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November 12, 2024

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Long-duration Energy Storage Seen as Key to Future Grid

Long-duration energy storage has emerged as key to enabling the continued growth of renewable energy. It also could help address the backlog of new transmission projects both in the U.S. and globally, say industry and Department of Energy experts. 

But there’s no consensus about the best way to store massive amounts of energy for more than a few hours or days, whether the technology is pumped storage, mechanical weights, compressed air or massive batteries. The 2030 DOE minimum storage target is at least 10 hours for utility-scale storage. (See DOE Targets 90% Cut in Cost of Long-duration Storage.)

“Given that there are so many different technologies that are being developed, it’s the government’s hope that we can try these out geographically as much as we can,” said Anna Siefken, a senior adviser in the Office of Technology Transitions at DOE, during a webinar with energy industry experts Wednesday presented by Madrid-based ATA Insights.

“We are not picking winners here. We’re trying to raise the floor, raise it so that everyone can participate in this market. But that does [require] off-takers. It takes people who are willing to go in on the risk, and the federal government is trying its best through any number of different programs to de-risk the technologies as much as possible,” she added.

Siefken also referred viewers to DOE’s Long Duration Energy Storage Report issued in March, one of a series of reports detailing the agency’s efforts to work with industry to commercialize clean energy technologies, particularly as an industrial strategy. (See DOE Reports Highlight 3 Technologies to Decarbonize U.S. Economy.)

“We’ve done clean hydrogen, advanced nuclear, carbon management and long duration energy storage, which is again why we’re here today.

“We were looking domestically at what are the barriers and challenges to commercialization of different technologies, and we wanted to create a credible fact base as well … [and] a language so that we can talk together about what we want to do, with long duration energy storage, in particular, for that report,” she said of the Liftoff Reports.

“We are pushing forward on clean energy technologies in a way that has not happened in the United States, ever. This is a moment in time. It’s very important. What we’re doing is trying to accelerate as many technologies forward as possible,” Siefken said.

Long Duration Storage Webinar (ATA Insights) Content.jpgClockwise from top left: Neva Espinoza, EPRI; Emily Fisher, Edison Electric Institute; Cristina Galan, ATA Insights; Julia Souder, Long Duration Storage Council; and Anna Siefken, DOE Office of Technology Transitions | ATA Insights

 

Julia Souder, CEO of the Long Duration Energy Storage Council, headquartered in Brussels, said backed-up transmission interconnection project queues have become a global crisis and developing effective and relatively inexpensive long-duration storage technologies could help while regulators work through the backlogs both in the U.S. and around the world.

Emily Fisher, general counsel for the Edison Electric Institute, agreed with Souder.

“One of the things that long-duration energy storage could do is defer some necessary investments in the transmission and distribution system. Not permanently, but they could create some flexibility in the transmission system that doesn’t currently exist. And that might help us get through some of our current backlog [while] trying to get more things interconnected to the grid, at least in the US,” she said.

The Storage Council was formed at COP26 “to initiate this $4 trillion marketplace and bring this diversity of thermal, mechanical, electrochemical and chemical technologies to the marketplace,” Souder said. “We have diverse technologies, and our membership spans over 20 countries and over 60 members. We’ve been growing because of … the diversity of long-duration storage, as well as the huge market opportunities.” She said the Storage Council has projected the world will need as much as 8 terawatts (8,000 GW) of long-duration energy storage by 2040.

Siefken said DOE favors working internationally on storage technologies.

“There are any number of challenges that we’ve identified domestically that are similar or have already been solved internationally. And there are a number of countries that have reached out to us directly that want to work on long-duration energy storage,” she said.

Neva Espinoza, vice president of energy supply and low carbon resources at the Electric Power Research Institute, said what’s important at this point is to encourage the development of many different storage technologies because those that are emerging are markedly different, varying from mechanical to chemical, from thermo to thermo-chemical.

“Each of those very specific technology options is unique from another in terms of the materials it uses, in terms of regional resources that may be required to best utilize that technology, in terms of how it integrates [with the grid].”

When asked by moderator Cristina Galan to explain what she meant by a “demonstration project,” Espinoza replied: “I’m specifically referring to building actual projects, integrating them into systems and operating them for relatively extended periods of time to really understand the true risk … and start the learning curve. And we need to learn from every single project as we build it.”

She added that such projects could be built on the former sites of fossil fuel power plants that already have the necessary grid connections, as well as a labor force.

Fisher, of the Edison Electric Institute, cautioned that the industry cannot know when any of the nascent technologies will become available, though she said she is convinced the engineering will be done and long-term storage will be developed.

“I believe that will happen in time. I think what we need to do is be preparing [for] the ecosystem issues that can tend to slow things down that have nothing to do with design,” she said.

“But I’m more worried about the dumb things that could get in the way, like regulatory regimes that weren’t built for [this] purpose and don’t really understand how to how to address long-duration energy storage.”

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WEIM Wins FERC OK for Resource Sufficiency Changes

FERC on Wednesday approved CAISO’s proposed changes to the Western Energy Imbalance Market’s resource sufficiency evaluation (RSE), including a provision to allow energy transfers to members who fail to meet resource obligations ahead of a trading interval (ER23-1534).

The package of changes was part of a second round of RSE-related tariff revisions, which were approved by the CAISO Board of Governors and WEIM Governing Body in December. (See CAISO, WEIM Boards Back Reliability Enhancements.)

The RSE test is designed to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to cover its own needs and to prevent participants from “leaning” on the market to meet internal demand. A balancing authority area (BAA) that fails the test before an operating hour is prohibited from receiving WEIM transfers during that interval.

But meeting that requirement has become a challenge for some participants as the West faces a worsening shortage of generating resources and declining liquidity in the regional bilateral electricity market that typically helps provide short-term resource sufficiency — which stakeholders attribute to the expansion of the WEIM itself.

The RSE consists of four tests that measure feasibility, balancing, capacity and flexibility. The rule changes approved Wednesday relate to the capacity test, which determines whether a WEIM participant has provided sufficient incremental bid-in capacity to meet the imbalance among load, intertie and generation base schedules.

The first rule change will allow CAISO to establish a process by which participants that fail the RSE can obtain “energy assistance” transfers from within the WEIM. Any BAA that receives such assistance will be subject to a surcharge on top of the cleared price for energy assistance transfers.

“The EIM assistance energy transfer surcharge is an after-the-fact charge designed to provide an alternative incentive for WEIM balancing authority areas to meet their resource sufficiency obligations during tight supply conditions while making additional supply available to other balancing authorities in the WEIM,” FERC noted in its order.  

CAISO plans to align the surcharge with the level of its soft ($1,000/MWh) or hard ($2,000/MWh) energy bid caps, depending on system conditions. It says energy assistance transfers will be voluntary for both the provider and recipient.

In approving the tariff revision, FERC concluded that CAISO’s plan “provides increased flexibility to WEIM participants and can help WEIM balancing authority areas to meet their resource sufficiency obligations during tight supply conditions.

“We also find the proposal allows CAISO to optimally dispatch supply and provide access to resources that were not otherwise available,” it said.

The rule change had particularly strong backing from WEIM member NV Energy. The Nevada-based utility faces increasingly critical shortages of resources during summer and has been seeking a legislative remedy to address the issue. (See Bill Would Require NV Energy to Examine Market Reliance.)

In a December letter to the CAISO and WEIM boards, Lindsey Schlekeway, NV Energy’s market policy manager, noted that her company had asked the ISO to develop a mechanism to make excess supply available to a “distressed EIM entity at an appropriate scarcity price” and said “it is of critical importance not to delay the implementation of this reliability enhancement past the summer of 2023 for grid reliability.”

Asymmetry Addressed

CAISO’s second and third RSE rule revisions focus specifically on the ISO itself.

The second change will allow the grid operator to exclude from its own RSE calculation any real-time “lower priority” energy exports out of its BAA. Those exports are currently included in the calculation even though the ISO can freely curtail them to meet its own load obligations. At the same time, real-time WEIM transfers into the ISO are not factored into the RSE, representing an asymmetry in treatment of transfers, CAISO argued. Inclusion of curtailable exports has caused CAISO to fail RSE tests that it would have otherwise passed, the ISO said.

FERC said CAISO’s proposal “helps mitigate this asymmetry and will improve the ability of the resource sufficiency test to more accurately reflect actual system conditions during periods of potential resource insufficiency.”

The third rule change pertains to scheduling priority rules and E-Tag requirements for lower priority exports, with CAISO clarifying how it will interpret its scheduling priority tariff provisions to ensure that it can manually curtail lower priority exports in real-time to meet its own supply obligations.

“We find that these clarifications are consistent with CAISO’s existing authority to apply the scheduling priorities and help provide better transparency for market participants,” FERC wrote. “Further, we find that these clarifications could help operators identify lower priority exports and priority exports for scheduling and manual curtailment purposes.”

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NY Green Bank Surpasses $2B in Financing

The NY Green Bank said Wednesday its financial commitments have passed the $2 billion mark and are likely to accelerate with the influx of new federal funding for the clean energy transition.

The fund is the largest green bank in the U.S., both in dollar value and scope of portfolio. It is marking its 10th anniversary this year and, through the end of May, had assisted 123 projects that will either decrease fossil fuel consumption or increase in clean energy production.

NYGB President Andrew Kessler told NetZero Insider on Thursday that the recently added federal funding streams — the Inflation Reduction Act, the CHIPS and Science Act, and the Infrastructure Investment and Jobs Act — are complementary to the work of green banks. The result will be acceleration, not replication, he said.

The fund was formed in 2013 by then-Gov. Andrew Cuomo as a division of the New York State Energy Research and Development Authority. The New York Public Service Commission in late 2013 authorized NYSERDA to use $165.6 million in unallocated funds as seed money for the bank (13-M-0412).

News accounts quoted NYGB’s president at the time, Alfred Griffin, saying the seed money would leverage additional financing that would total $800 million and reduce carbon dioxide emissions by 575,000 tons per year.

NYGB became self-sufficient in July 2017, when revenues began to exceed expenses. In its most recent metrics, through the end of 2022, the fund reported up to $5.6 billion in cumulative capital commitments and calculated that those projects accounted for 439,000 metric tons of carbon dioxide emission reductions in calendar year 2022.

Kessler said NYGB is the largest of its kind for several reasons, not least the 40-person staff and support of Cuomo and his successor, Gov. Kathy Hochul.

But the bank’s value and success have stemmed from its mission as a problem-solver: arranging financing for nontraditional projects or concepts that have trouble qualifying through traditional funding streams.

“Our approach has always been flexibility,” he said. “We are in the gap-filling business.”

This provides a double benefit to New York’s climate change mitigation goals. First, the bank moves a project and its climate benefits closer to realization. Second, it sets a financing model that traditional lenders can follow with similar projects in the future.

“Our mission is to animate private-sector capital,” Kessler said, likening it to a test kitchen.

NYGB looks for a sweet spot in the middle: Projects that do not have a high risk of failure because of technological or financial challenges but are not so mainstream that they could secure capital through traditional funding streams.

The question NYGB asks itself, Kessler said, is: “If we did this transaction, will the guys across the street say, ‘We could have done this. That’s business we missed.’”

The answer to that question, ideally, is “yes.”

Not every project flies. The applications that NYGB rejects often are for projects that cannot deliver a minimum equity percentage or rely too heavily on unproven technology.

NYGB started out heavily focused on solar project financing, particularly community solar, which was an unfamiliar business model when it began expanding across New York. A significant portion of its portfolio is still solar, but building decarbonization, clean transportation and other sectors have gained funding as well.

More recently, the fund has offered financing that allows developers to use their interconnection deposit as equity during the lengthy interconnection process.

And in April, NYGB officially launched a $250 million community decarbonization fund dedicated to projects that will reduce greenhouse gas emissions in disadvantaged communities.

Individually, the 123 projects that NYGB has financed to date can be overshadowed by the major renewable energy generation and transmission projects being developed across the state, some with price tags ranging into the billions. But Kessler said that the many small projects will have a large impact collectively. Just as important, they will have an intangible impact individually, as New Yorkers see them in their communities. Any effective clean energy transition will rely to a significant degree on behavioral changes and buy-in from millions of state residents, and Kessler said everyday familiarity can raise awareness and prompt organic change.

“You can see the energy transition is happening,” Kessler said. “When people see that and take notice … obviously that’s super helpful from a knowledge perspective.”

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FERC Approves PG&E’s Proposal to Spin off Generation

FERC on Wednesday approved Pacific Gas and Electric’s transaction to spin off its non-nuclear generation to a new subsidiary called Pacific Generation (EC23-38).

The firm plans to sell off up to 49.9% of the generation subsidiary so it can raise capital more efficiently than through the sale of additional stock in parent company PG&E.

Pacific Generation will become a certificated, cost-of-service public utility regulated by the California Public Utilities Commission in the same franchise territory as PG&E after the deal closes, providing cost-based generation to customers and selling some power into the CAISO market under a market-based rate tariff the firm will file with FERC.

The generators being spun off include 3,848 MW of hydro, 1,400 MW of natural gas units, 152 MW of solar and 182 MW of storage.

The proposal led to protests from the California Community Choice Association, the Transmission Agency of Northern California (TANC), Northern California Power Agency (NCPA) and Public Citizen. (See Parties Protest PG&E Plan to Spin Off Generation.)

The community choice aggregation association argued that without detailed information on which firm will buy the generation, its impact on vertical market power cannot be determined. FERC sided with PG&E, saying that spinning off the generation to a new subsidiary that does not provide any inputs to electricity products will not lead to vertical market power concerns.

While the utility promised to hold its customers harmless in the transactions, the city of Santa Clara, TANC, Public Citizen and NCPA said that was not enough to ensure that outcome. PG&E should look into less disruptive ways to raise capital, Public Citizen said.

TANC noted that PG&E wants to issue up to $2.1 billion in debt for the new firm, whose assets will value about $3.5 billion. It argued that FERC should require the company to show its accounting treatment and whether the deal would alter PG&E’s equity ratio. The utility provided no information on which costs transmission customers will be held harmless, which makes it impossible to determine whether that will actually happen, TANC said.

FERC determined that the deal would not affect rates. When it comes to wholesale rates, the assets will be bid at market prices, which will not be impacted by the seller’s cost-of-service retail rates.

Pacific Generation has yet to file a request for market-based rate authority; FERC said its approval is based on the new firm getting that authority before the deal closes.

“Failure by Pacific Generation to obtain market-based rate authority as PG&E represents in its application would constitute a material change in circumstances that we rely on in making our findings herein,” FERC said.

The commission also said the protesters failed to show the deal would impact PG&E’s cost of capital or transmission rates. The deal would not impact the firm’s return on equity, its credit rating or its capital structure, so claims to the contrary lack a factual basis, the commission said. It noted, however, that if those change, then that would also represent a material change to the facts relied upon in its approval.

FERC also found the deal would not affect rates, as the new subsidiary and the utility will still be regulated by it on the wholesale side, and the CPUC on the retail side.

Public Citizen argued that the transfer of generation to private equity could impair state oversight, but FERC said that is beyond the scope of the proceeding because it focused on the spinoff, not any later sales.

The deal would not lead to any cross-subsidization issues, where benefits are transferred from captive customers to shareholders, because both the utility and Pacific Generation will be regulated by the CPUC, FERC said.

“A debt issuance by Pacific Generation for the benefit of its utility affiliate, PG&E, is not analogous to a situation where the assets of a franchised public utility with captive customers are used to finance its market-regulated utility affiliates or nonutility affiliates or their activities, which the commission has stated may raise concerns,” FERC said.

Many of the protests argued that FERC should consider the spinoff and the subsequent sale of a minority interest in the generation at the same time, but the commission disagreed, saying expanding the proceeding to cover the second deal would be inappropriate.

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W.Va. Coal-fired Plant May Experiment with Hydrogen to Avoid Demo

The continued operation of a 1,300-MW West Virginia coal plant may depend upon whether the boilers can be modified to burn a portion of hydrogen to reduce emissions, an engineering challenge and controversial experiment Japanese power plants have been investigating.

Pleasants Power Station, on the West Virginia side of the Ohio River, now owned by Texas-based Energy Transition and Environmental Management (ETEM), is to shut down June 1 in preparation for demolition. Its previous owner, Energy Harbor, this year sold the plant to ETEM for demolition and leased it back in order to operate it through May 31.

At the urging of the West Virginia Legislature, the state’s Public Service Commission in April ordered Monongahela Power and Potomac Edison, subsidiaries of Ohio-based FirstEnergy, to negotiate with ETEM with the goal of purchasing Pleasants and continuing to operate it.  

FirstEnergy asked for a $3 million/month surcharge to continue operating the plant if the subsidiaries were able to purchase the plant, a request the PSC also approved.

But ETEM was recently approached by Omnis Fuel Technologies, a California company that opened a Morgantown, W.Va., office this month to purchase the power plant, according to a filing last week by Monongahela Power and Potomac Edison.

“ETEM is particularly focused on a proposed transaction with Omnis Fuel Technologies, LLC. If consummated, the [companies’] understanding [is] that the ETEM/Omnis transaction would result in continued operation of Pleasants to generate energy using the hydrogen byproduct of Omnis’s graphite production operations — an outcome that would not involve Mon Power’s acquisition or operation of Pleasants,” the FirstEnergy filing noted.

But Omnis must sign a purchase agreement by June 10 and close the transaction by July 31, according to the filing.

In the meantime, FirstEnergy said it is willing to continue to negotiate with ETEM should talks with Omnis break down.

“The companies are willing to work toward completion of the [letter of intent] in order to protect the continued viability of the plant if the ETEM/Omnis transaction is not consummated. If an LOI is reached, it will be presented to the commission as soon as possible with a request for expedited action in light of the urgent circumstances,” FirstEnergy wrote.

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Wash. Looks to Sell 11M Allowances in 2nd Cap-and-Trade Auction

Washington is aiming to auction off enough cap-and-trade credits Wednesday to cover more than 11 million metric tons of carbon emissions. 

The state’s Department of Ecology plans to auction 11.035 million allowances, with each entitling the holder to emit 1 metric ton of carbon. Of that amount, 8.585 million credits will go into effect this calendar year and another 2.45 million in 2026.

This will be the state’s second quarterly auction since the cap-and-trade law went into effect in January.  The results of Wednesday’s auction will be announced on June 7.

The first auction held on Feb. 28 sold all 6,185,222 allowances at $48.50 each to raise almost $300 million for the state’s coffers. (See Washington Confirms $300M Take for Cap-and-Trade Auction.) In April, the state legislature divided that $300 million into 188 appropriations for solar farms, climate planning, pumped storage projects, developing a hydrogen industry, installing solar on buildings, constructing infrastructure for electric vehicles, producing hybrid fuel-electric ferries and tackling other projects.

Revenue from the Wednesday auction will be appropriated in the legislature’s spring 2024 session, along with proceeds from auctions in August and November, and February 2024. In January, the Ecology Department made preliminary estimates that the auctions would raise $484 million in cap-and-trade revenue in fiscal 2023 and $957 million in fiscal 2024. (See Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024.)  

If today’s auction raises more than the Feb 28 auction, the state will be on its way to exceed its preliminary estimates.

The minimum bidding price is $22.20 per credit, the same as on Feb. 28. The allowances will be sold in bundles of 1,000 credits.

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California Bill to Speed Transmission Development Passes State Senate

A bill to accelerate the development of new transmission lines in California passed the state Senate Tuesday on a vote of 36-0 and is now headed for the lower house.

Senate Bill 619 would expand the authority of the California Energy Commission (CEC) by extending the agency’s existing “opt-in” permitting process to include new transmission lines that require a capital investment of at least $250 million over five years — although many such projects would still be excluded.

While not part of Gov. Gavin Newsom’s recently introduced legislative package to expedite the development of clean energy resources through looser permitting, SB 619 falls in line with the governor’s efforts, which last week took on a new sense of urgency. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)

“California’s efforts to build the clean energy supply of the future will fall flat if we rely on the grid of the past,” bill sponsor Sen. Steve Padilla (D) said in a statement Tuesday. “We must act now, to approve new projects and expand our transmission capacity. The state needs to triple the size of our grid over the next decade, and we are falling behind every single day.”

The CEC’s opt-in process is the product of a 2022 law (AB 205) that authorized the agency to create a new certification and permitting program that allows developers of non-emitting energy resources and related facilities — including transmission — to optionally seek approval from the CEC instead of a local permitting authority.

To be eligible for the process, a project must qualify under California’s Environmental Leadership Development Project program, which entails stringent environmental and labor provisions. SB 619 would expand the CEC permitting process to also include point-to-point transmission lines that function as more than just tie-ins for generating or storage resources.

‘Substantial Delays’

Under current California law, developers of point-to-point lines are prohibited from beginning construction before obtaining a certificate of public convenience and necessity (CPCN) from the California Public Utilities Commission — or, in the case of publicly owned utilities (POUs), a permit from a local authority.

The CPUC’s CPCN process includes both an environmental review under the California Environmental Quality Act (CEQA) and an evaluation of project need and costs. Critics — including Padilla — have blamed that process for the lack of needed new transmission in California.

“Despite the overwhelming need to expand our electrical grid, the California Public Utilities Commission has not authorized a new transmission project in over a decade,” the senator’s office said in its statement. “The current process requires multiple agencies, duplicative analyses, and permitting processes that take years to complete and create unnecessary cost overruns and substantial delays.”

SB 619 would allow a subset of transmission developers to circumvent those processes by opting into CEC review. But even if it passes, the bill might have a limited role in spurring construction of new transmission. That’s because it explicitly states that it will not contravene the CPUC’s oversight over transmission lines proposed by any utility falling under CPUC jurisdiction, which includes Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — the investor-owned utilities that serve more than half the state.

“The supporters of this bill acknowledge this limitation and recognize that additional work would be needed to make any changes to the existing CPUC’s authority related to permitting transmission projects,” said a bill analysis provided to senators before the floor vote. “Instead, this bill would capture a more limited set of transmission projects, those serving publicly-owned utilities (POUs), which would otherwise be permitted by local governments.”

According to the analysis, bill supporters include Clean Air Task Force, Clean Power Campaign, 350 Humboldt: Grassroots Climate Action, Elders Climate Action and San Diego Community Power.

“SB 619 is a much-needed reform to expedite approvals of badly needed new transmission, to expand solar, wind, and batteries, and enhance affordability and reliability,” V. John White, legislative director for Clean Power Campaign, said in a statement after Tuesday’s vote.

The Senate’s advancement of SB 619 could herald the passage of similar bills from Newsom’s legislative package. Those include proposals to streamline judicial review of certain clean energy and transportation projects by requiring that challenges under the CEQA be resolved within 270 days and a related measure to streamline procedures for the preparation of the public record for court review of CEQA challenges.

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FERC Accepts MISO’s Pledge for Annual Capacity Ratio Calculation

FERC on Tuesday accepted a MISO tariff revision that promises an annual update of unforced capacity-to-intermediate seasonal accredited capacity ratio the RTO uses to determine supply ahead of its capacity auction (ER23-1223).

The ratio disrupted MISO’s first seasonal capacity auctions and delayed the opening of its offer window by about a month. (See 1st MISO Seasonal Auctions Yield Adequate Supply.)

FERC said the grid operator’s pledge to calculate the ratio on an annual basis is reasonable and “provides greater notice to market participants regarding the timing” of its calculation.

“We expect that the schedule MISO develops with its stakeholders will incorporate sufficient time to work with market participants to validate and confirm [seasonal accredited capacity] values before finalizing the ratio,” the commission said. “We encourage MISO to continue working with its stakeholders to improve its processes from lessons learned.”

The grid operator’s calculation of the systemwide ratio in December produced an incorrect value. A computer error that counted previously excused maintenance outages against some planning resources undervalued their contributions.

This year, MISO and its Independent Market Monitor decided against reworking the ratio ahead of the spring capacity auction. They reasoned that the oversight wouldn’t harm reliability, there wasn’t enough time to rerun numbers, and market participants had already relied on the inaccurate ratio to enter bilateral supply contracts outside of the voluntary auction.

However, FERC found MISO in violation of its tariff and issued a show-cause order that had staff rehashing the calculation and delaying its first seasonal capacity auctions. (See FERC Terminates MISO Show-cause Order.)

After the ordeal, the grid operator updated its tariff to state that it will calculate the ratio on a standardized timeline, despite the determination requiring multiple rounds of market participants’ data submission and staff’s review and confirmation. MISO said its pledge to run the ratio annually is part of its lessons learned in moving to a seasonal capacity environment. It didn’t specify when it plans to publish the ratio, saying it will settle on dates with stakeholders and include them in a business practice manual.

Commissioner James Danly said in a partial dissent that MISO should commit to a more specific timeline in its tariff and name dates.

“Given that there is so much at stake in the inputs to the Planning Resource Auction (PRA), the date of the annual establishment of the systemwide … ratio for each planning year is fundamental to the mechanics of the market,” he wrote. “This ratio ultimately informs load serving entities and resources of their accredited capacity in advance of the [PRA]. While there could be debate on this, I believe that the rule of reason compels us to require the date’s inclusion in the tariff rather than the business practice manual.”

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Personnel, Meeting Costs Drive 2024 ERO Budget Hikes

With the North American electric grid experiencing “an alarming increase in reliability, resilience and security risks” — particularly cybersecurity, climate change and the evolving resource mix — NERC and the regional entities plan to raise their budgets and assessments by more than 10% in 2024.

NERC last week posted for industry comment its draft 2024 business plan and budget, along with those of the REs and the Western Interconnection Regional Advisory Body (WIRAB). Every document anticipates a budget increase of about 8% except WIRAB’s, which projects a decrease of $52,028, or 5.9%, from 2023; WIRAB’s assessment is still to grow by 1.6%, or $10,772. The overall ERO Enterprise budget is to grow by $25.2 million in 2024 to $275.4 million, while the collective assessments are to rise by 12.1%, from $214.1 million to $240.1 million.

Lion’s Share to NERC

As always, NERC’s budget is by far the largest contributor to the increase, at $110.6 million, up 9.5% from 2023. Personnel expenses account for the majority of NERC’s planned spending, at $64.4 million, up 11% from the prior year.

NERC plans to add 11.3 full-time equivalent (FTE) positions in 2024. The new employees are to be spread among the ERO’s departments, with the biggest increase of 2.59 FTEs in the Electricity Information Sharing and Analysis Center (E-ISAC). The new personnel will contribute to the E-ISAC’s “analytical capabilities [and] membership support,” along with expansion and enhancement of the Cybersecurity Risk Information Sharing Program, NERC said.

An additional 2.27 FTEs are to be added in the corporate services division, to support NERC’s cloud computing efforts and system administration, along with the publications team, while one open position is to be eliminated and filled with a contractor. Two positions are expected to be created to help with reliability standards development and technical expertise support, and the event analysis and situation awareness departments are to add one position each.

Additional growth in the personnel budget comes from increasing costs of salaries, health insurance and other benefits. NERC’s budget assumes a weighted average salary increase of 5.5%.

Meetings and travel costs are expected to rise 8.3% from 2023 levels, to $3.4 million. NERC said this increase “marks the return to pre-pandemic levels” of activity, though the ERO is also working to de-emphasize in-person meetings — in part to reduce expenses — with the most recent Board of Trustees and Member Representative Committee meetings following a hybrid format. (See NERC Board of Trustees/MRC Briefs: May 10-11, 2023.)

NERC’s operating expenses are to grow by 11.6% to $40.3 million due to additional contractor, consultant and software costs.

RE Budgets Set for Growth

WECC is projecting the largest budget of the REs, with $35.4 million expected in 2024, up $3.6 million from the year before. ReliabilityFirst is next with $31.3 million, a 12% increase, and SERC Reliability close behind at $31 million, up 10% from 2023. The Midwest Reliability Organization is to grow by $1.8 million to $24.9 million — the smallest increase of any RE — with the Northeast Power Coordinating Council rising 13.7% to $23.2 million and the Texas Reliability Entity projecting the smallest budget, at $19.2 million (up 8% from 2023).

2023-2024 ERO Assesments (NERC) Alt FI.jpgERO Enterprise assessments for 2023 (dark purple) and 2024 (light purple). | NERC

 

Like NERC, many of the REs’ budgets are driven by growing personnel, technology and travel costs. All entities reported they plan to add personnel, ranging from two FTEs in the case of MRO to the 12 estimated by NPCC. Meetings and travel are expected to increase for all REs except MRO, despite the entity planning to cohost the GridSecCon security conference next year.

Comments on the draft business plans and budgets are due by June 23.

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Carbon-capture Plant Coming Back into Service

The Petra Nova carbon-capture facility’s owner has told ERCOT that it plans to bring the plant out of mothballs and into year-round service in June.

Japanese oil and gas company JX Nippon filed a notification May 28 with the grid operator that it intends to bring the world’s largest carbon-capture plant back June 28. The plant has been shut down since 2020, during the height of the COVID-19 pandemic and in the face of slumping oil prices. (See NRG to Mothball Petra Nova CCS Plant.)

Petra Nova has a summer capacity of 71 MW and was retrofitted at a cost of $1 billion to capture carbon from one of the nearby W.A. Parish Generating Station’s coal-fired units. NRG Energy, which operates Parish, must complete repairs on the unit Petra Nova is connected to before it can return to service.

NRG and JX were partners in the carbon-capture project. JX bought NRG’s 50% stake for $3.6 million and closed the deal shortly after Congress passed the Inflation Reduction Act last August. The legislation includes a significant increase for the carbon-capture tax credit.

Petra Nova went online in December 2016. It sequestered more than 3.9 million tons of carbon dioxide in three years, despite frequent outages.

Also last week, Calpine said four gas units at its Deer Park Energy Center near Houston will be converted from generation resources to settlement-only, transmission self-generators as of Oct. 27. The resources each have a summer seasonal rating of 190 MW.