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December 22, 2024

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DOE Cuts NIETC List from 10 to 3 High-priority Transmission Corridors

The U.S. Department of Energy has slashed the list of 10 potential National Interest Electric Transmission Corridors it released in May to just three much narrower corridors in the third phase of its designation process, the department announced Dec. 16.

Established under the Federal Power Act, NIETCs are geographically defined areas in which the secretary of energy finds “present or expected transmission capacity constraints or congestion that adversely affects consumers,” according to the announcement published in the Federal Register. Transmission projects located within a NIETC are eligible for special DOE financing and FERC permitting processes aimed at accelerating development and construction.

DOE set out a four-step process for NIETC designations in December 2023, including an initial information-gathering phase to help identify potential NIETCs, followed by the release of the preliminary list of 10 possible corridors in May. (See On the Road to NIETCs, DOE Releases Preliminary List of 10 Tx Corridors.)

The three proposed NIETCs selected in Phase 3 are:

    • the Lake Erie-Canada Corridor, including parts of Lake Erie and Pennsylvania;
    • the Southwestern Grid Connector Corridor, including parts of Colorado, New Mexico and a small portion of western Oklahoma; and
    • the Tribal Energy Access Corridor, including central parts of North Dakota, South Dakota, Nebraska and five tribal reservations.

According to DOE, its decisions on these three corridors were based on its own analysis and the public comments it received during the first two phases of the process, as well as priorities set in the department’s National Transmission Needs Study released in October 2023.

“Transmission development in these areas is critical to address transmission needs … unmet through existing planning processes,” DOE said. All three corridors also have one or more transmission projects under development, which DOE sees having near-term impacts on easing grid congestion, helping to put more renewable energy online and cutting consumer costs.

For example, the Lake Erie-Canada Corridor is a slimmed-down version of the Mid-Atlantic-Canada corridor on the Phase 2 list of 10 potential NIETCs. The Phase 3 version contains a smaller area in Pennsylvania and a larger area in Lake Erie. NextEra Energy Transmission’s Lake Erie Connector project, a 73-mile underwater line, could be located in the corridor, allowing for bidirectional energy flows between Pennsylvania and Ontario.

While the project is still in the early phases of development, a transmission corridor with that kind of HVDC line would increase capacity for clean energy integration on the grid, as well as support resource adequacy in PJM via the connection with Canada, according to DOE.

The Tribal Energy Access Corridor is a similarly “refined” version of DOE’s Phase 2 Northern Plains potential NIETC, with most of the corridor running along existing rights of ways and connecting several tribal reservations to existing or planned HVDCs.

The corridor includes parts of the Dakotas, Nebraska, the Cheyenne River Reservation, Pine Ridge Reservation, Rosebud Indian Reservation, Standing Rock Reservation and Yankton Reservation.

NIETC designation here could help the Transmission and Renewables Interstate Bulk Electric Supply (TRIBES) HVDC project being developed by the Western Area Power Administration and other tribal and regional stakeholders, as well as relieving congestion and preparing for future demand growth. Nebraska, for example, is becoming a hub for data center development as part of a new “Silicon Prairie.”

While highlighting these projects, DOE noted that “NIETC designation is not a route determination for any particular transmission project, nor is it an endorsement of one or more transmission solutions.”

Why These, not Those?

Declining to comment on specific corridors, Dylan Reed, senior adviser for external affairs in DOE’s Grid Deployment Office, listed a number of reasons for the exclusion of the other Phase 2 potential NIETCs.

“NIETC designation can disrupt effective transmission planning or ongoing transmission project development in the region. That was one consideration,” Reed told RTO Insider.

“[No. 2] … there appeared to be limited [ability for] a NIETC designation to further transmission in the near term in that area. In some cases, we lacked sufficient information to be able to narrow the boundaries to facilitate timely designation,” he said.

Beyond prioritizing NIETCs that might meet shorter-term needs, DOE pointed to its own limitations of staffing and time for taking Phase 3 NIETCs to a final designation in Phase 4. The department is opening a 60-day comment period, which will include three webinars, one on each of the proposed NIETCs. The comment period will close Feb. 14, 2025.

Another key component of Phase 3 is determining whether the potential corridors will need a full environmental review under the National Environmental Policy Act. A NEPA review for each corridor could be required if DOE determines that “NIETC designation is a major federal action significantly affecting the quality of the human environment,” according to the announcement.

The department is also asking for additional input on other meetings or community engagement activities it should plan as part of its environmental reviews.

A full NEPA review could take two years, so Reed would not speculate on when final NIETC designations might be made. He also declined to speculate on what impacts, if any, the incoming administration of President-elect Donald Trump might have on the NIETC process.

But DOE said its decision not to move the other Phase 2 projects forward does not mean those areas do not have transmission needs. “Rather, DOE is exercising its discretion to focus on other potential NIETCs at this time and may in the future revisit these or other areas through the opening of a new designation process,” it said.

NIETC vs. NIMBY

Even before it was cut from the list, the Delta-Plains corridor drew strong political and public opposition within Oklahoma over the possibility of eminent domain acquisition of private lands.

As originally proposed, the corridor would have stretched 645 miles from Little Rock, Ark., through the Oklahoma Panhandle, with an 18-mile right of way in some portions.

“I won’t let anyone steamroll Oklahomans or their private property rights,” Gov. Kevin Stitt (R) posted on X. “The feds don’t get to just come here and claim eminent domain for a green energy project that nobody wants.”

Attorney General Gentner Drummond (R) sent a letter to U.S. Energy Secretary Jennifer Granholm calling the corridor “classic federal overreach” and pledged to protect private property rights.

DOE gave Oklahoma’s leadership advance notice on Dec. 13 that the Delta-Plains corridor would not be moving forward.

With or without a NIETC, the region does not lack for proposed transmission projects that could run into similar NIMBYism. The Southwestern Grid Connector corridor will graze the western edge of Oklahoma’s state line. DOE notes two projects in development in the potential NIETC: the Heartland Spirit Connector project by NextEra Energy Transmission, and the Southline Phase 3 project by Grid United.

Invenergy also has proposed the Cimarron Link to unlock access to the Oklahoma Panhandle’s “inexhaustible wind energy.”

SPP, which operates the grid in Oklahoma, has approved several large projects in the state as part of its 2024 Integrated Transmission Planning assessment. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.)

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Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024

BOSTON — Energy experts from across the Northeast gathered for Raab Associates’ New England Electricity Restructuring Roundtable on Dec. 13 for a preview of some of the key issues that will dominate policy discussions in the coming year.

While 2024 brought notable success on state-level climate policy in Massachusetts, the new year brings significant uncertainty regarding whether the change in federal administration will slow the momentum of the clean energy transition in the region. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)

Prior to the passage of a major omnibus climate bill in November, “the first thing on the list of challenges was siting and permitting,” said Rebecca Tepper, secretary of the Massachusetts Executive Office of Energy and Environmental Affairs.

The new climate law creates a streamlined siting and permitting process for clean energy infrastructure, capping the state’s review of permitting applications to 15 months for large projects. Tepper said collaboration between a wide range of stakeholders through the state’s Commission on Energy Infrastructure Siting and Permitting was essential to passing the bill with widespread support.

Looking forward, Tepper said the state’s “big challenge for [2025] is interconnection; you’re going to see us really focusing on that next year.”

Tepper also highlighted the possibility of another offshore wind procurement in 2025 and said the state is exploring the potential of new interregional transmission links with New York, PJM or Québec. “We see a lot of opportunity for further hydro coming from Canada,” she said.

Serge Abergel, COO of Hydro-Québec Energy Services, said increased transmission capacity between New England and Québec could help speed up decarbonization and reduce the need to overbuild renewables as the Northeastern U.S. achieves a highly decarbonized system. (See Québec, New England See Shifting Role for Canadian Hydropower.)

He said Hydro-Québec’s modeling indicates that an additional export-neutral transmission line between the regions could provide major benefits by 2040. A new line “could reduce the length of a major outage by about two days, and it could save [New England] $2 [billion] to $3 billion over those two days,” Abergel said.

Recent drought conditions have caused the company to reduce exports over the spot market to New England, causing some observers to question the reliability of Québec supply in the future and whether the benefits of new transmission capacity would justify the costs.

While ISO-NE’s exports to Québec have increased during the drought, imports continue to play a key reliability role on the grid: They earned $29 million in Pay-for-Performance credits during two capacity scarcity events this summer, far more than any other resource class. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.)

Former FERC Chair Richard Glick (left) and Jonathan Raab, Raab Associates | © RTO Insider LLC

Abergel said there is uncertainty over the degree that climate change has influenced the current drought and said the conditions are “on par with the worst cycle we’ve seen in the past.”

“Our firm commitments are always met, but our spot market sales fluctuate,” he said, adding that the New England Clean Energy Connect transmission project — which includes a 20-year contract for Québec to send baseload power to New England — should be in service in December 2025.

Hydro-Québec’s energy supply should also receive a major boost from a new agreement between Québec and Newfoundland and Labrador, which was announced the day before the roundtable. The agreement would increase the price Québec pays for power from the Churchill Falls hydroelectric generating station in Labrador while paving the way for a significant increase in generation capacity.

FERC Preview

Former FERC Chair Richard Glick, now a principal at GQS New Energy Strategies, previewed what the new year could bring for the commission.

As states work to decarbonize their power supply, Glick said the incoming Trump administration “will have an impact, but maybe not as much of an impact as some fear,” adding that he is “still very bullish on what’s going on in the clean energy side.”

He also praised FERC’s work on Order 1920-A, calling it “a very helpful order” that should increase the likelihood of successful transmission projects.

Regarding Order 2023, which overhauled FERC’s interconnection rules, Glick said the commission likely “didn’t go far enough” and noted that it has taken “a really long time to act on the compliance filings.” (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty.)

Under a Republican-led commission, grid operators may be afforded greater flexibility on both orders, Glick said. He added that, under the Trump administration, FERC could look more favorably at pipeline expansion projects and proposals to allow fossil generators to skip ahead in the interconnection queue for reliability purposes.

Electric Vehicle Outlook

The roundtable also featured a panel focused on transportation decarbonization, with speakers discussing the growth of the U.S. electric vehicle industry and the potential of managed charging.

Roger Kranenburg, vice president of energy strategy and policy for Eversource Energy, said he remains optimistic about the overall upward trend of EV sales despite recent growth challenges and a less favorable stance from the incoming administration. He emphasized the major role that fleet-level electrification will play in transportation decarbonization.

“Fleets are coming, and they’re going to transition faster” than individual consumers, Kranenburg said. “It’s all an economic decision.”

Chris Rauscher, head of grid services and virtual power plants at Sunrun, highlighted the potential of EVs to help eliminate peak demand costs and emissions.

There currently is “way more capacity in electric vehicles than there is in stationary storage in the U.S.,” Rauscher said, adding that, when modeling 200,000 bidirectional EVs on the New England power system, just 30% of the vehicles’ battery capacity would eliminate the need for oil peakers on a winter day.

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Lame Duck Permitting Push Fails; Manchin Blames House GOP Leaders

The bipartisan permitting bill that passed the Senate Energy & Natural Resources Committee is officially dead, with Sen. Joe Manchin (I-W.Va.) saying Dec. 16 it would not be included in a must-pass spending bill. 

Manchin blamed House Republicans, specifically Majority Leader Mike Johnson (R-La.), as negotiations around the issue failed and it will not be included in the last legislative vehicle to make it out of this Congress. 

“By taking permitting off the table for this Congress, Speaker Johnson and House Republican Leadership have done a disservice to the incoming Trump administration, which has been focused on strengthening our energy security and will now be forced to operate with their hands tied behind their backs when trying to issue permits for all of the types of energy and infrastructure projects our country needs,” Manchin said. 

While Republicans are poised to also take control of the Senate next year, their 53-47 majority will require votes from Democrats for meaningful permitting reform, he added. Reforming the National Environmental Policy Act, FERC’s governing statutes and other relevant laws is too far afield from the budget to be eligible for the reconciliation process that avoids the 60-vote threshold, which Democrats used to pass the Inflation Reduction Act. 

“I am very proud of the work that my friend and partner, Sen. John Barrasso, and I put in over the course of nearly two years with our colleagues on the Senate Energy & Natural Resources Committee to get the Energy Permitting Reform Act negotiated, drafted and through the committee process with a historic 15-4 favorable vote, sending a clear signal that the time is now to get this done,” Manchin said. 

As Congress was negotiating what would be included in the continuing resolution it needs to pass by the end of this week to keep the government funded, a broad group of trade associations asked for its passage.  

The American Council on Renewable Energy, American Chemistry Council, Advanced Energy United, Center for LNG, Clean Energy Buyers Association, Electric Power Supply Association, National Mining Association, Solar Energy Industries Association, the U.S. Chamber of Commerce, and dozens of others signed onto a letter urging Congress to pass a bill. 

“America’s energy industry is united in one common goal — providing affordable, reliable, cleaner domestic energy,” the letter said. “But our current permitting system frequently prevents us from accomplishing that goal, bogging down our projects in bureaucratic delays and endless litigation. For example, it can take, on average, up to 10 years to permit a single transmission line and 29 years to move mining projects through the federal permitting process, 3-8 years just for litigation.” 

Another letter from 25 conservative and “free market” groups, led by the Competitive Enterprise Institute, urged Congress to wait until its next session to pass permitting legislation. They specifically argued against increasing the federal role in electric transmission siting. 

“It makes no sense for Republicans to move forward with legislation now when next year they will control the House, the Senate and the White House,” the CEI-led letter said. 

“Anything that Republicans and those who want genuine permitting reform can get now they can get next year, and much more. There would be less need for compromise, such as by enacting harmful transmission policy that would untap the Inflation Reduction Act subsidies and primarily serve to put unreliable electricity generation on the grid (i.e. wind and solar).” 

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Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros

Speakers at the PJM Public Interest and Environmental Organizations User Group’s meeting Dec. 10 said the growth of local transmission projects is a major contributor to grid upgrades making up an increasing share of rates.

RMI’s Claire Wayner said transmission and distribution are making up an increasingly larger amount of consumers’ energy spending even as the number of line miles built is decreasing. Compared to regional projects that are reviewed at multiple levels to ensure reliability is delivered at least cost, local projects lack transparency and oversight, she argued.

Wayner co-authored a report for RMI, released in November, that recommended several changes to the regulation of local projects. It showed that while transmission spending nationwide hit a new high in 2023 — accounting for 24% of consumers’ bills in 2020 compared to 10% in 2005 — the share of transmission spending that went to high-voltage projects has declined, falling from 72% in 2014 to 34% in 2021. In PJM, spending on local projects increased 26-fold between 2009 and 2023.

Many states don’t require certificates of public convenience and necessity (CPCNs) for local projects, which Wayner said effectively exempts them from review at public utility commissions. In addition to expanding CPCN requirements, she said states can also create electric transmission authorities and establish expedited cost recovery for projects that have undergone regional review.

Wayner recommended that FERC require independent transmission monitors, consider performance-based regulation, and rework its formula rate process to eliminate the presumption of prudence and RTO adder for local projects that do not undergo regional review.

She also argued that PJM could improve its processes by creating windows for utilities to submit local needs to be reviewed by the RTO as it plans regional solutions; standardizing definitions and tracking of local projects; and providing states with more opportunities for input on regional planning.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he has submitted cost-related questions on dozens of local, supplemental projects in PJM’s Planning Community portal and often received what he deemed inadequate or incomplete responses. In some cases, answers simply referred him back to the PJM website, which does not provide the detailed cost breakdowns he was seeking, he said.

“There is no ability to get more specific cost information than the sticker price of these projects,” he said.

Poulos also identified 31 instances in 2023 in which supplemental projects presented to PJM’s Transmission Expansion Advisory Committee were either already under construction or had been completed. He questioned what value there can be from stakeholder input on local projects that have already been completed.

CAPS has hired a consultant to further investigate how PJM’s tracking of supplemental projects can be improved, he said.

Advocates Lay out 2025 Priorities

Poulos also presented several issues that consumer advocates intend to focus on next year, including changes to PJM bylaws and governance, removing barriers to storage development, improving participation in demand response programs and a sub-annual capacity market design.

With rising capacity prices and the elimination of energy efficiency from PJM’s markets, Poulos said it is increasingly important for stakeholders to find opportunities for load to participate in the markets.

“It’s a part of the equation that has just been ignored for way too long,” he said.

Because consumer advocates make up one of five member sectors at PJM but only hold about 4% of non-sector-weighted votes at lower committees, he expressed skepticism that the stakeholder process could yield such changes directly.

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Texas Public Utility Commission Briefs: Dec. 12, 2024

The Texas Public Utility Commission’s staff has recommended not moving forward with the proposed performance credit mechanism (PCM) market design for ERCOT as it currently is designed, setting up an interesting decision for the PUC in its final open meeting of the year. 

A day after the commissioners agreed to delay any decision until that Dec. 19 meeting, staff said in a Dec. 13 filing that the PCM market tool results in “minimal” additional resource adequacy value under its current design parameters. They also said alternative design choices would result in the PCM not complying with state law, and market modifications likely will be needed to achieve the PUC’s chosen reliability standard in the long term (55000). 

“We intend to bring this back on the 19th and make a decision on where to go forward from there with the PCM,” PUC Chair Thomas Gleeson said during the commission’s Dec. 12 meeting. 

“There’s still a lot up in the air, right?” Commissioner Lori Cobos said. She referenced ERCOT’s stand-alone dispatchable reliability reserve service still under development, the Real-time Co-optimization plus Batteries project, and important questions surrounding the ancillary service demand curves, all of which are to be brought online before the PCM. 

“You have to put those into a structure then and put them into operation and be able to get this analysis to be able to understand whether [they’re] working or not,” Cobos said. 

Gleeson said during a conference in September the PCM should be placed on the back end of other market changes. 

“We have a number of tools at our disposal. We should try to see if we can meet our reliability goals with those tools before we look to implement something that’s new and novel and that we don’t really know how it interacts with the rest of our market,” he said at the time. (See “Market Participants Pan PCM,” PUC’s Gleeson at Texas Clean Energy Summit: Smooth Tenure Turns ‘Interesting’.) 

The commission in August directed ERCOT and the Independent Market Monitor to complete updated assessments on the PCM’s cost to and effects on the market and file a report on the costs and benefits of continuing the program. Staff then reviewed the assessments before making their recommendation.  

Staff said the ERCOT assessment, conducted with the Energy and Environmental Economics (E3) consulting firm, recommended refinements to the PCM’s design be considered so the tool could have a more substantive impact on reliability before eliminating it as a potential option. 

The IMM found the PCM to be a “novel form of a capacity market” in that it settles based on after-the-fact availability rather than ex-ante based on expected availability. Staff noted the monitor also concluded the PCM would provide a new source of revenue for generators that would increase ERCOT’s capacity margin and the costs to customers but reduce shortage revenues. 

The monitor said the PCM’s net costs are likely to exceed $1 billion annually in the short term because its cost cap provision is likely to bind. Eventually, the higher capacity margins would reduce the frequency of shortage pricing, with the net costs falling to $350 million to $725 million per year. Without the cost cap, those costs would range from $930 million to $2 billion, the IMM said.

The PCM was selected as ERCOT’s new market design in 2023 by the PUC, then under the chairmanship of Peter Lake. In February 2024, ERCOT and E3 filed a strawman design with 37 parameter decisions, leading to months of workshops and stakeholder discussion. 

The mechanism would reward thermal generators with credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

Two New TEF Applications

The commission approved two more applications for Texas Energy Fund (TEF) loans identified by staff and advanced them for due diligence (56896). 

The NRG Energy and WattBridge Energy IPP Holdings projects represent 1,231 MW of potential new generation and replace an apparently fraudulent project submitted by a company with suspect backing that left a nearly 1,300-MW hole in the fund’s portfolio. (See Texas PUC Rejects Possible ‘Fraudulent’ Loan Application.) 

The additions bump the TEF’s In-ERCOT Generation Loan Program portfolio to 18 applications offering 9.72 GW of potential new generation. They are seeking $5.34 billion in loaned funds. The Texas legislature has allocated $5 billion to the fund. 

The NRG application is for a new 721-MW natural gas combined cycle unit at its Cedar Bayou plant near Houston. WattBridge submitted applications for four projects totaling 1,600 MW. The company uses 48-MW aeroderivative gas turbines.  

The TEF was established by state law and voters in 2023 and offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable, primarily thermal, generation. The fund has four separate programs.

Entergy Resiliency Plan Approved

The commission approved Entergy Texas’s “Future Ready” resiliency plan, a $335 million, three-year proposal consisting of six resiliency measures that begins next year. Each of the measures is intended to prevent, withstand, mitigate or more promptly recover from the risks posed by one or more specified and defined resiliency events to the utility’s transmission or distribution system, Entergy said (56735). 

Entergy hopes to gain PUC approval of $137 million in projects and to seek conditional approval and include $198 million of additional resiliency projects under the TEF’s Outside ERCOT Grant Program. Once it’s up and running, the program will award grants for infrastructure modernization, weatherization, reliability and resiliency improvements, and vegetation management. 

Entergy also is making a second attempt to secure funds from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships program to help with its $107.5 million infrastructure and grid hardening project in Port Arthur, Texas. The utility’s staff told commissioners they are negotiating with the DOE over a $54 million cost-sharing portion of the plan. 

An administrative law judge found a settlement reached between Entergy and PUC staff, the Office of Public Utility Counsel and several consumer groups to be in the public interest.

Glotfelty Closes His Last Meeting

Commissioner Jimmy Glotfelty was given the honor of adjourning the open meeting with a ceremonial gavel honoring his 3½-year tenure on the PUC. It was the commissioner’s last meeting after announcing Dec. 4 he would step down. (See Texas PUC’s Glotfelty to Resign from Commission.) 

“This has been a wonderful opportunity, serving with you all and serving with the prior commissioners that have come before us,” Glotfelty said. “It has been a proud time in my career. It’s my hope that we’ve done it with honor and that we have done it knowing the gravity of our decisions can mean life and death.” 

“Thank you for all the work you did on my nuclear project. I appreciate you getting it started for me so I can take it over,” joked Gleeson, who will pick up Glotfelty’s role leading the PUC’s advanced nuclear reactor effort. “We’re definitely going to miss you. You’re leaving a big hole up at this dais with you walking out.” 

Glotfelty then gaveled the meeting to a close. “I announce us adjourned,” he said.

PUC Hires External Affairs Chief

Gleeson opened the meeting by announcing Lucy Nashed’s hiring as the agency’s new chief of external affairs. She will oversee the PUC’s external-facing divisions (communications, government relations, public engagement, utility outreach and consumer protection) and their strategy and day-to-day operations. 

Nashed previously directed communications for Texans for Lawsuit Reform over eight years. The organization advocates for a “fair and efficient” legal system and against “abusive and unnecessary litigation.” 

The commissioners also passed a motion requesting the Office of the Attorney General to intervene in Rio Grande Electric Cooperative’s petition from a declaratory order from FERC. The cooperative requests FERC not to assert jurisdiction over public utilities not presently under the Federal Power Act after RGEC disconnected from WECC and interconnected with ERCOT (EL25-23). 

The cooperative said that while some of its distribution lines served by its WECC transmission facilities cross state lines to serve end-users in New Mexico, the energy is carried by RGEC’s non-jurisdictional distribution facilities and would not constitute wholesale transmission in interstate commerce. 

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CISA Seeks Comments on Cyber Response Plan Update

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) is taking comments on its draft National Cyber Incident Response Plan (NCIRP), developed alongside the Office of the National Cyber Director (ONCD) and with input from industry, which was published Dec. 16 in the Federal Register.

CISA has been revising the NCIRP since October 2023, as directed in the National Cybersecurity Strategy published by the Biden administration earlier that year. The NCIRP, originally published in 2016, is meant to serve as “the nation’s framework for coordinated response to significant cyber incidents.” However, the changing cyber threat landscape and national response capabilities have undergone significant changes since the original publication — not the least of which is the establishment of CISA and ONCD themselves.

“Today’s increasingly complex threat environment demands that we have a seamless, agile and effective incident response framework,” CISA Director Jen Easterly said in a statement. “This draft NCIRP update leverages the lessons learned over the past several years to achieve a deeper unity of effort between the government and the private sector. We encourage public comment and feedback to help us ensure its maximum effectiveness.”

The goal of the NCIRP was to set out, in broad terms, the structures of the federal government’s response to cyber incidents and its relationship to federal agencies; state, local, tribal and territorial governments; the private sector; and civil society. Entities should not approach it as “a step-by-step instruction manual on how to conduct a response effort,” CISA said, noting that “every incident and every response is different.”

The plan’s authors laid out four lines of effort: asset response, threat response, intelligence support and affected entity response.

Asset response involves helping affected entities protect their assets, mitigate vulnerabilities and reduce the impact of cyber incidents. Threat response means coordinating law enforcement and national security investigations, collecting evidence and facilitating information sharing.

Intelligence support refers to building situational threat awareness, while affected entity response refers to supporting affected entities’ efforts to manage the impact of a cyber incident.

Cyber incident response comes in two main phases, according to CISA: detection and response. Detection involves the discovery, reporting and validation of an incident, as well as assessing whether it qualifies as a significant cyber incident, which 2016’s Presidential Policy Directive 41 defines as a cyber incident or group of incidents that likely will cause harm to U.S. national security or economic interests, foreign relations, or the liberties or public health and safety of the American people.

Detecting events and validating their severity requires “active engagement with service providers, the cybersecurity community, and critical infrastructure owners and operators,” the plan said. The detection phase begins when a cyber incident is identified and involves a series of key decisions including determining the incident’s severity, engaging private sector stakeholders for additional information, and understanding the scope and impact of the incident.

In the response phase, entities act to contain, eradicate and recover from incidents, while assisting law enforcement agencies with their investigations. Key decisions in this phase include determining which non-governmental stakeholders can best contribute to solution development and implementation, identifying shared priorities for response and deciding what additional resources might be needed for effective mitigation.

After a significant cyber incident, the Cyber Response Group in the office of the president must order a review of the response and prepare a report within 30 days. A declaration of a significant incident will terminate 120 days after the declaration or its last renewal. The government’s Cyber Safety Review Board also will review the incident to find areas for improving cyber response practices in the public and private sectors.

Cybersecurity has become a constant concern in recent years as nation-state rivals have sought to gain advantages over the U.S. by threatening the integrity of critical infrastructure including the electric grid. CISA has issued multiple warnings this year about electronic infiltration from actors sponsored by Iran and China, which have used sophisticated techniques called “living off the land” to disguise their intrusions as normal network traffic. (See Agencies Describe a Year of Iran Cyber Attacks.)

Members of the public have until Jan. 15, 2025, to register comments on the NCIRP.

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Stakeholders Turn down NYISO Reserve Performance Penalties

The NYISO Business Issues Committee on Dec. 11 tabled an ISO proposal to levy financial penalties against consistently underperforming generators in the reserve market, though it supported a related measure intended to better identify such resources so they can be removed.

The Operating Reserves Performance Penalty proposal, presented to the Installed Capacity Working Group in November, consisted of two components. The BIC declined to recommend that the Management Committee approve assessing the financial penalties, which would require tariff changes and was not well received by members of the ICAPWG. (See Stakeholders Skeptical of NYISO Performance Penalty Proposal.)

“We’ve received robust feedback across multiple meetings, and in the holiday spirit, it makes me feel a bit like a chestnut roasting on an open fire at times,” said Nathaniel Gilbraith, NYISO manager of energy market design.

While NYISO believed that the performance penalty proposal was “reasonable and commensurate” with the issue of underperformance, the ISO recognized that stakeholders preferred focusing on disqualification and removal of poor performers, Gilbraith said.

The dollar value of these poor performers ranges between $100 million and $260 million per year, according to the ISO.

The committee did, however, support the second component, which is to establish a rebuttable presumption for resources found to be underperforming. Those resources would be removed from the market unless they can demonstrate that the cause of the poor performance has been fixed. As part of that, NYISO would establish three different metrics for assessing underperformance. The BIC recommended directing the ISO to describe the “consequences for persistent operating reserve market underperformers” as described in the original proposal.

If approved by the MC at its meeting Dec. 18, NYISO would develop a new proposal in the first quarter of 2025 to be presented for feedback and aiming for stakeholder approval by the end of next year.

The BIC’s motion specified that “the proposed process enhancements will not alter the NYISO’s existing tariff authority to remove operating reserves qualification from suppliers that consistently underperform.”

It passed with four abstentions and New York City in opposition.

“As I understand it, the removal will occur after some period of time, but during that period of time, these market participants are still going to be compensated for a service they have not provided,” said Kevin Lang of Couch White, speaking on behalf of the city. “From the perspective of a consumer, that is unjust and unreasonable.”

Lang said that while the city supported removing bad actors, without the financial penalties, the proposal did not fully address the issue.

“We are extremely concerned that the NYISO is not going to pursue what, quite frankly, we thought was the totality of this,” he said.

NYISO staff clarified that penalties could be reexamined in 2025. Lang was not satisfied, later saying that this was not a “market design complete” proposal, something he blamed on the rushed process toward the end of the year.

Mark Younger of Hudson Energy Economics agreed.

“I hope we can do this at a high level and get through this alternative motion quickly, and get on with the holiday period,” Younger said. “It should be no surprise to anybody that I thought the process we took to get here was a total disaster. … You heard vociferous and, as you tended to note, very consistent and clear concerns that were ignored until about a week ago.”

Younger added that he hoped NYISO would have this “all wrapped up by the end of April.”

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Strong 2025 Predicted for US Blue Hydrogen

Wood Mackenzie predicts that the U.S. low-carbon hydrogen sector will focus on blue rather than green in 2025 as federal leadership turns from blue to red. 

Regulatory uncertainty, policy changes and competition for the renewable power used to generate green hydrogen will have a significant impact, the data and analytics firm said in its newly published forecast. 

But Wood Mackenzie does expect 2025 to be a pivotal year for the hydrogen and ammonia sectors despite the challenges that persist.  

“We anticipate increased levels of activity across both sectors and a shift towards greater commercialisation, with some surprises along the way,” principal analyst Bridget van Dorsten wrote Dec. 12 in announcing “Hydrogen: 5 things to look for in 2025.” 

Wood Mackenzie’s analysts expect the U.S. to solidify its position as the world’s leading producer of blue hydrogen as the second Trump administration begins. Over 1.5 Mtpa of U.S. blue production capacity will reach final investment decision in 2025, the report predicts, over 10 times more than for green hydrogen. 

The Biden administration’s push to develop the clean hydrogen sector has been slow to develop momentum, and the report envisions some significant headwinds for U.S. green hydrogen as President Trump returns to office. 

“While there will still be some demand driven by corporate decarbonisation efforts, near-term opportunities for green hydrogen will shrink, and we anticipate a substantial uptick in cancellations, particularly for projects targeting mobility, steel and e-fuels,” the authors write. 

A dozen or more colors and shades exist to designate the means by which hydrogen is produced. Truly green hydrogen is produced from water with renewable power and creates no carbon dioxide emissions, while blue hydrogen is generated from natural gas, with resulting CO2 captured and sequestered or repurposed. 

The distinctions and details are of intense interest to industrial and environmental lobbyists, and neither side seems happy with the state of affairs. Over two years after Biden’s signature Inflation Reduction Act passed, there still is no final guidance for the 45V tax credit for clean hydrogen production. 

Trump has railed against the Inflation Reduction Act and various aspects of the clean energy transition, placing the future of 45V and Biden’s Hydrogen Hub initiative in question. 

But Wood Mackenzie expects that the 45Q tax credit — for investment in carbon capture and storage — will receive continued support, as it is strongly backed by the oil and gas industry. 

The report predicts some 2025 growth in green hydrogen outside the U.S., with at least one giga-scale project reaching final investment decision. 

It sees strongest growth in China, India and the emerging economies of Latin America and the Middle East where there are low-cost renewable options, supportive government initiatives and availability of low-cost Chinese-made electrolyzers. 

However, Wood Mackenzie also expects a continued mismatch between investments in production and contracts for output. 

Of the 5.5 Mtpa of low-carbon hydrogen projects that have taken final investment decisions, the report notes, 2.5 million tons is uncontracted, most notably within U.S. blue hydrogen. 

Even as some of these blue hydrogen projects start to unwind their uncontracted positions, overall uncontracted volumes are expected to rise. 

The report also predicts growing momentum for the low-carbon ammonia space. It estimates an $8 billion investment across the value chain in 2025, double the amount seen in 2024. 

“A key driver will be the strategic investments aimed at enabling offtake agreements, as projects push forward with greater certainty,” the authors write. “Many of these investors are targeting new energy markets for hydrogen (e.g. maritime, aviation, etc.), where demand for low-carbon ammonia is rising, positioning themselves to secure long-term offtake agreements as the market scales.” 

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FERC OKs CAISO Plan to Streamline Interconnection Process

FERC on Dec. 16 approved CAISO’s request to further streamline its generator interconnection process in response to the high volume of requests in its interconnection queue.  

The commission’s order permits the ISO to apply six sets of tariff revisions related to its Generator Interconnection and Deliverability Allocation Procedures (GIDAP) and associated Generator Interconnection Agreements (GIAs) to resources that joined the queue in Cluster 14 — which opened in April 2021 — or earlier. 

The tariff revisions won’t apply to interconnection customers that already have executed GIAs or have requested that GIAs be filed unexecuted.  

In September, FERC approved a larger proposal to streamline the ISO’s interconnection process starting with 2023’s Cluster 15 and beyond. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)  

The newest tariff amendments are intended to manage the “large volume of interconnection requests already studied but for which GIAs have not yet been executed,” the commission noted in its order (ER25-131). The revisions are a result of the ISO’s Interconnection Process Enhancements (IPE) initiative, which involved over a year of stakeholder engagement that led to the approval of refinements to the process.  

The IPE proposal is intended to complement — not replace — CAISO’s FERC Order 2023 compliance filing, which is still pending approval. The order states that, while the tariff revisions in the most recent filing touch on some reforms in the Order 2023 filing, “CAISO does not propose revisions to any section of its tariff pending commission acceptance.”  

The six sets of tariff revisions the commission approved Dec. 16 will:  

Subject new small asynchronous generating facilities in Clusters 14 or earlier to fault recording requirements that CAISO currently applies only to asynchronous generating facilities larger than 20 MW. 

    • Update the granularity of phase angle measuring unit data for asynchronous facilities by increasing the sampling rate of that data. 
    • Unify the payment and authorization schedules among interconnection customers sharing network upgrades to develop a construction timeline necessary to meet the earliest interconnection customer’s commercial operation date. 
    • Increase the material modification assessment (MMA) deposit cost from $10,000 to $30,000 and extend the estimated time to complete an MMA from 45 days to 60 days.  
    • Create a new “implementation deposit” of $35,000 to cover specific customer costs after completion of interconnection studies in order to avoid passing off those costs to other market participants.  
    • Limit the ability of a customer to linger in the queue after it gives up its deliverability rights. 

The commission said CAISO’s proposals “will improve the accuracy of data about the system, help mitigate reliability issues, enhance the certainty and efficiency of the network upgrade process, ensure that the costs of managing interconnection requests between GIA execution and commercial operation are not allocated to all market participants, and reduce administrative overhead.”  

The new rules become effective Dec. 17.  

Robert Mullin contributed to this article. 

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CAISO Launches New Initiative for Storage Resource Design

CAISO on Dec. 11 kicked off a new Storage Design and Modeling Initiative intended to tackle an array of challenges related to the market participation of storage resources, including further addressing bid cost recovery (BCR) issues and developing a default energy bid (DEB) formula specifically for batteries.  

The initiative piggybacks off the ISO’s prior storage BCR working group, which identified that BCR provisions don’t align with storage resources and led to passage of a proposal to modify the calculation used to determine BCR payments. (See Proposal to Refine Bid Cost Recovery for Storage Passes Unanimously.) 

But several stakeholders, along with CAISO’s Market Surveillance Committee and Department of Market Monitoring, emphasized that the proposal was only a first step in addressing the number of problems identified with storage BCR and their default energy bids.  

The new initiative will delve into previously identified problems, including the need for a holistic redesign of the uplift mechanism for storage and changes to the DEB that reflect the specific characteristics of the resources. It will also introduce new ideas designed to further integrate batteries efficiently into the ISO market, including a proposal to develop a state-of-charge (SOC) mechanism and a way for storage batteries to bid into the market based on their SOC.  

The working group’s effort will be separated into three topic groups: The first deals with BCR, the DEB and outage management systems (OMS); the second covers all topics related to state-of-charge management; and the third deals with distribution-level and paired resource topics.   

Bid Cost Recovery, Default Energy Bid Modification

While CAISO’s completed storage BCR and DEB initiative closed a major market design gap related to existing BCR for storage resources, the ISO identified a further need to address storage assets’ lack of exposure to real-time prices if they deviate from their day-ahead schedules. As a result, the new initiative will seek to redesign the storage uplift mechanism, Sergio Dueñas Melendez, storage sector manager at CAISO, said during the meeting to launch the effort.  

In prior working groups, stakeholders also recommended modifications to the storage DEB and the desire to consider standard approval for storage reference level change requests, which are currently manually processed by ISO staff. Automation and standard approval would provide clarity for market participants, Dueñas Melendez said.  

Lastly, the ISO is seeking to enhance the outage management system (OMS) to align with storage resources, which includes reviewing lower and upper SOC real-time biddable parameter use, clarification of how SOC physical outages impact Pmax and Pmin outages, and improvement of OMS functionality to better support outage submissions from storage assets.  

State-of-charge Management

The ISO is considering developing a “system SOC” mechanism that would track total energy available across the entire storage fleet.  

“Thinking about the fleet holistically may allow better optimization of that storage fleet in critical conditions,” said Dinesh Das Gupta, policy developer at CAISO.  

The system SOC mechanism will work in tandem with how the market operates, so it would be an addition to the system, not a replacement.  

CAISO is also considering developing a “biddable SOC market participation pathway” that would allow energy storage resources to offer charge and discharge bids in relation to their SOC.  

“The vast majority of storage resources participate in the market through the non-generator resource model, which approximates values through megawatt price bid pairings,” Das Gupta said. “A new pathway option centered on bidding at a given SOC may address multiple needs that are currently not found with the non-generator model.”  

Developing this new pathway would take additional time from a policy and technical perspective, Das Gupta highlighted.  

The ISO also highlighted the need to modify the SOC definition and calculation, after determining that resources may face physical constraints not reported to the market that prevent dispatch. Refining how SOC is defined and calculated would improve the ISO’s confidence in a storage resource’s ability to follow dispatch signals during tight system conditions, Das Gupta said.  

The working group will also consider the nonlinearity of a storage resource’s SOC. Non-generator resources are modeled linearly, but energy storage resources have non-linear maximum charging and discharging abilities. Better accounting for this nonlinearity, especially under extreme conditions, may improve storage resource performance, Das Gupta said.  

Finally, the ISO highlighted the need to explore SOC management for capacity awards. The current SOC calculation doesn’t fully model the impacts of capacity awards, particularly for the ISO’s flexible ramping product, which could result in storage resources being unavailable for other commitments, potentially jeopardizing reliability.  

“With the flexible ramping product, we’re seeing potentially serious implications given the price of the product and the high percentage of the product being provided by storage resources,” Das Gupta said.    

Distribution-level Resources

Distribution-level storage assets provide wholesale energy storage to the system via the distribution network rather than through a direct interconnection at the bulk transmission level. These assets fall under both the ISO tariff and the distribution level tariff, and aligning the two would “enhance operational confidence for both resources,” Das Gupta said.   

Additionally, due to significant growth in co-located resources, each with unique parameters and challenges, the ISO is also seeking to explore settlement provisions, including BCR, following increased operational experience with co-located resources.  

The last effort in this topic group seeks to address the lack of a DEB for hybrid resources. Developing a bid for such resources would allow bidding up to the soft-offer cap.  

Next Steps

CAISO expects to release a straw proposal for the initiative in March 2025, with a final proposal slated for July.