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November 20, 2024

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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.

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Maryland Offers OSW Developer More Lucrative Terms

Maryland will allow its lone remaining contracted offshore wind developer to seek higher compensation and other changes for the wind farms it is proposing off the Delmarva Peninsula. 

Gov. Wes Moore (D) on May 9 signed into law alterations to the regulatory framework under which four projects were bid into the state’s offshore wind pipeline. 

The intent is to preserve what still is in the pipeline and lay the groundwork for contracting new projects. 

Ørsted’s Skipjack Wind 1 and US Wind’s MarWin 1 received contracts in Maryland’s Round 1 solicitation for the offshore renewable energy certificates (ORECs) that will subsidize their construction. Skipjack Wind 2 and US Wind’s Momentum Wind won OREC contracts in Round 2. 

Ørsted, reeling from cost increases and supply chain constraints with its Northeast projects, terminated the Skipjack contract in January 2024. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.) 

The US Wind contracts total 1.1 GW, about 13% of Maryland’s 8.5 GW offshore wind goal. The two projects are advancing through the regulatory process and remain under contract. Maryland wants to keep them under contract. (See Draft Environmental Statement Prepared for Maryland OSW.)

The new law (HB 1296) requires the Maryland Public Service Commission to open a revised Round 2 proceeding to consider revised schedules, sizes and pricing for any contract previously approved in Round 2. It also allows the PSC to consider a request from a project approved in Round 1 to increase the maximum amount of ORECs and modify its project schedule. 

The Round 2 requests must include commitments for in-state investment in a local supply chain. 

A fiscal analysis prepared for legislators indicates the net financial impact on ratepayers will be the same or less if US Wind is awarded more expensive ORECs, because that in effect would be a reallocation of some or all of Ørsted’s ORECs to US Wind.

Industry trade group Oceantic Network said this last provision is important to keep the Maryland projects on track after the wave of offshore wind contract cancellations along the Northeast Coast in 2023 and 2024. 

Oceantic CEO Liz Burdock said in a news release: 

“Today’s bill signing demonstrates Maryland’s steadfast commitment to maintaining its strategic manufacturing advantage by working with industry to develop solutions and help reset current markets. The offshore wind industry already contributed massively to the state’s economy and is poised to generate approximately $650,000,000 in investment and support nearly 35,000 jobs. 

“Today’s bill contains provisions that will buttress efforts to realize offshore wind investments in facilities like Tradepoint Atlantic and the Port of Baltimore, as well as spur investments beyond Maryland in ports and manufacturing facilities that can be utilized for projects across the East Coast. Along with the Bureau of Ocean Energy Management’s upcoming Central Atlantic Lease Auction this summer, this bill and future efforts from Maryland will place the state’s 8.5-GW goal firmly within reach.” 

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3 GW of Storage Help ERCOT Through Scarcity

Energy storage resources bailed out the ERCOT grid May 8, providing a record amount of energy to help the Texas grid operator through the first tight conditions of the maintenance season. 

Discharging batteries provided 3,195 MW at 8:05 p.m. CT, according to Grid Status, meeting 5% of demand for the first time and smashing the previous record by more than 1 GW.  

“The future is here!” former FERC Chair Pat Wood, now Hunt Energy Network’s CEO, said on social media. 

The old mark came Sept. 6 when ESRs provided 2,172 MW of energy after a voltage drop forced ERCOT into emergency operations for the first time since Winter Storm Uri. (See ERCOT Voltage Drop Leads to EEA Level 2.) 

ERCOT began the year with 3.3 GW of storage capacity. That is expected to double by the end of the year, but an additional 145 GW of storage capacity is in the interconnection queue. 

The ISO had issued a weather watch for the day because of “unseasonably” high temperatures, high levels of expected maintenance outages and the potential for lower reserves. Weather watches are not calls for conservation, ERCOT says. 

The heat index at DFW Airport reached 103 degrees Fahrenheit. 

The grid operator’s May resource adequacy forecast, distributed in March, assumed 14.7 GW of thermal assets would be offline during the month. Instead, 24.7 GW of the resources were offline May 8, according to the ERCOT dashboard. The same forecast also predicted 2 GW of energy storage availability. 

Peak load averaged 68.9 GW during the hour ending at 5 p.m. ERCOT’s record is 85.5 GW, set last August. 

Prices neared their $5,000 cap during the interval ending at 8:15 p.m. 

ERCOT on May 3 issued a request for proposal for 500 MW of demand response, primarily in the San Antonio area. The grid operator has established a generic transmission constraint south of the city to address power flow limitations over transmission lines. 

The RFP was issued May 8. 

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Canada Pension Board, Global Infrastructure Partners to Buy Allete

Canada’s pension board and a private equity firm intend to buy Duluth, Minn.-based energy company Allete for $6.2 billion, which appears to make some Minnesota regulators apprehensive.  

Allete announced May 6 that it entered into an agreement to be acquired by Canada Pension Plan Investment Board (CPP Investments) and Global Infrastructure Partners (GIP). The two would disperse $67/share to shareholders and assume Allete’s debt. 

Following the acquisition, Allete would become a private company, no longer traded on the New York Stock Exchange. The sale is scheduled to close next year and requires approvals from shareholders, Minnesota and Wisconsin regulators, FERC, the Federal Trade Commission, and possibly others.  

In a press release, Allete CEO Bethany Owen said the transaction would grant Allete “access to the capital we need” to serve customers and hit clean energy targets as the fleet transitions. 

“CPP Investments and GIP have a successful track record of long-term partnerships with infrastructure businesses, and they recognize the important role our Allete companies serve in our communities as well as our nation’s energy future,” Owen said. “Together, we will continue to invest in the clean energy transition and build on our 100-plus-year history of providing safe, reliable, affordable energy to our customers.” 

Allete CEO Bethany Owen | Allete

Allete’s Minnesota Power, which serves about 150,000 residents and industrial customers across 15 municipalities, must reach Minnesota’s 100% carbon-free electricity mandate by 2040. 

Allete also boasts clean energy developer Allete Clean Energy and North Dakota-based wind operator Allete Renewable Resources in addition to BNI Energy in North Dakota; Superior Water, Light and Power in Superior, Wis.; and distributed solar energy developer New Energy Equity. 

Owen framed the transition to private ownership as a positive development, allowing Allete to draw on its owners’ financial resources instead of having to issue equity in the markets. She said, “strong partners will not only limit our exposure to volatile financial markets, it also will ensure Allete has access to the significant capital needed for our planned investments now and over the long term.”  

CPP Investment Board has about $591 billion Canadian dollars (about $432 billion USD) in assets; it oversees the retirement funds for approximately 21 million Canadians. GIP manages $112 billion with a focus on energy, transportation, digital infrastructure, and water and waste management. GIP is set to provide 60% of the equity to purchase Allete, with CPP Investments providing the remaining equity.  

Earlier this year, BlackRock announced it plans to acquire GIP for $3 billion of cash and approximately 12 million shares of BlackRock common stock. That negotiated deal hasn’t been finalized and is awaiting FERC approval (EC24-58). BlackRock already owns 13.55% of Allete.  

Minnesota regulators appeared apprehensive of Allete’s reclassification as a private company owned by investment firms during a special planning meeting May 9 discussing the possible sale.  

There, Owen emphasized the acquisition wouldn’t mean a change in day-to-day operations or customer rates. In the press release, Allete said its headquarters, leadership, workforce, compensation and charitable contributions would remain undisturbed. 

“Allete is a relatively small company doing big, important things,” Owen told regulators, adding that becoming a privately held company will help it raise more than double its current, roughly $3.4 billion market value for new infrastructure projects.  

Owen said Allete will file a petition for approval of the sale with the Minnesota PUC and the Public Service Commission of Wisconsin sometime in July.  

GIP founding partner Jonathan Bram said he’s certain regulators will thoroughly evaluate the acquisition’s details.  

“There haven’t been a lot of acquisitions like this in front of the commission,” Minnesota Public Utilities Commission Chair Katie Sieben said. She asked how the sale would affect Allete’s transparency.  

Minnesota Power Vice President of Regulatory and Legislative Affairs Jennifer Cady said even though Minnesota Power wouldn’t have to make SEC filings going forward, transparency would continue through rate cases and FERC Form 1 filings, alongside other FERC filings. Cady also said the PUC could require more reporting as a condition of the sale.  

Katherine Hinderlie, manager of the Residential Utilities Division at the Minnesota Office of the Attorney General, said the likely amount of protected data in the sale means there’s a good chance it will become a contested proceeding.  

Commissioner Hwikwon Ham said he worried that investor firms could lobby to weaken Minnesota’s “strong” regulatory model.  

GIP representatives said they’re happy with Minnesota’s regulatory model and don’t plan to influence changes.  

Allete has said that Minnesota Power and Superior Water, Light and Power will continue as “independently operated, locally managed, regulated utilities.”  

Minnesota Power is partial owner in a proposal to build the gas-fired Nemadji Trail Energy Center in Wisconsin. Plans for the plant hit a snag in April when the city council of Superior, Wis., didn’t allow necessary zoning changes for construction to begin. (See City Council Vote Stalls Planned Wisconsin Gas-fired Plant.)  

After announcing its sale, Allete canceled its first-quarter earnings call, scheduled for May 9.  

In the press release, GIP CEO Bayo Ogunlesi said it and CPP Investments “look forward to partnering to provide Allete with additional capital so they can continue to decarbonize their business to benefit the customers and communities they serve.” 

“Bringing together Allete, with its demonstrated commitment to clean energy, with GIP, one of the world’s premier developers of renewable power, furthers our commitment to serve growing market needs for affordable, carbon-free and more secure sources of energy,” Bayo said.  

Concerns over the BlackRock Connection

The announcement doesn’t sit well with a nonprofit consumer advocate. Public Citizen Energy Program Director Tyson Slocum said the pending sale of GIP to BlackRock means that BlackRock — “a totally different animal” — would be the one to acquire Allete. 

Public Citizen said it plans to lodge a protest with FERC over BlackRock’s takeover of GIP considering the Allete deal.  

Allete would “lose significant transparency” under its new ownership, Slocum predicted, and could be “consumed into BlackRock’s black box” if the world’s largest asset manager successfully obtains GIP.  

Slocum said he expects GIP and CPP Investments to agree to short-term commitments along the lines of reducing rates, shielding customers from transaction costs and possibly decarbonizing Allete’s fleet faster. However, he said impacts in the long run are murkier and entirely up to the new owners.  

“The long-term issue of the utility going private can’t be undone. That’s the big issue here,” Slocum said in an interview with RTO Insider. “If BlackRock is ultimately the owner, they can do whatever they want with their asset. This is a really, really serious move by BlackRock. Whatever assurances the companies are giving, you’re losing transparency at the holding company level.”  

Slocum said SEC filings are not on par with FERC Form 1 filings, with the former occurring at the holding company level while the latter are at the franchised utility level. Comparing detailed SEC disclosures to FERC and state filings is a “tired talking point that is factually inaccurate,” he said.  

Slocum said nothing is stopping the new ownership from creating numerous LLCs to obscure investment decisions. It could have state commissioners playing “whack-a-mole” trying to regulate financial activities, he said.  

Slocum said he worried that investor firm ownership would trade the existing influence of everyday shareholders to the “wealthiest 1% of the planet.” He noted only a handful of utilities with captive service areas are privately controlled, including Puget Sound Energy, El Paso Electric, Cleco and Duquesne Light Co. 

Slocum recommended the Minnesota PUC require BlackRock representatives attend upcoming meetings.  

“Missing at that conference today was BlackRock,” he said of the PUC’s special planning meeting. “It looks like state regulators haven’t wrapped their heads around this. Whatever hearing Minnesota has next, they must have BlackRock there.”  

BlackRock thus far has styled itself to FERC as a passive minority holder of utilities, Slocum said, and ownership of GIP would change that. He said federal agencies might consider splitting BlackRock in two so it can maintain both passive and active ownership of utilities.  

“I have no idea how you navigate that unless you force a divesture,” Slocum said.  

Slocum also said BlackRock should abstain from the shareholder vote for GIP and CPP Investments to acquire Allete. Although BlackRock currently owns shares, participating in the vote would constitute a “clear conflict of interest” given its expected purchase of GIP. 

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ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%

ISO-NE’s proposed resource capacity accreditation (RCA) updates would result in an estimated 11% increase in capacity market revenues, the RTO told the NEPOOL Markets Committee on May 7. 

Despite the overall increase, ISO-NE projects revenues to vary significantly based on resource class. The modeling showed that compensation for gas, dual fuel, energy efficiency, solar and imports would increase, while revenues for oil, energy storage, active demand response, wind and hybrid resources would decrease. 

The RTO also estimated that the RCA updates would reduce the loss-of-load expectation by about 38%. 

Initially introduced in 2021, the RCA project is intended to better align ISO-NE’s capacity market with the reliability contributions that different resources provide to the grid. Accreditation values would be based on a given resource’s expected output during the hours of greatest reliability risk. 

The RTO emphasized that the revenue results are dependent on the modeling assumptions and are likely to change as the resource mix and seasonal risk profile shifts. The RTO’s modeling indicates that near-term reliability risks are concentrated in the summer, and it projects that winter reliability risks will rise dramatically as heating electrification intensifies and winter peak loads will surpass summer peaks in the mid-2030s. 

The seasonal risk balance likely significantly affects the revenues projected for gas-only resources. While one of the main drivers of the RCA project was to better account for gas constraints during winter months, ISO-NE projects that the changes will increase gas-only resources’ revenues by 11% (coincidentally). This increase is attributed in part to the concentration of risks in the summer, when gas resources face minimal constraints, ISO-NE said. As winter reliability contributions become more important, gas constraints will have a greater impact on capacity accreditation, likely reducing revenues. 

The design of the capacity auction could also significantly change before the RCA updates are implemented. 

ISO-NE is proposing to shift its capacity auction from a forward annual design, with the auction for each yearlong capacity commitment period (CCP) held over three years in advance, to a prompt seasonal design, with auctions held much closer to the CCP, which would be broken up into seasonal segments. 

If FERC accepts ISO-NE’s proposal to delay Forward Capacity Auction 19 an additional two years, the RTO “will focus on evaluating scope and phasing of work for a combined accreditation design with a seasonal/prompt capacity market to implement for CCP 19 and would target discussing initial scope considerations with the MC in July,” said the RTO’s principal analyst, Dane Schiro. 

Despite the uncertainties, the RTO’s presentation provides the most detailed look to date at how the changes will ultimately impact resource compensation. 

ISO-NE projects dual-fuel resources to have the largest increase in total revenue, about $78.3 million (19.8%), followed by a class of non-intermittent resources including coal, nuclear and wood-burning generators at $50.6 million (29.1%); gas-only resources at $38.7 million; energy efficiency at $36.5 million (38.3%); imports at $22.5 million (81.1%, the largest percentage increase); and non-intermittent hydro at $16.1 million (29.4%). 

RCA revenue results by resource class | ISO-NE

Meanwhile, ISO-NE estimated that energy storage (including both batteries and pumped hydro) would have the most significant decrease in revenue, about $58 million (36.7%), followed by oil-only resources at $12.8 million (11.9%), hybrid resources at $6 million (52.1%, the largest percentage decrease), active demand response at $5.8 million (23.2%) and wind at $4 million (8.7%). 

Alex Chaplin of New Leaf Energy told RTO Insider the company is concerned that the projected revenues indicate the updated accreditation methodology may undervalue storage resources. 

“Some New England states have energy storage goals and have implemented (or are working to implement) incentive programs for storage to help address the ‘missing money’ problem batteries face,” Chaplin wrote in an email. “We fear that a significant reduction in capacity revenues will worsen the missing money problem and negatively impact storage deployments in the region.” 

Aleks Mitreski of Brookfield Renewable expressed perplexity about why storage resources experienced such a significant reduction in capacity revenues relative to fossil resources, adding that the differences may stem from how ISO-NE models the physical parameters of various resource classes. 

“Pumped storage resources that operate every day receive a sizable capacity payment reduction of 36%, while oil units that run a few days of the year only get a 12% payment reduction,” Mitreski told RTO Insider.