addition to accepting the ERO’s 2023 audited financial statements and statement of activities for the first quarter, trustees voted to approve the work of two standards development projects. 

NERC’s Soo Jin Kim and Howard Gugel at the board meeting. | NERC

Introducing Project 2016-02 (Modifications to CIP standards), NERC Vice President of Engineering and Standards Soo Jin Kim explained that the project — one of NERC’s longest — was intended to address “a need … to provide for virtualization and virtualized technologies to be implemented into our cyber systems.” 

Nearly all of NERC’s Critical Infrastructure Protection (CIP) standards were affected by the changes, which Kim said were designed to be “future proof [and] backward compatible” with a wide range of existing and potential future technologies.   

Next came Project 2023-03 (Internal network security monitoring), which saw the board accept proposed standard CIP-015-1 (Cybersecurity — INSM). The standard will require registered entities to implement one or more documented INSM processes on grid cyber systems considered to be high impact, as well as medium-impact systems with external routable connectivity. 

The board and MRC’s next meetings will be held Aug. 14-15 in Vancouver, Canada. 

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NJ Enacts New Construction Electrification Incentives

New Jersey has enacted a package of new construction incentives worth up to $5.25 per square foot for new residential and nonresidential construction, in line with the state’s commitment to adopt an electrification program to install electric space heating and cooling systems in 400,000 homes by December 2030. 

The New Jersey Board of Public Utilities (BPU), which approved the incentive plan April 30 in a 4-0 vote, will start providing the incentives in coming months. The program is designed to streamline the application process for new construction and set up a long-term goal of “transforming the new construction market in N.J. to one in which most new buildings will have ‘net zero’ energy usage,” according to a BPU release. 

BPU President Christine Guhl-Sadovy said the plan, known as the New Construction Program, “improves standards and achieves greater energy efficiency to benefit the environment, residents and businesses in New Jersey.“  

It aims to do so by creating a single point of entry into the program, eliminating market gaps and optimizing program process flow, the agency says. Builders and developers can seek incentives through three pathways — “bundled,” “streamlined” and “high performance” — for which participation is determined by the elements of the proposed project and its effectiveness in cutting emissions. 

The basic incentive plan offers a payment of between $0.25 and $2.50 per square foot of construction, to which a bonus can be added for reducing greenhouse gases. A project also can receive a bonus of $1.50 per square foot if the project reduces carbon emissions by 3 tons. And it could receive an “enhanced incentive” of up to an additional $1.25 per square foot if it creates affordable housing, is a nonresidential project in an urban opportunity zone or is an industrial “high-energy intensity building.” 

Persuading Consumers

The program is part of Gov. Phil Murphy’s effort to achieve the building electrification goals he set out in a February 2023 order. Aside from the electrification of 400,000 homes, the order calls for electric space heating and cooling systems to be installed in 20,000 commercial properties and for the state to ensure that 10% of all low- to moderate-income properties are electrification-ready by 2030. 

To that end, Murphy (D) has created a Clean Buildings Working Group to plot the transition and a task force to study how to mitigate the impact on the gas sector, as well as a portfolio of incentive programs. State officials say they are not forcing a shift to gas — not “mandating anyone give up their gas stove,” as one BPU official put it — but want to do so by encouraging consumers to make the move with incentives. 

However, the New Jersey Department of Environmental Protection in December 2022 held off enacting a rule that would have banned the installation of new commercial-size fossil fuel boilers after Jan. 1, 2025, after protests from business and fuel groups. (See NJ BPU Outlines $150M Building Decarbonization Plan.) 

A key element of New Jersey’s strategy, as in other states, is to improve the efficiency of existing buildings, cutting energy waste and heat leakage. Yet a panel at the Montclair State University Clean and Sustainable Energy Summit on May 2 on “Energy Efficiency Innovation for Equitable Decarbonization” showed that strategy is not easy. 

Speakers representing different utilities said factors such as supply chain delays and cost increases, lack of resident awareness of programs, landlord reluctance to invest in their buildings and the “culture shock” experienced by consumers confronted with an unfamiliar program asking them to make a dramatic shift have presented challenges and helped prevent the programs from gaining greater traction. 

New Jersey is at the start of a “new dawn” of energy efficiency that began with the 2018 passage of the Clean Energy Act, which gave utilities the responsibility for implementing energy efficiency programs, Anne-Marie Peracchio, managing director of marketing and energy efficiency for New Jersey Natural Gas, said at the conference. The law set goals of a 2% annual reduction in electricity sales and a 0.75% reduction in gas use.  

In July 2021, the state enacted a three-year energy efficiency program — known as a Triennium — and last year, it approved a second period, Triennium 2, running from 2025 to 2027 with funding for demand-response programs, voluntary electrification backed by incentives for appliances and projects costs and weatherization assessment and remediation. 

Building Owner Reluctance

Implementing the program has presented a series of challenges, said Sirajuddin Shaikh, senior engineer for utility Jersey Central Power & Light Co. Inflation has slowed the uptake of efficiency measures, as has customers finding the payback period is longer, he said.   

Supply chain problems emerged in 2021 and continue, especially for orders of mechanical equipment, for which deliveries can be delayed by 15 to 30 weeks, he said.  

“Not all customers are able to wait that long,” he said.  

Sirajuddin Shaikh, senior engineer for Jersey Central Power & Light, speaks about energy efficiency at the Montclair summit. | © RTO Insider LLC

Some potential projects never advance because building owners don’t want to be bothered with the paperwork required to take part in an efficiency program or are not comfortable with the ongoing evaluation of the impact of the project, which is needed to verify its effectiveness, Shaikh said. 

In addition, as time moves on, “low-hanging fruit” projects that immediately improve efficiency — such as installing energy-efficient lighting systems — are completed. And some building owners are reluctant to undertake the kind of “deep-retrofit” measures that are left, and that require greater investment and a longer payback period, he said. 

Another challenge is that the COVID-19 pandemic continues to affect the market, with many people still working from home, resulting in low office occupancy rates. 

“Building owners are looking at the buildings and saying, ‘Hey, if the offices are not occupied, what’s my motivation to invest money in my building to make it more energy efficient?’” Shaikh said. Some building owners also don’t see the benefit of investing in energy efficiency because it’s the tenant — and not the owner — who benefits from the cost reduction, he said. 

“There is a constant tension going on,” he said. “Whether you’re talking about commercial property or multifamily property, most of the tenants are responsible for paying the utility bill.” 

Consumer Education

Candyce Rountree, manager of residential energy efficiency for Pepco Holdings, said the company has a “huge challenge with customer awareness” of its portfolio of energy efficiency programs, with customers often unaware that programs existed or what they are for. 

“A lot of customers were a little bit confused about, you know, why a utility company would be incentivizing customers to use less of their products,” she said. 

A key solution adopted by Pepco was to mount an aggressive outreach program, she said. 

“We’ve offered community workshops, we’ve engaged community outreach businesses, we’ve had targeted marketing campaigns and partnerships with local organizations,” she said. “And all that was crucial for increasing awareness and encouraging participation in our energy efficiency programs.” 

The company also needed to overcome the fallout from the increase in interest rates, she said. Pre-pandemic, the company offered ratepayers zero-interest loans to buy energy-efficient products, but the rise in interest rates pushed up the cost of running the programs because the utility had to “buy down those interest rates,” she said. 

Tim Fagan, manager of planning and evaluation for Public Service Electric & Gas, said promoting the adoption of heat pumps in New Jersey poses challenges. For one, convincing customers in the North of heat pump capabilities is tougher than in Southern states, where the winters are milder and the heat pump “down there runs more or less just like an air conditioner.” 

New Jersey’s relative energy costs also pose a challenge, he said. From a financial standpoint, switching from an oil or propane heater to an electric heat pump “generally speaking is positive for the customer,” he said. 

“However, when a customer switches from natural gas to a high-efficiency heat pump, generally speaking, it’s not,” he said. To compensate, the utility emphasizes a broader, “whole-home approach,” and that helps shift the equation, he said. 

“We’re going to look at the whole house,” he said. “Insulate it, air-seal it, make sure that heat transfer slows down. And therefore, when you put that heat pump in, perhaps now you can turn the overall kind of equation from negative to positive, or at least bring it down to make it a little bit more palatable for the customer.” 

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Calif. Grid Equipped for Summer, CAISO Says

CAISO officials are optimistic about the grid’s performance this summer, as the system has added 4.5 GW of nameplate capacity since September, with an additional 4.5 GW on the way. 

The figures are in CAISO’s 2024 Summer Loads and Resources Assessment released May 9. 

The summer assessment found that resources expected by this summer will suffice to meet forecast demand plus an 18.5% reserve margin for June through September. 

In September, when California often faces its highest demand for electricity, CAISO’s assessment showed at least 3,438 MW of capacity above the forecasted demand plus reserve margin during the 6-10 p.m. peak net load hours. 

“Our findings provide a solid factual basis for going into the summer with optimism for maintaining reliability as the weather — and demand for electricity — begin to heat up between now and September and into October,” Aditya Jayam Prabhakar, CAISO director of resource assessment and planning, said in a blog post. 

In addition to the resource growth, the summer 2024 demand forecast has softened, CAISO said. Hydropower conditions are expected to be “average to slightly above average” after a winter that left the state’s snowpack at 109% of the historical average. 

Those factors combined will more than offset generation retirements and the transition of gas-fired generation into the state’s strategic reserves, CAISO said. 

However, the summer assessment notes it doesn’t take into account “extreme events” such as wildfires or regional heat waves “that continue to pose a risk for emergency conditions to the CAISO grid.” 

Two-pronged Analysis

For its analysis, CAISO used a probabilistic assessment of resources based on the California Public Utilities Commission’s February 2024 preferred system plan along with a multihour stack analysis looking at energy sufficiency on peak days during each summer month. 

CAISO projected that summer peak load will be highest in July, at 46,244 MW, followed by 45,972 MW in September and 45,059 MW in August. 

CAISO’s all-time high peak load was 52,061 MW on Sept. 6, 2022, at 4:58 p.m., amid an extended heat wave, the ISO reported. Rolling blackouts were narrowly averted when the Governor’s Office of Emergency Services sent out text messages urging consumers to conserve electricity. (See CAISO Reports on Summer Heat Wave Performance.) 

Last summer, CAISO issued level 1 energy emergency alerts on three days in July, which were attributed to high levels of exports to the Southwest. (See CAISO DMM: High Exports to Southwest Led to July EEAs.) 

Weather forecasts show that above-normal temperatures are probable across the West this summer, especially in the desert Southwest in August and September. Above-normal temperatures are less likely in coastal areas. 

CAISO has access to emergency resources, the summer assessment noted. 

Under the Electricity Supply Strategic Reliability Reserve Program (ESSRRP), the lifetimes of three gas-fired generating stations — Alamitos, Huntington Beach and Ormond Beach — were extended to support the grid during extreme events. Their combined capacity is about 2,859 MW. 

Additional resources include the Demand Side Grid Support (DSGS) program, which the California Energy Commission launched in August 2022, and the Distributed Electricity Backup Assets (DEBA) program. 

Resource Growth

From September through December, CAISO’s capacity grew by 3,576 MW, including 1,842 MW of solar and 1,321 MW of battery storage. 

An additional 926 MW of capacity was added in the first three months of 2024. And from April through June, an additional 4,569 MW of capacity is expected, with 818 MW of solar and 3,199 MW of battery storage. 

Gov. Gavin Newsom (D) noted battery storage’s growing role in California in a release April 25. California reached 10,379 MW of battery storage in April, up from 770 MW in 2019, Newsom’s office said. 

Also during April, battery storage discharge exceeded 6,000 MW for the first time, and batteries were the largest source of grid power supply at one point during the day. 

“Our energy storage revolution is here, and it couldn’t come at a more pivotal moment as we move from a grid powered by dirty fossil fuels to one powered by clean energy,” Newsom said in a statement.