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November 19, 2024

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MISO Wants $10K VOLL, a Nearly Threefold Increase

CARMEL, Ind. — MISO last week said its extensive analysis shows that its current $3,500/MWh value of lost load (VOLL) should be raised to $10,000/MWh.  

The grid operator has made a renewed push in recent months to re-estimate its value of lost load after saying that its existing VOLL is dated, having been established in the 2008-2009 time frame. MISO’s current VOLL reflects the willingness of the lowest-income residential customers in the RTO’s footprint to pay for uninterrupted service.  

During a Feb. 29 Market Subcommittee meeting, MISO’s Chuck Hansen said the $3,500/MWh limit “can currently curtail valid market prices.”  

“When the system is in a more vulnerable state, prices should reflect the risk of diminishing reserves,” Hansen said.  

Three years ago, MISO’s Independent Market Monitor recommended the RTO adopt a $10,000/MWh VOLL.  

Hansen likened a well-thought-out VOLL to the “jolt” delivered from farmers’ electric fences, which aren’t meant to injure livestock.  

“The goal isn’t to shock the cows; the goal is to just keep them in the field,” he explained. 

Hansen said a raised value would almost counterintuitively moderate market volatility because market participants would take more actions to dodge the highest prices.  

“With higher prices, we expect lower volatility and more preparation to avoid those kinds of real-time energy deficiencies,” he said.  

Hansen said MISO’s current VOLL is “outdated and below industry willingness to respond to demand.” He said a reasonable VOLL would properly discourage market participants from “these ‘touching the electric fence’ situations” and “potentially make them more rare than they already are.” 

New VOLL Means New ORDC

MISO said it also will seek to change how VOLL ties into its operating reserve demand curve (ORDC). MISO’s ORDC is linked to VOLL, and the current curve mostly sits at $1,100/MWh and $2,100/MWh across two large steps before it tops out at $3,500/MWh.  

Despite proposing a $10,000/MWh VOLL, MISO wants its ORDC to peak at $6,000/MWh and stay there until about 50% of cleared operating reserves materialize. From there, the curve would slope downward until MISO can confirm more than 80% of its cleared operating reserves, at which point the curve would become two steps: $1,100/MWh until 88% of reserves show up and $600/MWh until 100% of reserves turn up.  

If MISO already had the new curve in place, Hansen said more than 90% of MISO’s past shortages would have resulted in lower penalty prices. Most of the RTO’s operating reserve shortages occur at 88% of reserves or higher. Historically, MISO has never experienced an operating reserve shortage below 50%.  

“This is not just about raising VOLL and making prices higher. On the right side of the curve, we thought it was appropriate to lower prices,” Hansen said. 

Hansen said MISO would like to introduce an ORDC that is lower for small reserve shortages and results in higher prices for greater shortages.  

“As reserves go away, we want prices to approach VOLL, but we don’t want prices to be so high that they reach VOLL well before load shedding is initiated,” Hansen said. Conversely, he added that the lower bound of the ORDC shouldn’t be so low that it’s cheaper for market participants to violate marketwide operating reserve requirement.  

Hansen said MISO wants to continue to use an updated VOLL as a price cap for locational marginal prices, market clearing prices and during load shed events.  

But he said MISO would like to sever the connection between VOLL and MISO’s emergency demand response offer cap. MISO has called on its emergency demand response only once, more than 15 years ago. Today, MISO’s emergency demand response averages less than 500 MW and is managed on a separate system from the RTO’s markets. The product was introduced before MISO debuted its ancillary service market, and owners are under no obligation to be available. Hansen said MISO has debated retiring its emergency demand response product and urges market participants to move their offerings under the RTO’s existing load-modifying resource and demand response programs.  

MISO’s proposed ORDC. The ‘SOM’ curve refers to the Independent Market Monitor’s past recommendation for a new curve. | MISO

Justification for $10K

Hansen said the current VOLL was established alongside the launch of MISO’s ancillary services market and “that number has not changed in 15 years.”  

He said MISO has made hundreds of calculations to freshen its VOLL, including crunching numbers for different lengths of outages; nonsummer versus summertime periods; afternoon, evening or off-peak periods; and using different customer load classes, including small commercial, industrial, residential and manufacturing segments.   

MISO found that for a one-hour outage occurring off-peak in summer, VOLL will run $4,337/MW for residential customers and up to nearly $81,000/MW for small commercial and industrial customers. For an eight-hour outage occurring off-peak in summer, a residential VOLL will run about $8,107/MW, while small commercial and industrial customers’ value runs more than $266,000/MW.  

“We’ve been studying a range of numbers, many numbers,” Hansen said.  

MISO found that its highest VOLL occurs during off-peak periods with small commercial and industrial customers the most exposed to risks of lost revenue. Larger commercial and industrial customers often have access to more capital to prepare to bounce back more quickly from an outage, staff said.  

When MISO made its 2007 FERC filing to create VOLL, it used the average of the $1,470/MWh median value of its residential class and the $15,250/MWh lowest median value of the small commercial and industrial class. The resulting VOLL was weighted 85% toward residential customers.  

Using that same 2007 calculation, Hansen said the 2023 VOLL for a summertime, one-hour outage occurring off peak should be $13,640/MWh.  

“What we’re proposing is actually on the conservative side,” Hansen said.  

Hansen reminded stakeholders that MISO isn’t in charge of which customers are affected by outages when it orders load shedding. The RTO simply tells local balancing authorities how many megawatts it needs off the system. MISO said a recent survey of its local balancing authorities shows that when instituting rolling blackouts, customers dropped on average are 48% residential, 30% large commercial and industrial, and 22% small commercial and industrial.  

Hansen said a $10K VOLL reflects that industrial customer load is also shed alongside residential load during dire circumstances. 

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MISO: New Capacity Accreditation Filing Imminent

CARMEL, Ind. — MISO is determined to file with FERC by the end of March to introduce a probabilistic capacity accreditation that’s controversial among stakeholders.  

MISO stakeholders continued to lobby for a deferral during a Feb. 28 Resource Adequacy Subcommittee meeting, again telling the RTO it hasn’t shared enough information on its loss of load-oriented accreditation style. (See MISO Set on March Accreditation Filing, Stakeholders Push for Slowdown.) A filing in March seems destined to gather several protests.  

But Senior Manager of Market Design Neil Shah said MISO has now shared enough data from its analyses to give stakeholders a “broad indication” of their future capacity credits to adjust generation plans accordingly.  

“The filing needs to happen now for stakeholders to make those adjustments,” Shah said.  

MISO doesn’t intend the accreditation to take effect until the 2028/29 planning year. 

Shah said “the beauty of” MISO’s method is that it measures the reliability contribution of all resources across “hundreds and hundreds” of simulated risky hours. 

Under the new method, generators’ capacity credits would be determined by a combination of individual past performance and resource-class average performance during hours with tight conditions and modeled loss-of-load hours for different types of generation. Most resources’ credits would shrink under the new accreditation. Resources would be divided by fuel type: gas, coal, hydro, nuclear, energy storage, pumped storage, wind and solar. MISO at first didn’t commit to listing resource types in its tariff filing with FERC.  

Shah likened MISO’s accreditation change to his homeowner’s insurance policy recently increasing by a few hundred dollars based not on him, but on his neighbors filing more claims recently. He said his insurer took the growing claims as proof of rising risk in his neighborhood and reassessed. MISO, Shah said, is no different with this new accreditation direction.  

Many MISO stakeholders have argued the loss-of-load accreditation would inject too much uncertainty into the MISO market, disrupting integrated resource plans and investment decisions. At the RASC meeting, some said they don’t have adequate insight into how capacity credits would differ by resource type and questioned whether MISO’s proposed resource classes would sufficiently represent all types of resources in MISO.  

Shah said MISO is prepared to make a future filing if new technology necessitates the RTO add new resource classes but said MISO has landed on a “good representation of resources classes” in the footprint today.  

Shah also noted that during the three-year transition period, MISO wouldn’t apply the accreditation but would publish indicative accreditation results for resource classes, as well as anticipated local reliability requirements and planning resource margin requirements based on the direct loss-of-load accreditation method. MISO wouldn’t share unit-level capacity values publicly; market participants would need to request those from the grid operator.  

MISO has said the new accreditation would better ensure seasonal reserve requirements are met, shape long-term investment and retirement decisions “by accurately representing the capacity value of a resource in the prompt year,” and incentivize resources to show up during times of the greatest system need. It has characterized the new accreditation style as a “consistent accreditation methodology for all resources, capturing the reliability contribution during times of highest risk.”  

MISO’s Zak Joundi has said MISO members would “have plenty of time to adjust” to the new rules.  

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MISO Names New Chief Information Security Officer

MISO announced it has promoted Eric Miller to chief information security officer and the RTO’s newest vice president.  

Miller joined MISO in 2020 as an executive director of digital technology. Prior to signing on with MISO, Miller held IT and cybersecurity leadership roles at Ascension Technologies, the health care company’s IT division.   

Miller is based out of MISO’s Carmel, Ind., headquarters and is now responsible for managing the RTO’s physical security, cybersecurity, and technology infrastructure and operations. 

“I look forward to stepping into this new role at MISO,” Miller said in a March 1 press release. “I’m excited about leading a world-class team of professionals who are committed to a safe, secure and reliable bulk electric system.” 

Former Chief Information Security Officer Keri Glitch left MISO last year to join Fortis, where she serves as the vice president of information technology.  

Miller has a master’s degree in systems engineering from Johns Hopkins University and a Master of Business Administration from Bowling Green State University. He also was a commissioned officer in the U.S. Army.  

MISO said Miller recently completed the CISO Executive Education and Certificate Program from Carnegie Mellon University’s Heinz College of Information Systems and Public Policy, in addition to holding multiple other cybersecurity certifications.  

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Bill to Link Wash. Cap-and-trade with Calif.-Quebec Passes Both Houses

Washington’s Democratic-controlled House of Representatives on Feb. 29 approved a bill that would allow the state’s cap-and-trade program to link up with the system shared by California and Quebec.  

Senate Bill 6058, sponsored by Sen. Joe Nguyen (D), passed the House 57-39 along party lines — just as it did in the Senate earlier this month. (See Carbon Market Linkage Bill Passes Wash. Senate.) 

The two houses must now reconcile minor changes added to the bill.  

Washington is negotiating with California and Quebec on potentially meshing their cap-and-trade programs with the expectation that a bigger market would soften carbon allowance prices, which then could reduce the state’s high gasoline prices.  

Linkage between the markets could take place no earlier than 2025. Looming over the development is a November referendum on whether to repeal Washington’s cap-and-invest program, which some have blamed for the state’s gas price increases.

House Republicans opposed the bill Feb. 29, spending the majority of a four-and-a-half-hour debate slamming cap-and-invest for boosting gas prices. When focused on the specifics of SB 6058, Republicans said they did not like tying Washington’s program to the much larger California one, which see its own unique ups and downs. They also voiced skepticism about claims that a larger market would decrease gas prices in the Evergreen State. 

“We’re going into an agreement without a clear understanding of the partners we want a relationship with,” Rep. Keith Goehner (R) said.  

“Fools rush in. We should not rush into any linkage,” said Rep. Jim Walsh (R), who is also one of the leaders of the initiative to repeal cap-and-invest. 

Majority Leader Joe Fitzgibbon (D) pointed out that a common argument against Washington’s efforts to combat climate change is that one state’s efforts won’t affect global warming. He said a carbon market combining Washington, California and Quebec would create a greater effect on reducing emissions. And Fitzgibbon noted that New York, Massachusetts and Maryland are watching Washington’s efforts with the idea of creating their own cap-and-trade programs to eventually join the bigger market. 

The bill “simply sets us up for success as we work with California and Quebec collectively to protect our air sheds from greenhouse gases,” said Rep. Beth Doglio (D).

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‘Bigger Stuff’ is Coming for SPP’s REAL Team

DFW AIRPORT, Texas — SPP’s Resource and Energy Leadership (REAL) Team last week marked the one-year anniversary of its formation with yet another discussion of resource adequacy issues and the various metrics used to determine a reliability standard. 

But not to worry. Major developments are on the horizon. 

“The bigger stuff is coming later,” said SPP’s Casey Cathey, senior director of grid asset utilization, following the Feb. 21 meeting. 

That would be the winter planning resource margin (PRM) and a reliability standard based on expected unserved energy (EUE). However, it may take time. 

“I think we need some time to bake in more of an understanding about the interrelationship between EUE and the fuel mix, as well as the load changes,” Cathey said. “We do need to work towards an accelerated standard, but we’ve never enforced an EUE limit before. It’s always been PRM. As we’re continually seeing the fuel mix change and the loads are also under a lot of scrutiny, with more resources that are underperforming and more extreme events, I think the fear is to put a standard without it being potentially well thought out could be extremely costly.” 

To ease that fear, the REAL Team contracted last year with firms 1898 & Co. and Astrape Consulting to conduct a future resource mix study. The study focused on five- and 10-year projections for PRM and renewable resources’ effective load-carrying capability values as providing better forward-looking information than the standard loss-of-load expectation (LOLE) studies. 

It also considered EUE as a new metric, given resource adequacy’s shift from “capacity adequacy” to “energy adequacy.” SPP staff said they have found a divergence in EUE and LOLE as the system evolves more toward an “energy-limited” resource portfolio. 

The study found the existing 0.1 LOLE reliability target continues to contribute to an increased EUE and “unacceptable reliability” and that as renewable capacity increases, the winter season becomes dominant. Implementing reliability metrics separated by season helps meet the annual LOLE/EUE target, it said. found the existing 0.1 LOLE reliability target continues to contribute to an increased EUE and “unacceptable reliability” and that as renewable capacity increases, the winter season becomes dominant. Implementing reliability metrics separated by season helps meet the annual LOLE/EUE target, it said. 

However, the study found a last-in allocation methodology “may allocate more accreditation than appropriate to certain technology types due to synergies between resources. It said more studies are required to confirm the appropriate level of a normalized EUE as a reliability standard. 

“We have a natural breakdown that winter events are longer, deeper and they have more amounts of energy per event than you do in the summer,” 1898’s Brian Despard said. “If you add more renewables, you’re shifting from summer events to winter events and there’s naturally more unserved energy in the winter. So, we have to install a standard that says, ‘Let’s keep unserved energy the same instead of keeping the number of events the same.’ We’re going to have a secondary and complementary requirement that says, ‘I will get a credit for the ability to maintain those standards as well.’” 

Brian Despard, 1898 & Co. | © RTO Insider LLC

The REAL Team will continue its discussion of the PRM and EUE metric when it gathers at SPP’s headquarters in Little Rock, Ark, March 22. 

“That’s March Madness,” said Kristie Fiegen, chair of both the REAL Team and the South Dakota Public Utilities Commission and an apparent fan of college basketball’s annual postseason tournament. 

Still, the meeting will go on. 

“More education is needed across the board for members, for the Regional State Committee, for REAL,” Cathey said. 

The REAL Team reports to the RSC, which is composed of SPP state regulators. Also, it is working in tandem with the Supply Adequacy Working Group (SAWG) and the RSC’s Cost Allocation Working Team. 

“We’re kind of working to educate on the EUE, but to also help that education form how we might best establish our very first separate winter planning reserve margin,” Cathey said. “Even though we don’t have a standard — and this is what’s a little bit confusing — we still understand that we shouldn’t just let EUE be this massive number. We have to use the data from the loss-of-load expectation study to best inform how we balance the risk between winter and summer for upcoming 2026 binding season.” 

The REAL Team directed SAWG to consider EUE associated with an LOLE metric to determine winter and summer PRMs, recommend an EUE standard, and place the expectation of that effect on the 2025 LOLE study.  

Evergy’s Colton Kennedy, SAWG’s chair, agreed that more education and analysis is needed.   

“There’s a separate conversation around what [we] are establishing as a region for an EUE standard. I think honestly, we don’t need that to set the PRM, to recommend PRM,” he said. “I think we know that there are gaps. We know that the EUE is something that needs to be incorporated into the target. I don’t think we have enough information to say this is the appropriate risk tolerance for this region.” 

Separately, the team approved a tariff change (RR605) intended to clarify resource availability expectations for both the summer and winter seasons. The measure adds a definition of authorized outages and more requirements for availability during the two seasons when not on an authorized outage, and it clarifies when load-responsible entities and generation owners should submit resource adequacy capacity to meet their requirements. 

“It’s not the most complicated policy, but it’s fairly important. If we didn’t do it, we will be shooting ourselves in the foot,” Cathey said. 

The revision’s language is seen as meeting FERC’s expectation that SPP consider expedited proceedings for any future filings on the winter season RA requirement. The commission in November rejected the grid operator’s first attempt at a winter resource adequacy requirement; the RTO plans to refile the requirement, nonbinding until the 2026-27 winter, in April. (See “FERC Rejects Winter Requirement,” ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.) 

The REAL Team also endorsed a pair of initiatives by staff and stakeholders: 

    • The Market Working Group’s development of potential availability market constructs and other incentive-based mechanisms. The MWG explored five options before determining that, based on staff’s evaluation, a performance credit mechanism (PCM) similar to ERCOT’s and an energy availability market would provide the largest economic and reliability benefits. The group is monitoring ERCOT’s PCM development process and will reevaluate the need for additional mechanisms once resource adequacy policies are implemented and evaluated. 
    • Staff’s pursuit of a price-formation policy that dispatches the system based on the true obligation and prices the system during a scarcity event using the obligation without the effect of load shed and emergency energy assistance. Staff plans to secure approval from stakeholders, regulators and the board in April and May, and then take the revision request to the same bodies in July and August. 
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Sunrise Wind, Empire Wind Tapped for New OSW Contracts

Two major New York offshore wind projects are getting back on track, with more lucrative contract awards to replace their existing deals with the state. 

New York on Feb. 29 announced conditional contract awards to Empire Wind 1 and Sunrise Wind, which have a combined 1,734-MW capacity rating — about a fifth of the state’s 9-GW goal for 2035. 

Importantly, both are mature projects, with many of their agreements and permits already in hand. They should be able to come online years sooner than new proposals that would start from scratch. 

Empire Wind and Sunrise Wind will cancel their existing contracts. The numbers would be much larger in the replacement contract.  

Their original contract had an all-in average development cost of $83.36/MWh in 2018 dollars, with an average residential monthly bill impact of 73 cents. 

NYSERDA said Feb. 29 the new conditional contract carried a weighted average all-in lifetime development cost of $150.15/MWh, with an average monthly bill impact of $2.09. 

Providing final contracts are negotiated, the announcement potentially represents the continued comeback of New York’s offshore wind portfolio from near collapse amid the industry problems of 2023. 

Empire Wind 1 and 2, Sunrise Wind and Beacon Wind asked the state in June for more money for their projects, which totaled 4,230 MW of nameplate capacity. Construction costs had soared since they locked in their offtake contracts and the projects had become financially untenable. 

The state in October refused but allowed them to rebid in a rush fourth solicitation that opened at the end of November. Empire 2 and Beacon canceled their contracts and did not rebid. Sunrise and Empire 1 rebid and a new project — the 1,300-MW Community Wind 2 — also submitted a proposal. The state said that project was waitlisted, with potential contract award and negotiation at a later date. 

‘New Beginning’

The U.S. Bureau of Ocean Energy Management green-lighted Empire Wind with a positive record of decision in November and now is finalizing its record of decision with Sunrise Wind. New York Gov. Kathy Hochul (D) framed the contract awards as a way to get the state’s nascent offshore wind sector — and its expected economic and environmental benefits — back on track. 

“Offshore wind is foundational to our fight against climate change,” she said in a statement, “and these awards demonstrate our national leadership to advance a zero-emissions electric grid at the best value to New Yorkers.”   

Empire developer Equinor hailed the contract announcement. “This is a promising new beginning for Empire Wind and we’re ready to get started,” said Molly Morris, president of Equinor Renewables America. 

Sunrise developer Ørsted had a similar reaction. 

“With the selection of Sunrise Wind, New York’s offshore wind story is set to enter a new chapter of large-scale job creation and economic development, and we thank Governor Hochul and her administration for their continued leadership,” said David Hardy, CEO Americas at Ørsted. 

There is much yet to do, however. 

New York’s offshore wind portfolio now consists entirely of South Fork Wind — a first-in-the-nation pioneer nearing completion, but also a 12-turbine installation rated at just 132 MW. 

Three other proposals awarded conditional contracts in the third solicitation — Attentive Energy One, Community Offshore Wind 1 and Excelsior Wind, with a combined capacity of 4,032 MW — still are negotiating final contracts with the New York State Energy Research and Development Authority, more than four months after they were selected. 

‘Steadfast’ for OSW

The financial turmoil that hit the offshore wind industry’s Northeast projects last year is believed to be settling down but is not over. Equinor and Ørsted said Feb. 29 they do not expect to make final investment decisions until mid-2024. 

Equinor and BP recently announced they would terminate their partnership on the Empire and Beacon projects, with BP taking Beacon and Equinor taking Empire. Equinor said Feb. 29 it will bring in a new partner on Empire Wind to reduce its exposure. 

Ørsted’s projects off the New England coast have been in partnership with Eversource, which has been trying to exit the cash-sucking venture since late 2022. Awarding of a final contract for Sunrise would trigger Ørsted’s acquisition of Eversource’s portion of that project, though Eversource would remain involved, leading onshore construction. 

“We are steadfast in our conviction that offshore wind is critical to address climate change and help meet the growing demand for clean, reliable energy,” Community Offshore Wind President Doug Perkins said in a statement Feb. 29. “Our commitment to both New York and the U.S. offshore wind industry is unchanged and we look forward to working with NYSERDA in the future to advance New York’s clean energy goals.” 

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Biden Names 3 Nominees to Give FERC 5 Members Again

President Joe Biden announced three FERC nominees Feb. 29, which would bring the agency back to a full complement of five members even after Commissioner Allison Clements leaves. 

Biden named to the federal regulator Judy Chang, a former Massachusetts official; FERC analyst David Rosner, who has been detailed to the Democratic staff on the Senate Energy & Natural Resources Committee; and West Virginia Solicitor General Lindsay See. Senate Minority Leader Mitch McConnell (R-Ky.) recommended See. 

The last two have links to Sen. Joe Manchin (D-W.Va.), who chairs the Energy & Natural Resources Committee, which will hold hearings on the nominees and must vote them out before they can move onto consideration by the entire Senate. Rosner has worked under Manchin at the committee. 

“A fully seated, bipartisan FERC provides more opportunity for advancing long-lasting, sensible energy infrastructure policy,” Manchin said in a statement. “As chairman of the Senate Energy and Natural Resources Committee, I look forward to reviewing the qualifications of the three individuals nominated today to be FERC commissioners and assessing their commitment to American energy security.” 

As solicitor general, See argued her state’s side of the case before the Supreme Court in West Virginia v. EPA, which limited how the agency can regulate carbon emissions from power plants. (See Supreme Court Rejects EPA Generation Shifting.) 

Chang has more than 20 years of experience in energy economics and policy, including a stint as the undersecretary of Energy and Climate Solutions in Massachusetts where she helped implement its climate change mitigation efforts. She has presented and testified before federal and state agencies and regulatory authorities on energy resource deployment, energy contracts, transmission planning and electricity market design. 

Chang is a senior fellow at Harvard University’s Kennedy School of Government. She got her master’s of public policy from the Kennedy School and her bachelor’s at the University of California, Davis. 

Rosner has 15 years of experience on energy technologies, market design and energy policy issues, including his stint working on assignment for Manchin’s committee staff. He also was a senior policy adviser at DOE’s Office of Energy Policy and Systems Analysis and associate director of the Bipartisan Policy Center’s energy project and holds degrees in economics and public policy. 

Before becoming solicitor general, See worked at Gibson, Dunn & Crutcher in Washington, D.C. She graduated from Harvard Law School and is from Michigan. 

The nominees and the potential return to a full slate of FERC commissioners this year was welcomed by many in statements issued Feb. 29. 

“A full complement of commissioners is critical to ensure robust debate and efficient progress on the important issues that FERC will be asked to weigh in on in the coming months and years, from interconnection reform to transmission planning to market rule changes in light of the energy transition,” Advanced Energy United Managing Director Caitlin Marquis said in a statement. “We encourage the Senate to move forward quickly with the review process and look forward to working with a fully staffed commission under the leadership of Chair Willie Phillips.” 

Sierra Club Executive Director Ben Jealous put out a statement saying while FERC may not be well known to the public, it is critical to bring more renewable energy online quickly. 

“A fully staffed FERC has the opportunity to tackle the climate crisis while making our transmission grids more resilient and reliable,” Jealous said. “But FERC must turn around its track record of acting as a rubber stamp for the fossil fuel industry. As these nominees move through the Senate confirmation process, we will be watching for these candidates to commit to weighing climate, environmental justice, health and consumer cost impacts heavily in any decision they make. The courts have repeatedly said FERC must factor in these considerations, and the Sierra Club is committed to ensuring the makeup of the commission is in step with this mandate.” 

The Natural Resources Defense Council also welcomed the new nominees, with Sustainable FERC Project senior attorney Christy Walsh saying a fully staffed commission is important. 

“We hope for a swift and robust confirmation process that will give the nominees a chance to offer their perspectives and plans on key issues like transmission, interconnection, markets, gas regulation and environmental justice,” she said. 

The Electricity Transmission Competition Coalition also said it wants to see a full complement of five commissioners. 

“I urge the nominees to put consumers first and support electricity transmission competition, which is the key to fulfilling FERC’s mandate of providing affordable and reliable electricity,” ETCC Chair Paul Cicio said in a statement. “FERC’s role is more important than ever with spending on transmission set to grow; pro-competition commissioners will be key to ensuring that upgrades to the grid come at the lowest cost to consumers.” 

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NIST Expands Cyber Framework in Latest Release

The National Institute of Standards and Technology (NIST) released the latest version of its Cybersecurity Framework (CSF) this week, aiming to help public- and private-sector organizations stay ahead of the growing digital threat landscape.  

Version 2.0 of the CSF, published Feb. 26, represents an expansion for the framework. The new document is “designed for all audiences, industry sectors and organization types, from the smallest schools and nonprofits to the largest agencies and corporations,” NIST said in a statement. 

“The CSF has been a vital tool for many organizations, helping them anticipate and deal with cybersecurity threats,” NIST Director Laurie Locascio said. “CSF 2.0 … is not just about one document. It is about a suite of resources that can be customized and used individually or in combination over time as an organization’s cybersecurity needs change and its capabilities evolve.” 

This is the first major update to the CSF since NIST first published the document in 2014 in response to Executive Order 13636. NERC is one of many organizations to use the framework, though not directly; rather, the ERO partnered with NIST in 2021 to produce a set of tools to help registered entities map the CSF to NERC’s Critical Infrastructure Protection (CIP) standards. (See NERC, NIST Update Cybersecurity Mapping.)  

The CSF is meant to support the implementation of the federal government’s National Cybersecurity Strategy, released last March. The strategy has five pillars: 

    • Defend critical infrastructure. 
    • Disrupt and dismantle threat actors. 
    • Shape market forces to drive security and resilience. 
    • Invest in a resilient future. 
    • Forge international partnerships to pursue shared goals. 

In keeping with these goals, the new CSF “goes beyond protecting critical infrastructure … to all organizations in any sector,” NIST’s release said, explaining that comments on a draft CSF received last year demonstrated that a broad range of organizations had an appetite for a version of the framework they could use.  

The final framework shows this focus with the addition of quick-start guides allowing users with specific needs — for example, owners of small businesses or staff looking to secure their digital supply chains — to easily access information that suits them without wading through irrelevant sections. Organizations can also set up custom profiles representing both their current and desired status and access community profiles that show how similar organizations have used the CSF. 

Also added to the new version is a focus on governance, with “Govern” as the first of the CSF’s core functions. The document calls governance activities “critical for incorporating cybersecurity into an organization’s broader enterprise risk management strategy.” Duties under this function include establishing a cybersecurity strategy and supply chain risk management, and mapping out staff roles, responsibilities, authorities, and areas of oversight. 

Governance underlies the other core functions, which NIST defines as: 

    • Identify — Understand the organization’s assets, suppliers and related cybersecurity risks, and identify opportunities for improvement in its policies and practices. 
    • Protect — Ensure that safeguards are in place to manage cybersecurity risks. 
    • Detect — Find and analyze possible cyberattacks and compromises. 
    • Respond — Take action in response to detected cybersecurity incidents. 
    • Recover — Ensure that assets and operations affected by a cybersecurity incident are restored. 

NIST said it expects the new CSF to be translated for use internationally; the original is available in 13 languages, the organization said. It also plans to continue working with the International Organization for Standardization and the International Electrotechnical Commission to align cybersecurity documents across countries and industries. 

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PJM Rejects Storage as Alternative to Brandon Shores RMR

PJM is rejecting a study that suggests it could avoid extending the 1,295-MW Brandon Shores generator’s life by installing storage and reconductoring several lines outside Baltimore. 

The analysis, conducted by GridLab and Telos Energy, found that installing a 600-MW battery at the Brandon Shores point of interconnection and reconductoring several 115-kV lines could provide the grid services offered by the generator and be in place in time for the 2025 retirement requested by plant owner Talen Energy.  

The study estimated the battery would cost $452 million after tax credits and could produce $348 million in net revenues over 20 years. Comparing Brandon Shores to other generators that have received RMR contracts, the study estimated that continuing to run Brandon Shores could cost $258 million per year. 

“We think this is a model that could be exported throughout PJM and even in other ISO regions as well: opportunities to replace retiring generation with storage as a means to avoid an RMR and … have a stronger system, a more reliable system, instead of paying for an uneconomical plant to stay online for several more years until transmission upgrades come in,” Gridlab Senior Program Manager Casey Baker said. 

PJM is in talks with Talen Energy to keep the generator running until its $796 million Grid Solutions Package is completed in 2028 to address expected reliability violations. The project includes a new 500-kV substation, a new 500-kV line between the Peach Bottom and Graceton substations and a 230-kV line from Graceton to a new 230-kV Batavia Road substation outside Baltimore. (See FERC Approves PJM RTEP Projects over State Protests.)  

PJM spokesperson Jeff Shields told RTO Insider that a battery installation is not a viable alternative to an RMR for Brandon Shores. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades” PJM PC/TEAC Briefs: June 6, 2023.) 

“PJM does not believe that a battery solution would address the comprehensive reliability needs in the BGE and surrounding areas, be able to be put in place by 2025, or be economically feasible,” Shields said in an email. “The Brandon Shores RMR is a must to maintain regional reliability until any additional enhancements could even be considered in the future.”  

Sierra Club Senior Attorney Casey Roberts said she believes there is time for PJM to consider alternatives to keeping Brandon Shores online. 

“The deactivation dates are June 2025, so we think there’s actually a pretty good amount of time for PJM to look at alternative solutions and see what else can be implemented. PJM has expressed some urgency with nailing down an RMR agreement with Talen for Brandon Shores as soon as possible, but in our view it’s better to take a little bit of extra time to make sure you have the most cost-effective and reliable solution rather than rushing to the thing you’ve always done,” she said. 

She pointed to the example of the Petersburg Generating Station retirement owned by AES Indiana, where the utility is planning on switching two of the four coal units to natural gas, retiring the other two and installing an 800-MWh battery. 

“We have definitely seen examples of coal plant sites and interconnection rights being repurposed for varying forms of clean energy, also for natural gas, but it’s essentially a way of seamlessly replacing the grid services provided by a retiring asset by something else. … Some of those examples are storage,” Roberts told RTO Insider. 

Roberts said that RTOs can be limited by a status-quo bias that pushes them to prefer solutions and resources that their staff have prior experience with. 

“PJM doesn’t see itself as being in the business of procuring generation, so in the example where an RMR could be avoided by the installation of wind or solar, for example, PJM just doesn’t see that as a tool in their toolbox right now. They see their only tool as to procure transmission technologies … or to pay the retiring generator to stick around for a few more years,” she said, adding that other RTOs do have processes to procure the reliability services provided by thermal resources. She noted that the Maryland Public Service Commission had protested PJM’s Grid Solutions Package filing, arguing that the RTO’s proposed solution had not considered a state law requiring the development of 3 GW of storage in the state, which the PSC argued provided an opportunity for PJM to work with the state to find alternatives (ER23-2612). 

Tori Leonard, spokesperson for the PSC, said the commission appreciates the study and understands that PJM will be providing a full assessment of its findings. 

To conduct the study, GridLab and Telos consulted with PJM to perform their own reliability analysis, confirming that the deactivation of Brandon Shores without any modifications to the grid would result in reliability violations. The most severe line overloads were found under summer peak load conditions with an unplanned outage occurring during a maintenance outage — an N-1-1 scenario.  

The worst voltage collapse contingency was seen during an extended winter peak with high generation or transmission outages, such as the December 2022 Winter Storm Elliott. Baker said that the modeling showed that if the summer violations were resolved, winter needs would also be met. 

In an announcement of the analysis, the Sierra Club argued that storage combined with the line reconductoring identified could not only meet the needs until the Grid Solutions Package’s completion, but that the battery’s characteristics could bring added reliability over the retiring coal generator. 

“The battery storage solution can also be more reliable than the coal solution, since batteries can start up and inject power far more quickly than a coal plant. Many reliability events arise on short notice due to unexpected outages of other power facilities, so the quick response of the battery could make all the difference in keeping the lights on,” the announcement said.  

“Unfortunately, PJM lacks a framework to evaluate alternatives like this to RMR agreements. Instead of clearly defining the reliability need and seeking the most cost-effective solution, PJM assumes only the retiring generator can provide reliability, and will pay whatever it takes to keep them online … PJM’s approach reflects a missed opportunity to uphold its responsibility to ensure bulk power system reliability while also supporting state clean energy policies.” 

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Utility Regulators Repeat Concerns About Tx Siting Oversight

State utility regulators reiterated their concerns about FERC’s efforts to promote transmission development at the Feb. 28 meeting of the task force established for that purpose. 

The issue of federal authority usurping state and local control has been raised repeatedly since plans were announced to create National Interest Electric Transmission Corridors (NIETCs) and to give backstop authority to FERC. (See What are National Interest Electric Transmission Corridors and Why Do We Need Them?) 

Grid constraints are a potentially fatal obstacle to the electrification goals set by the federal government and many states. Siting new transmission to address those constraints can be slow and difficult, particularly for lines that cross regional boundaries. NIETCs and backstop authority are two ways to potentially address this. 

The Feb. 28 meeting was the eighth for the Joint Federal-State Task Force on Electric Transmission, formed under a June 2021 FERC order (Docket AD21-15-000). FERC Chair Willie Phillips and Kimberly Duffley of the North Carolina Utility Commission co-chair the task force. 

Phillips said Feb. 28 that FERC has already heard the concerns of states and stakeholders during the comment process, “but there is something to be said for sitting around this table and hearing from you directly, and face-to-face.” 

Moderator Jonathan Raab opened the discussion by asking task force members to identify the transmission siting challenges that exist in their regions. 

Kansas Corporation Commission Chair Andrew French said the growth of renewable generation on the Plains has created difficult optics. 

“More and more,” he said, “as energy becomes exported, there’s at least a perception that Kansas land is increasingly being used to benefit faraway customers in other states to satisfy their policy goals.” 

Riley Allen of the Vermont Public Utility Commission had good things to say about the transmission siting process in his state and in the ISO-NE region. But he noted it typically takes 13 to 20 months in Vermont, which exceeds the 12-month threshold that is one of the triggers proposed for FERC backstop action.  

“But I think there’s room for improvement,” he said. “I think backstop authority will certainly add some life to the timeliness of these things going forward.” 

Darcie Houck of the California Public Utilities Commission said complications frequently arise when working with federal land management agencies, particularly when coordinating joint environmental processes. Also, federal technical studies supporting permitting often are delayed. And the PUC must coordinate with tribal nations and local governments, creating a complex process with many stakeholders.  

“Another challenge to timely siting of transmission comes from substantial community opposition,” Houck added, which often includes legal challenges demanding PUC response. 

Tricia Pridemore of the Georgia Public Service Commission listed several complicating factors nationwide, including regulations on federal land, local opposition, disagreements over environmental reviews and cost allocation, interconnection queue delays, supply chain constraints and multilayered planning processes with multiple responsible entities.  

These usually are not an issue in the Southeast, she said, due to its market structure, but major transmission projects there still take years to build, due to their complexity — seven years or longer for a 50-mile, 500-kV line. 

“The intensely local and regional differences are of course what makes one-size-fits-all transmission policies very challenging,” Pridemore said.  

She welcomed changes to federal policies that would remove barriers to transmission development but added: “From the vantage point of the Southeast, we must also ensure that those changes do not upend processes that are working so well.” 

The task force retained a collegial tone, but Pridemore was not alone with concerns; others cited other potential sticking points. 

Wyoming PSC Chair Mary Throne said whatever new federal process emerges should allow state and local review to play out before initiating a parallel federal process. 

“Concurrent proceedings are probably not ideal,” she said. “Certainly, in Wyoming’s case and most places in the interior West, I don’t think it’s the state and local proceedings that are slowing down the processes — not that we are incapable of our own bureaucratic delays and duplication. But understanding the local lay of the land before you start is essential.” 

Pennsylvania Public Utility Commission Vice Chair Kimberly Barrow made a similar point: “A simultaneous prefiling process that’s going on while the state process is ongoing will be problematic.” 

States appreciate the need for speed and efficiency, but parallel proceedings would be confusing for stakeholders, she added, and it would be a conflict of interest for PUC staff to participate in both at once. 

Allen said the idea of simultaneous state and federal reviews is his one significant issue with the backstop proposal. “I would much rather see the processes sequenced,” he said, adding that stakeholders should be directed toward the state review because state processes have been groomed over the course of decades and inherently are local in character. 

That said, Allen does support the idea of backstop authority. “I just worry that if we push too hard in parallel it’s going to create some complications that are going to undermine the longer-term objectives,” he added. 

French urged that FERC not make some existing problems worse as it addresses others. “While I think that our planning does need to get more anticipatory, more holistic, solving multiple needs,” he said, “I think as you do those things, it becomes much more difficult to communicate to the public and to landowners why your state needs to build this project that is maybe serving lots of different stakeholders.” 

Connecticut Public Utilities Regulatory Authority Chair Marissa Paslick Gillett said many utility regulatory agencies are having trouble recruiting engineers and other staff to do the work needed, and many of those hired are early in their careers, so technical assistance from federal agencies is helpful. 

“I will say however, sometimes it’s difficult to even take advantage of free assistance.” That might sound like an oxymoron, she acknowledged, but if a state requires a contract and a fixed timeline for anyone involved in the process, it is not. 

New York PSC Commissioner John Howard urged greater federal control over a specific area of concern for his state: getting the mandated 9 GW of electricity from offshore wind turbines to land, and someday more than 20 GW. New York has finite opportunities for radial transmission lines from each wind farm to land because of its geography, he said. A meshed offshore grid that spans RTO boundaries from New England to the Mid-Atlantic is a better solution. 

“Now is the time to begin planning for this multi-ISO meshed network,” he said. “I would pose the question to this group and to FERC: Is it time to acknowledge that the Atlantic Ocean may be a national interest corridor in and of itself? That is something we should come to grips with very quickly.” 

Howard added: “I don’t believe that the states alone will be able to find the individual leadership necessary to move this process forward.” 

Houck said California supports the goals of NIETC and backstop, but she picked apart some of the details of those proposals. Twelve months may not be enough time for a state to approve a complex project, she said, but at the end of those 12 months, the state might be able to conclude the process more quickly than FERC would if it started a backstop proceeding. 

She called for a more nuanced approach than a one-size-fits-all solution. 

Michigan PSC Chair Dan Scripps said if a proposed transmission line is entirely within a state and will serve only that state, great deference should be given to the local siting authority. “It’s unclear to me why FERC would substitute its judgment for the local siting authority — for a single-state project.” 

If a multistate RTO project benefiting multiple states is being blocked by one state, there could be a role for backstop authority, Scripps added, but FERC should limit itself to siting, and leave cost allocation and planning to the RTO.  

French made a similar point: ”If a state is, in FERC’s opinion, acting too parochially in looking at the need for the line, not considering regional and interregional benefits,” he could understand FERC stepping in. 

But if FERC finds it needs to override a state decision, he said, it should do so as narrowly as possible, and defer as much as possible to the state’s underlying proceeding, particularly on the routing of a proposed line — review of which is a large part of the state regulator’s workload. 

French also urged clarification on what exactly a FERC siting permit would entail — just routing, or also things such as interconnection and cost recovery mechanisms. “I think there is a lot of angst from folks about what approval of a line through the backstop siting process really means.” 

Duffley said she thought that with the Feb. 28 meeting, the task force had covered the ground it set out to cover. “FERC’s final rule on transmission issues, we’re all anticipating that it will be issued soon,” she said.