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November 14, 2024

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EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand

The burgeoning power demand from data centers and artificial intelligence can be met by other means than new natural gas-fired power plants that could hinder state and local emission-reduction goals, according to a new report from the Electric Power Research Institute (EPRI). 

The centers’ insatiable appetite for electricity could more than double by 2030, the report says; so, tech developers and utilities should work together to turn the passive demand of these megawatt-guzzling facilities into grid assets, by using their backup generators to provide system reliability and flexibility.  

“The data centers all have 100% backup generation on site” — usually diesel generators — “to prevent catastrophic failures,” said David Porter, EPRI’s vice president for electrification and sustainable energy strategy. “The backup generation has the ability to function as a grid resource in times of need; it doesn’t have to be long term.” 

But creating these “shared energy” systems first will mean gaining data center willingness to set them up by addressing industry fears about how any use of their backup power might affect the reliability of their own operations, Porter said. In addition, utilities also will have to offer “the right incentives financially to the data centers to make it worth their while to participate in a program like that,” he said. 

EPRI’s other options for keeping data center demand growth at lower levels include improved energy efficiency and better forecasting for new centers and the power they will need. 

“Forecasts need to make better projections describing new point load locations, magnitudes and timing alongside better techniques for making decisions ― to build or not build long-lead-time infrastructure ― while facing the economic, regulatory and political uncertainty associated with siting these large [centers],” the report says. 

EPRI’s research and recommendations stand in contrast to those recommending pushing back the closure of some fossil fuel-fired plants and adding new gas generation to deal with the load. 

The prime example is Virginia, which boasts of having the largest concentration of data centers in the world in its northern, D.C.-area suburbs — the so-called “Data Center Alley” in Loudoun County. Local concerns center on the environmental impacts of the thousands of diesel backup generators already located at the centers and a new 500-kV transmission line being planned by PJM, as well as likely increases on residential utility bills. 

The 2020 Virginia Clean Economy Act requires Dominion Energy, its largest investor-owned utility, to deliver 100% of its power from renewable sources by 2045. 

The utility’s most recent long-term integrated resource plan sees most new generation between now and that deadline coming from solar and storage. But among the options considered in the IRP, Dominion’s preferred plan keeps some coal-fired generation online through 2030, converts a 415-MW coal plant to natural gas and builds at least three new natural gas plants with a combined capacity of 1,708 MW, with the final, 523-MW facility coming online in 2049. 

The EPRI report counters with a focus on “scalable clean energy supply,” primarily solar, wind and storage. Tech giants like Amazon, Apple, Google, Meta and Microsoft — known in the industry as “hyperscalers” — are procuring thousands of megawatts of new clean energy to cover their operational power demands, the report says. 

Top data center developers ― including Iron Mountain, Digital Realty Trust, QTS Realty Trust and Switch ― similarly have increased their procurement of clean energy, according to a 2023 report by S&P Global. Google, Microsoft and Iron Mountain have led industry efforts to match their power demand with carbon-free generation hour for hour 24/7. 

In the long term, many in the industry are looking toward small modular reactors as an option for the kind of clean, dispatchable power that data centers need, but Porter does not expect the technology ― now in the early stages of demonstration and deployment ― to reach broad, commercial scale until the 2030s. 

The coming clash between data center and AI load growth and the clean energy transition “is not going to be easy,” he said. “Even solar and wind resources that can really help with zero-carbon electrons … are not coming online as fast as might be needed to support this and other growth.” 

To keep electricity abundant, reliable and affordable, Porter said, “optionality is still our best opportunity for that, so, I think a collection of different types of resources.” Data centers might replace their backup diesel generators with a mix of renewables and energy storage, biofuels or green hydrogen. 

Just How Much?

The EPRI report also provides a detailed picture of the power demand of data centers, their uneven geographic distribution and the dramatic impact AI is having on growth trends. 

While a regular Google search eats up about 0.3 Wh of power, a similar search via AI takes close to 10 times as much electricity: 2.9 Wh. The appetite of generative AI, which can produce images, video or text, multiplied by millions of worldwide users, could “lead to a step change in power requirements,” the report says. 

Hyperscale data centers require 100 MW or more of power ― the equivalent demand of 80,000 homes ― and can be built and brought online within two years. 

Virginia’s data centers currently represent 25% of the state’s electricity consumption. But given ongoing high growth, EPRI estimates data center power demand in the state could almost double by 2030, to 46%. According to the Virginia Economic Development Partnership, the state already has 150, or 35%, of the world’s hyperscale data centers. 

On a national level, data centers accounted for 4% of electricity consumption across the U.S. in 2023. EPRI’s report models low-, moderate-, high- and higher-growth scenarios, with data center demand either edging up to 4.6% of total consumption by 2030 (low growth) or more than doubling to 9.1% (higher growth). 

The EPRI study anticipates the power demand of data centers could edge up by 4.6% or more than double to 9.1% by 2030. | EPRI

Virginia and 14 other states spread across the U.S. make up 80% of that demand, the report says. Consequently, forecasts of demand growth should be looked at regionally, Porter said. Decisions about where data centers are located may depend on “several key things … like what’s the communications infrastructure, what’s the price of electricity, what’s the price of land and is there still workforce available in the area?” he said. 

“Power availability is also part of that, and depending on where you are, in some parts of the country, it’s easier to get large blocks of power than others,” he said. 

While not specifically mentioned in the report, grid expansion must be part of the bigger picture on meeting data center power demand, Porter said. Hyperscale centers are “not going to be distribution-served facilities; [their power] will come from transmission,” he said. “That’s part of why there’s a need for better communications, particularly with the near-, mid- and longer-term [planning] from the data centers to the utilities,” given the yearslong process for planning and permitting new transmission lines. 

Grid-enhancing technologies ― such as upgrading existing lines with advanced conductors ― should be looked at as both interim and longer-term solutions for expanding transmission capacity, he said. 

Energy Efficiency

Historically, data centers have been able to offset their increasing power demand through efficiency, but with the U.S. economy and data centers growing at unfamiliar and accelerated speeds, whether efficiency can keep up remains uncertain.

EPRI’s research has included “interesting conversations with hyperscalers,” Porter said. “They still firmly believe that as their capabilities to architect what happens inside data centers, coupled with continued improvements in chips … the [electricity] demand for data centers will not grow in huge leaps and bounds.” 

Major efficiency gains may be made in facility cooling ― typically air conditioning ― which traditionally has accounted for 35% of data center power demand, the report says. Newer cooling technologies that use liquids to absorb and dissipate heat can cut demand by up to 50%. 

Using system redundancy at data centers is another option, Porter said. Centers may have backup or redundant servers “that are running at 50% of their capability,” Porter said. “The challenge with this is that a server running at 50% of capacity uses as much energy as it would if it were running at 100% capacity.” 

Other approaches include “pruning”: cutting unnecessary elements in neural networks, which reduces computational complexity — and energy demand — while “maintaining robust performance,” the report says. Power capping reduces energy use but may slightly decrease speed by 3 to 4%, Porter said. 

A recent webinar sponsored by Canary Media also looked at the role of wholesale markets in responding to the increasing power demands of data centers and the potential inefficiency of non-RTO markets such as the Southeast. 

“If we had an RTO that covered the whole region, you wouldn’t be building three or four gas plants for the same load,” said Maggie Shober, research director at the Southern Alliance for Clean Energy. “The flip side of that is we don’t have reserve margin sharing here in the Southeast,” so individual utilities may be predicting a need for larger reserves. 

Shober and other speakers at the webinar zeroed in on the Georgia Public Service Commission’s recent approval of an updated IRP for Georgia Power after the utility predicted 17-fold growth in demand by 2030, largely from data centers. The new plan includes a power purchase agreement that would help keep a coal-fired plant in Mississippi online through at least 2028, along with three new, company-owned gas-fired plants with a total capacity of 1,400 MW. 

The Clean Energy Buyers Association (CEBA) was able to push Georgia Power to a last-minute addendum to the IRP, committing the utility to develop a new program that allows large-demand customers, like data centers, to bring their own clean power into the utility’s system, said Priya Barua, CEBA’s senior director for market and policy innovation. 

The utility has agreed to work with CEBA and other customers to design the program, which will be included in its 2025 IRP, Barua said. “I think it’s an important first step for opening a new path for Georgia to have kind of expanded options for meeting load growth” in the absence of an organized market. 

Shober sees the Georgia Power and Dominion IRPs as a “trial run because we know this kind of load is coming. … My worry is that this sort of panic reaction and kneejerk reactions by a number of utilities means that we don’t have the right processes in place and the right level of transparency to meet that kind of load” with proactive planning and a diverse set of options. 

Simon Mahan, executive director of the Southern Renewable Energy Association, said such changes should include a hard look at the value different resources bring to the grid. “Historically, natural gas, coal [and] nuclear resources … would get 100% accreditation. The utilities would just assume, ‘Oh yes, they’re always going to be around because we can turn them on and off.’ 

“The reality is showing that’s not the case. So, we need to appropriately accredit those resources as we’re also properly accrediting wind, solar [and] batteries.” 

Barua agreed that new, more holistic thinking is needed — and maybe taking some risks. “We’ve reached the stage where we’re going to need to be uncomfortable to come up with the right kinds of solutions for the challenge that the system is facing right now.” 

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Appeals Court Overturns Wis. Ban on DR Aggregation in MISO

An appeals court has toppled Wisconsin’s longstanding ban on aggregators of demand response participating in wholesale markets.  

The District IV Court of Appeals for Wisconsin agreed with the Midwest Renewable Energy Association (MREA) that the Wisconsin Public Service Commission’s circa-2009, temporary order prohibiting customers and aggregators from selling demand response in MISO was procedurally improper (2021CV41).  

The court said in a May 31 ruling that the original order in fact meets the definition of a rule according to Wisconsin law and the Wisconsin PSC should have proposed and adopted it using different procedures. Judges called the order “invalid and unenforceable” and reversed a circuit court’s decision to dismiss a challenge to it.  

“There is no dispute that, in issuing the order, the commission did not comply with the pertinent rulemaking procedures set forth” in Wisconsin statute, the appeals court said.  

The 15-year-old order — which bars retail customers of Wisconsin’s largest utilities, as well as third-party aggregators, from selling load reductions in wholesale markets — was considered temporary when commissioners approved it. It was to remain in effect until regulators rescinded it through another order, which to date hasn’t happened.  

At the time, commissioners reasoned they needed time to analyze the financial implications of demand response aggregations on ratepayers and investigate how such aggregations would affect utility-sponsored demand response programs and resource planning.  

MREA first challenged the order with the Portage County Circuit Court in 2021.  

The Wisconsin PSC asked the appeals court to sustain the dismissal. It said MREA failed to challenge the order within 30 days of issuance and didn’t exhaust all administrative remedies first because it didn’t ask regulators to reopen the docket to rescind or alter the order. The commission also argued it has main jurisdiction over the issue.  

But the court said the order isn’t an administrative decision according to Wisconsin law and isn’t subject to the 30-day limit. It noted Wisconsin law allows plaintiffs to petition courts “for declaratory relief without first asking the agency to rule” on claims and dismissed the commission’s contention that the PSC was exclusively equipped to handle the matter.  

“[MREA’s} argument that the order is an invalid, unpromulgated rule involves only issues of law that fall squarely within the circuit court’s expertise,” the court said. It remanded the case to the circuit court with instructions for the court to deem the temporary order invalid.  

The court similarly wasn’t persuaded by the Wisconsin PSC’s argument that the order didn’t amount to the “general application” of a rule. Wisconsin considers rules generally applicable when the class of constituents is “described in general terms and new members can be added to the class.” 

The court agreed with MREA that since the order applied to all existing and future retail customers of Wisconsin’s four largest utilities and all existing and future third-party aggregators, it met the definition of a rule.  

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MISO Pursuing More Dynamic Regulation Reserves

CARMEL, Ind. — MISO said a riskier operating environment means it needs a more nuanced approach to its regulation reserve requirements.  

At its May 30 meeting, MISO’s Reliability Subcommittee agreed to take up a project to make regulation reserves more dynamic. MISO plans to design a process with stakeholders to quantify operating uncertainty and prescribe the requirement depending on anticipated risks.  

Manager of Operations Risk Assessment Congcong Wang said historically, MISO’s regulating reserve relies on a static requirement “that may not be effective in managing the increasing and varying uncertainty in the 4-second to 5-minute time frame” given MISO’s changing resource portfolio. She said MISO needs a more calibrated approach that involves a requirement that varies by hour and season in either high, medium or low amounts. MISO currently carries about 400 MW of regulation reserves. 

“Appropriately setting its requirement is critical for the product to work effectively,” Wang said.  

MISO’s ancillary service market provides regulating reserves, which are designed to maintain frequency regulation up to 5 minutes at a time. 

Wang said MISO expects to begin work in earnest on the initiative in the third quarter. She said the shift shouldn’t require completely new software or a filing with FERC to edit the MISO tariff.  

The regulation reserve project likely will spawn a sister task: MISO said it also plans to update the uncertainty component of its ramping product to be more dynamic. Wang said while MISO’s ramp capability requirement’s variation component is dynamic, its uncertainty component is “hard coded as a static parameter” and has been updated only once in 2021 since the product’s inception in 2016. MISO would like to come up with a method to quantify uncertainty over the next 10 to 30 minutes and use that in its anticipated ramp-up needs.  

Wang said the move would have MISO’s software more accurately predicting when it needs ramp-up capability and sending out scarcity pricing to incentivize resources. She said the goal is to have MISO more clearly signaling beforehand when it could use flexibility.  

MISO last year essentially disabled its down-ramp product in an acknowledgement that it virtually never requires it.   

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MISO to Cut Conductor-only Work from Competitive Bidding

CARMEL, Ind. — MISO said after its experience with its first long-range transmission portfolio, it no longer wants to open simple, conductor-only projects to its competitive bidding process.  

MISO competitive transmission lead Alex Monn said the amount of time and effort that went into opening some straightforward, long-range transmission plan (LRTP) lines to competition wasn’t worth the outcome. 

“Applying the competitive transmission process to projects that solely entail installing new conductor is costly and inefficient,” Monn said during a May 29 Planning Advisory Committee meeting.  

MISO evaluated five competitive transmission projects from the first cycle of its $10 billion long-range transmission plan. It said two rounds of competitive bidding were composed solely of installing new conductor on replaced transmission structures. For those, Monn said MISO developed requests for proposals and formally selected developers when only the incumbent transmission owners applied to string the lines in both cases. (See MISO Selects Ameren, Dairyland to Build 3rd and 4th LRTP Competitive Projects.) Neither project exceeded $25 million.  

MISO plans to make a FERC filing in July to designate the installations of conductor on already replaced transmission structures as upgrades, not projects eligible for bids. 

Currently, the applicability of MISO’s competitive process varies based on structure design. The RTO already considers work a mere upgrade when circuit needs to be strung on existing transmission structures that have spare positions available. However, it allows competitive bidding on the conductor portion of the job when transmission structures don’t have spare positions and need to be replaced to make space for new capacity. 

Monn said extending MISO’s upgrade definition to both scenarios and eliminating bidding would simplify its competitive transmission process.  

MISO hopes to implement the change in September. It’s collecting stakeholder reactions on its plan through mid-June. 

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Vistra Joins Rush for Dispatchable Generation Loans

Vistra, Texas’ largest generator, said May 30 it plans to add nearly 2 GW of gas-fired capacity to the ERCOT grid over the next year by investing in existing power plants to increase their output. 

The capacity additions will help meet ERCOT’s and the Public Utility Commission’s desire for more dispatchable (i.e., thermal) generation necessary to meet the state’s growing demand. 

“Texas is in the enviable position of experiencing sustained economic growth, which includes rapidly increasing power demand as a result of population growth and electrification activities in a number of areas, including transportation, data centers, manufacturing and industrial activities,” Vistra CEO Jim Burke said in a news release.  

Vistra said it was filing a notice of intent to seek disbursements from the $5 billion Texas Energy Fund (TEF)’s Generation Loan Program. The program is designed to drive more dispatchable energy to the ERCOT system.  

The PUC said June 1 it had received 125 notices of intent totaling $38.9 billion in financing for 55.9 GW of proposed dispatchable projects, fulfilling the hopes of some participants that the TEF would be oversubscribed (56455). 

Formal applications now can be submitted by entities that submitted a notice of intent. Completed loan applications must be filed by July 27. The first disbursements, financing up to 60% of a loan, should be issued by Dec. 31, 2025. 

The commission established the TEF in March because of state legislation passed last year. Qualifying projects must add at least 100 MW of dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

Through Luminant, its generation subsidiary, Vistra plans to: 

    • Build up to 860 MW of advanced, simple-cycle peaker plants in West Texas, supporting the increased power demands of the state’s oil and gas industry. 
    • Repower its coal-fired Coleto Creek Power Plant as a gas-fired unit and use the existing infrastructure to provide up to 600 MW of capacity when the coal plant retires in 2027 to comply with EPA rules. 
    • Complete several upgrade projects at its existing gas plants, adding more than 500 MW of summer capacity and 100 MW of winter capacity. 

Vistra said its quick-start gas units would help back up the grid when renewable resources are not available and battery storage resources have reached their limits. Nearly half of the capacity would come online this summer and the remainder next summer. 

All three projects are based on market reforms passed during the 2023 legislative session that include new ancillary services, the performance credit mechanism and an effective reliability standard. The company said implementation could offer the regulatory framework needed to incentivize long-term investments in the grid. 

“Since the market opened to competition, over $100 billion has been invested by a wide range of investors in a variety of power generation technologies to meet the growing needs of Texans,” Burke said. “The ERCOT market has a history of attracting generation owners who put their capital at risk when there are investment signals.” 

The projects are contingent upon other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation, Vistra said. 

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Report: Home Retrofit Benefits Maxed by Combining Fed Funds with Other Sources

The American Council for an Energy-Efficient Economy, AnnDyl Policy Group and Building Performance Association published a paper last week showing how states can maximize the impact of federal funds for home energy retrofits. 

“Federal funding for residential energy retrofits will make a huge difference, but what’s most important now is that states put it to use effectively,” said ACEEE Buildings Program Senior Fellow Jennifer Amann, who co-authored the report. “Existing programs lay the groundwork for improved retrofit efforts and market approaches that will make it easier and more affordable to retrofit housing to enhance comfort, improve health, and cut energy costs and climate-warming emissions. With the new funding now available, states can improve on these programs and continue to innovate.” 

The federal government has put up $53 billion in rebates, grants and other incentives, on top of tax credits and deductions for home energy retrofits that are not capped. The Infrastructure Investment and Jobs Act and the Inflation Reduction Act offered billions in funding to agencies including the departments of Energy and Housing and Urban Development, EPA and the IRS. The biggest chunk is $27 billion from the IRA for the Greenhouse Gas Reduction Fund administered by EPA. 

An additional $30 billion is available from nonfederal sources, including state and local programs, utility offerings and housing funds. The biggest chunk of those funds comes from banks which on average put out $24 billion in loans that can be used for upgrades, while utility programs come in at just under $2 billion across the country. 

The funding can help make up for the fact that homeowners and landlords often have less access to capital than the owners of commercial buildings, which can cause them to defer efficiency investments. 

Combining the federal funds with other sources can help states increase the overall impact and invigorate longer-term transformation for the home retrofit industry. States can successfully combine funding sources by reaching out to key stakeholders to identify program gaps, reviewing and expanding their own goals, and matching new and existing program objectives. 

States have to ensure that funds that have separate requirements are not blended together, but combining funds can make retrofits more successful, and programs that appear as a single incentive are less confusing for consumers, the report said. 

The impact of the federal programs is going to vary by state because they all have different programs themselves, for their utilities and from other sources. 

“Some states have access to deep funding streams from ratepayer programs, government agencies with a wealth of capacity and history in clean energy, and access to secure energy data, whereas other states are beginning now with none of this existing infrastructure,” the report said. “However, states with less history are also less burdened by past decisions and precedents in building their future policies and innovations.” 

The report suggests that states make customer utility data available in order to take full advantage of the federal funds. 

“Secure access to their own energy use data provides utility customers with information they can use to change their behavior and to partner with third parties (e.g., contractors) to reduce their energy use,” the report said. “Advanced metering infrastructure facilitates data access; federal and state governments are working with utilities to develop best practices to support data access while addressing privacy concerns.” 

The report also suggests incorporating grid flexibility to bridge traditional and “dynamic” efficiency, meaning smart thermostats, grid-enabled water heaters and other products that can offer flexibility for the grid. 

The current federal investment can support longer-term market transformation so that eventually, the residential retrofit agency can be self-sustaining absent incentives and other market interventions. 

“Key steps for market transformation include consideration of long-term goals in program design; collaboration with contractors, distributors and suppliers to build a robust industry infrastructure; and demonstration of the long-term value of retrofit investments,” the report said. “By considering opportunities to drive lasting changes in both market supply and demand, programs can generate benefits well beyond the life of the program.” 

Prioritizing historically underserved communities is important, with the report noting that renters have long seen much fewer benefits from such programs. Bringing programs to multifamily and single-family rental homes while protecting renters themselves from displacement is possible, it said. 

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NV Energy Confirms Intent to Join CAISO’s EDAM

NV Energy intends to join CAISO’s Extended Day-Ahead Market (EDAM), an official with the utility said May 31, notching a major win for the ISO in its competition with SPP’s Markets+ day-ahead offering in the West. 

The announcement confirms what multiple sources have recently told RTO Insider: that the Nevada-based utility had disclosed in private meetings that it had decided on the EDAM and would make that news public upon filing its integrated resource plan with the Public Utilities Commission of Nevada (PUCN). (See NV Energy to Join CAISO’s Extended Day-Ahead Market.) 

Speaking at a monthly meeting of the Launch Committee of the West-Wide Governance Pathways Initiative, Dave Rubin, NV Energy’s federal energy policy director, acknowledged the accuracy of the press reports and said the utility submitted its IRP — which includes the request — to the PUCN that same day. 

“We will indicate NV Energy’s intention to request authorization from our commission later this year to join the EDAM,” said Rubin, who also is a member of the Launch Committee. 

Rubin said the Nevada process for joining a day-ahead market is different from some other Western states because state law requires a utility to obtain “formal authorization” from the utility commission to move forward with a market decision.

The decision is a key victory for the EDAM because NV Energy’s control area occupies a central position in CAISO’s Western Energy Imbalance Market (WEIM), providing a key corridor for wheel-throughs of energy between the market’s California participants — including the ISO — and PacifiCorp’s massive balancing authority area in the inland West. 

Brian Turner, a Pathways Launch Committee member who leads Advanced Energy United’s regulatory engagement in the West, called NV Energy’s decision to join EDAM a “big deal” based on the “critical mass” it brings and the overall “functioning of the grid.” 

NV Energy’s decision moves Nevada from “being on the periphery of a possible Markets+ to being at the center of what will come with EDAM,” Turner said in an interview. “So, it’s a very big deal that they’re joining.” 

The Brattle Group study released this year that showed NV Energy could earn as much as $149 million in benefits from participating in EDAM noted that the scale of the utility’s benefits is heavily correlated with the shape of the market footprint “due to its large amount of transfer capability and centrality” in the Western Interconnection.   

“NVE benefits tend to be higher when it is central to the market and facilitates transfers within the market,” the study found in assessing outcomes based on multiple footprints for both EDAM and Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

NV Energy’s decision in favor of EDAM also is significant for the work of the Pathways Launch Committee, which voted May 31 to advance step 1 of its CAISO governance proposal to the ISO’s stakeholder process. The proposal calls for CAISO to alter its tariff to elevate the “joint” authority the WEIM’s Governing Body currently shares with CAISO’s Board of Governors over WEIM matters to “primary” authority.  

Under the plan, the ISO would file that change with FERC only after the EDAM secures implementation agreements with a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO’s annual load in 2022.  

So far, only PacifiCorp has fully committed to signing such an agreement, but the EDAM also has solid commitments from Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric. NV Energy’s commitment would position CAISO to trigger that change. 

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Panel Provides Update on Energy Storage in Mass.

Battery storage remains largely reliant on state programs and subsidies to be viable in Massachusetts but increasingly could stand on its own as renewable resources proliferate, a panel of energy storage experts said during a webinar May 30. 

“As we further decarbonize our grid, these products become ever more important,” said Tom Ferguson, energy storage programs manager at the Massachusetts Executive Office of Energy and Environmental Affairs. 

Ferguson noted that battery storage’s ability to balance the grid will become more valuable with more intermittent resources on the system. He emphasized that long-duration storage pairs particularly well with offshore wind, which could help drive the business case for long-duration technologies. 

While credits associated with Massachusetts’ Clean Peak Energy Standard (CPS) make up a major portion of the revenue for new storage resources today, “over time, the hope is that the need for incentives will decrease,” Ferguson said. 

He cited a December 2023 report commissioned by the state that found storage likely will be “a cost-effective element of mid- and long-term resource portfolios” but needs increased state support in the near term to scale up quickly enough to meet the state’s goals. 

“Additional state programs will be required, as will dedicated efforts to reduce existing financial, technological, supply chain and operational barriers to deployment,” the report found. 

Responding to a question about Massachusetts’ progress toward its goal of deploying 1,000 MW of storage by the end of 2025, Ferguson said the state currently has “a little over 500 MW. … We’re hoping we’ll hit that target.” 

Chris Sherman, senior vice president at Cogentrix Energy, discussed the company’s ongoing efforts to replace the West Springfield Station, which retired in 2022, with battery storage. 

The first phase of the project consists of a 45-MW battery facility with a projected in-service date of mid-2025, while the company is “in the process of designing Phase 2, which will likely be an additional 105 MW,” Sherman said. 

“The clean peak standard is the basis for the project,” Sherman said, noting that it accounts for about 40% of the project’s projected revenue. 

Looming changes to how ISO-NE accredits resources in its Forward Capacity Market likely will further reduce the revenues available to battery storage from the wholesale markets, Sherman added. 

An ISO-NE analysis from early May indicated the in-development accreditation changes could result in a $58 million reduction in total capacity market revenues for storage resources. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

The changes are intended to better align capacity procurements with actual reliability benefits. Sherman said they amount to “a fairly significant derate,” adding that “we would need to have that [capacity market revenue] made up somewhere … [but] it was probably the least amount of our revenue; it was never a great revenue source.” 

Todd Olinsky-Paul, senior project director at the Clean Energy States Alliance, said the new accreditation framework likely will “push battery storage toward longer-duration resources.” 

Jason Viadero, director of engineering and generation assets at Massachusetts Municipal Wholesale Electric Co. (MMWEC), said the company has deployed storage to minimize its peak and save customers money without substantial support from state programs. Massachusetts’ municipal utilities are not subject to the CPS. 

“This is one specific use case that completely stands on its own economically,” Viadero said. “These systems are able to pay for themselves throughout the life of the system.” 

Growing electricity demand will make peak shaving increasingly important, Viadero said, highlighting the significant differences in ISO-NE’s cost projections for a 57-GW peak load system and 51 GW. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

Viadero said MMWEC is working to deploy “upwards of 50 MW” of energy storage in 2024 and 2025, with a greater focus on longer-duration storage going forward. 

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Calif. Officials ‘Cautiously Optimistic’ on Summer Reliability

California energy officials are “cautiously optimistic” about maintaining grid reliability this summer, with the state benefiting from above-normal snowpack and precipitation coupled with expectations for cooler temperatures in coastal regions.  

That was the assessment of multiple presenters speaking during a summer reliability workshop hosted by the California Energy Commission on May 29. 

But climate change is making it increasingly hard to ensure reliable grid conditions, and planners must remain vigilant to avoid outages such as those in 2020, CEC Vice Chair Siva Gunda said during the workshop. “In 2020, we had two [rolling] outages on Aug. 14 and Aug. 15 — something we hadn’t seen at that point in 20 years — and it has been a primary focus in California to ensure electric reliability as we move forward.”  

Maintaining reliability requires a host of responses to keep up with decarbonization efforts and a warming climate, including having flexible and dispatchable resources, especially during the critical sunset hours when solar rolls off the system, said David Erne, CEC deputy director of resource planning, reliability and emergency response. But this summer is looking better than last, he said.  

Weather Patterns

Zeroing in on weather conditions, Amber Motley, director of short-term forecasting at CAISO, highlighted that the central Sierra Nevada had above-normal snow water equivalent this winter, although California was at 67% of its snowpack average as of May 20, said Jeff Fuentes, deputy chief of fire intelligence at Cal Fire.  

But the Pacific Northwest “did not have as good of a snow year,” Motley said, resulting in abnormally dry to moderate drought conditions in many portions of Oregon and Washington.   

This summer also should mark a transition away from El Niño, which is associated with warmer sea surface temperatures in the Pacific Ocean and hotter, dryer conditions in the northern U.S., to La Niña, marked by colder sea temperatures, drought and warmer conditions in the South and heavy rains in the Pacific Northwest.  

“For the Desert Southwest, this is really critical,” Motley said. “Because of the position of … where the heat is focused to be, it’s expected they don’t get as much monsoon moisture, which leads to less precipitation, but also leads to less cooling for them in the evening hours. The key piece as we head into summer is really watching the position of that [heat] ridge.” 

Another factor to watch, Motley said, is above-normal sea surface temperatures in the Atlantic, leading to forecasts that hurricane season will be more extreme — which impacts conditions in the West.  

“That’s going to be critical to watch because if you have big hurricanes, when we get into the August and July time period, they will move up into the gulf, and they kind of act like a traffic jam to the atmosphere. So, that could allow a ridge to stay parked over the West and not move for a number of days.”  

Taking all these pieces into account, forecasters anticipate above-average temperatures in the Desert Southwest, interior California and Rockies regions and a low probability of above-normal temperatures in California’s coastal regions.  

California fire risk is low to normal, Fuentes said, but “normal” typically means one to two large fires in each of the state’s service areas in June, three in July and six in August. Additionally, the Pacific Northwest will see normal risk of significant fires until July, when areas of Central and Southeast Oregon may shift to above-average potential for wildfire.  

Reliability

Changing weather patterns aren’t the only significant challenge to ensuring reliability. Expedited resource builds coupled with delays and resource retirements also are having an impact, said Branden Sudduth, WECC vice president of reliability planning and performance analysis.  

“Over the last two-year cycle when we developed our reports, we saw about 5,000 MW worth of generation retirements being delayed,” Sudduth said. “A lot of states in the West are focused on making sure they have adequate energy, adequate resources over the next couple of years. But we just want to make sure that people are alert and aware that those retirements are still going to happen in the future, and we just need to keep our foot on the gas pedal when it comes to making sure that we get new resources developed, built and online.”  

Sudduth provided an overview of NERC’s 2024 Summer Reliability Assessment, which evaluates June through September. This year’s assessment showed that while all areas of North America have adequate resources for normal summer demand, British Columbia, California, Mexico and the Southwestern U.S. have an elevated risk of insufficient operating reserves and loss of load under “extreme conditions,” defined as demand meeting or exceeding the 90th percentile threshold of the region’s demand curve. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

The “good news,” Sudduth noted, is that no regions were identified as “high risk,” indicated as having insufficient operating reserves under expected conditions, for the upcoming summer.  

Focusing on the elevated risk identified for California and Mexico, the highest chance for load loss was the period ending at 7 p.m., though that totaled less than one hour. In the Southwest, the concern lay in the potential for a heat wave to increase the region’s probability of being unable to meet its operating reserve requirements.  

A broader reliability concern identified by WECC is the industry’s ability to keep up with the pace of development.  

“From January 2023 to June 2023, the Western Interconnection added around 14 GW of new generation capacity. Currently, we’re planned to add just over 17 GW” by summer, Sudduth said. “As we look at things such as supply chain delays and … we know there are workforce shortage issues, that’s really one of the challenges we face is can we build enough generation quick enough to meet our plans, and I assume that will continue to be one of our challenges in future years as the pace of generation builds [continues] to increase.” 

Christine Root, integrated resource planning and compliance supervisor at the California Public Utilities Commission, emphasized the rapid pace of resource development, with 18,500 MW of clean energy nameplate capacity coming online from 2020 to 2024, 5,700 MW of that last year — “the highest amount of clean energy on record for a given year thus far.”  

Ensuring reliability is dependent on long-term forward planning and procuring the volume of resources needed to support the evolving grid, Root added. The CPUC adopted a preferred system plan in February 2024, which estimates 55 GW coming online by 2035, 32 GW of which is expected to be solar.  

Though grid planners and forecasters presented a generally positive outlook for summer 2024, they continued to emphasize the importance of being cautious and vigilant.  

“Maintaining reliability is paramount and underscored by what we’re all collectively facing with the climate crisis,” said Christine Hironaka, senior adviser for energy for the office of Gov. Gavin Newsom.  

She noted that extreme heat events like the one in September 2022 are likely “to increase in frequency and intensity as time goes on.”  

“I think the good news is, last year … the grid did not have any major emergencies and I think the topline for me is we remain cautiously optimistic for this summer’s outlook,” she said.  

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Texas RE Sees Challenges in Resource Mix, Physical Security

Staff at the Texas Reliability Entity said in a webinar that the regional entity’s upcoming Reliability Performance and Regional Risk Assessment should show most performance metrics are “trending in the right direction,” although work still is needed in some areas. 

Texas RE produces the assessment each year as a supplement to NERC’s State of Reliability report, reviewing the performance of the state’s grid over the previous year. Both reports normally are released in June. Speaking at the RE’s regular “Talk with Texas RE” event May 30, Director of Reliability Services David Penney said the assessment has performed a valuable role since the RE started releasing it 10 years ago.

“We’re one of the few regional entities that puts a report like this together, that looks at both the regional performance from a reliability perspective, as well as a regional risk assessment to look at the risks that we face as a region,” Penney said. “We tried to tailor this report [to] … a target audience [of] industry stakeholders, industry executives, as well as policymakers, to [share] the key risks that we [see] as a region, as opposed to what you may see from other industries or other [regional] entities.” 

Penney observed that of the seven reliability performance metrics the RE tracks, more than half either were improving or stable in 2023 compared to the previous year. These include resource adequacy — where reserve margins show sufficient resource capacity, and Texas RE has observed “a very positive trend” in winterization since the February 2021 winter storm — transmission performance, and protection system performance, where the misoperation rate decreased in 2023 and remains below NERC’s overall misoperation rate. 

However, the RE did note several areas where monitoring is needed, such as resource performance, which analyzes generator outage rates, primary frequency response and balancing contingency events to measure generation performance. Penney noted that while the RE has seen improvement in PFR performance, there also has been a long-term increase in equivalent forced outage rate, indicating times when generators have experienced forced outages when the units were needed to meet load.

Texas RE also identified issues in grid transformation, which measures the developing challenges associated with the shift to renewable resources. Penney said the report will discuss the need to monitor the drop in solar performance in evening hours and how it impacts reliability, as well as the decrease in system inertia levels that may leave the grid open to disruption.

Along with these issues, Penney discussed the physical security risks to electric equipment, which have risen across most categories in recent years. For example, the RE counted 15 gunshot incidents involving power stations in 2023, up from three the year before. A similar increase was reported in theft incidents, while the number of intrusion events rose from 18 to 20. Penney said the number of physical security events has continued to rise this year, indicating “this is a risk that’s definitely not going away.”