A three-judge panel on the U.S. Court of Appeals for the District of Columbia has vacated a safety rule on transporting liquified natural gas over rail.
The Sierra Club, a group of state attorneys general and others filed an appeal of a rule crafted by the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) authorizing LNG’s transportation in newly designed tank cars with no permit required.
“The new final rule … imposed no limit on the number of LNG tank cars that could be included in a single train and set no mandatory speed limit for trains that carry LNG,” said the Jan. 17 decision.
One company was considering a single train with 80 cars carrying LNG, when a group of environmentalists said that the explosive force of just 22 cars full of LNG would be the equivalent of the atomic bomb dropped on Hiroshima.
In addition to being highly flammable, LNG has the risk that if its temperature rises, it can expand and place tremendous pressure on tanks leading to an explosion. If it is spilled without igniting, it can form an ultra-cold gas cloud that quickly expands, severely injuring people and damaging property in its path, the court said.
PHMSA determined shipping LNG by rail would have no significant impact on the environment and declined to prepare an environmental impact statement. Sierra Club and other petitioners argued that the National Environmental Policy Act required the agency to craft an EIS and its failure to do so was arbitrary and capricious. The court agreed, vacating the rule for additional proceedings at PHMSA.
Historically, LNG could be transported only by truck or pipeline, and shipping it by train required a special, one-off permit. That changed after President Trump issued an executive order in 2019, which told PHMSA to issue a blanket approval for shipping LNG by rail.
The agency authorized that the fuel could be shipped in tank cars that had been operating on the rails for decades and were designed to carry cold, dense gases. The rules for shipping similar chemicals involved communication, and the rail industry adopted a voluntary speed limit of 50 mph when trains had more than 20 cars with them. PHSMA proposed no such limits to trains hauling LNG.
Opponents criticized the rule for failing to take the risk of an accident seriously and for failing to put a speed limit or a cap on the number of cars. They also argued the train cars to be used, DOT-113 tank cars, had seen 14 breaches in prior incidents and petitioners questioned their record, as did the National Transportation Safety Board.
PHMSA did require some upgrades for the cars to carry LNG, including a thicker outer tank and better steel, calling the new model a “120W9” car. It also authorized the new cars to carry a higher density of LNG, raising it from 32.5% of total volume to 37.3%.
The agency required special monitoring equipment for all LNG cars and required trains with 20 in a row, or 35 in total, to have special braking technology. Railroads also were required to consider safety risk factors such as population density when scheduling LNG shipments.
After President Biden assumed office, PHMSA suspended the July 2020 rule, but it did not complete a replacement.
Though no utilities have been blamed for the deadly wildfires in Los Angeles so far, stakeholders have cautioned that companies like Southern California Edison are not completely out of the woods and still face financial and legal risk.
Commenting on the wildfires in a Jan. 16 newsletter, investment bank Jefferies noted that electrical monitoring company Whisker Labs did not find evidence of a major transmission line fault before the Eaton Fire erupted. The blaze burned more than 14,000 acres, causing damage to thousands of structures and at least 17 fatalities, according to officials.
However, Whisker Labs found there were energized distribution lines west of Eaton Canyon despite warnings about high winds prior to the fire’s start, the newsletter stated.
Whisker Labs cannot point to a specific source for any fault event, but “based off of multiple faults detected in the lead up to the fire’s reported start time, the team confirmed with certainty there were energized distribution lines west of the fire,” according to Jefferies.
SCE, one of the area’s largest utilities, told RTO Insider on Jan. 13 that no fire agency has suggested its facilities were involved in igniting the Eaton Fire.
Local utility Pasadena Water and Power also operates in the region.
Still, if SCE’s equipment is found to be at fault down the line, the utility’s credit rating could take a hit, Moody’s Ratings cautioned in a report Jan. 16, per Reuters. The report also said the company could see financial damage if the California Wildfire Fund runs out of money. Utilities pay into the fund to receive reimbursements for some wildfire claims.
Additionally, legal challenges are already starting to trickle in. Some affected by the Eaton Fire filed lawsuits against SCE last week, alleging the blaze began under one of the company’s transmission towers. SCE has also received preservation notices from counsel representing insurance companies.
Another issue is whether SCE took adequate measures to mitigate risks under its California Public Utilities Commission-approved Wildfire Mitigation Plan, Jefferies contended.
“To date, we have not seen evidence supporting ‘serious doubt’ of prudency, but we will be closely looking to see whether EIX followed its preemptive safety power shutoffs to the letter,” Jefferies stated.
Fire agencies are investigating whether SCE equipment was involved in the smaller Hurst Fire, the utility announced Jan. 12.
SCE said the Hurst Fire was reported at approximately 10:10 p.m. and that a 220-kV circuit experienced a relay at 10:11 p.m. A downed power line was discovered at a tower associated with the circuit, and “SCE does not know whether the damage observed occurred before or after the start of the fire,” the utility added.
The NYISO Operating Committee has approved the final Locational Capacity Requirements for the 2025/26 capability year. These were the same LCR values presented earlier to the ICAP working group.
The LCRs, expressed as a percentage of the peak load forecast, represent the minimum capacity New York’s generators and load-serving entities must maintain within each of the downstate zones, which have transmission constraints.
“I’m going to vote yes because the ISO did the LCR study consistent with all its rules,” said Mark Younger of consulting firm Hudson Energy Economics. “However, I am quite concerned that we still have a major inconsistency between the transmission security needs that are represented in the TSLs [transmission security limits] and ultimately affect the LCR.”
2025-2026 final LCR results | NYISO
Younger said this had been an issue for several years, had been undercutting price signals and was more important now because the ISO had found a reliability need in its most recent RNA.
Operations Report, December 2024
NYISO also presented the monthly Operations Report for the previous month. The peak load, 23,065 MW, occurred Dec. 23, 2024.
Over the last month of 2024, 2,736 MW of land-based wind, 136 MW of offshore wind, 6,048 MW of behind-the-meter solar and 571 MW of front-of-the-meter solar were installed. Additionally, 63 MW of energy storage was installed.
Aaron Markham, vice president of operations, noted that NYISO was taking preparatory action for severe winter weather. NYISO said it was prepared to meet anticipated demand for the current cold snap.
NYISO expected demand to peak at 24,400 MW on Jan. 21 and 24,200 MW on Jan. 22.
NYISO’s 2024/25 Winter Assessment found that 29,514 MW of resources were available statewide; 2,275 MW were available through emergency dispatch.
BOSTON — Managing the often-at-odds priorities of affordability, reliability and decarbonization will require a delicate balance of innovation, market reforms and stability, industry experts told attendees of the Northeast Energy and Commerce Association’s Power Markets Conference on Jan. 16.
Speakers discussed some of the major changes on the horizon for the region’s wholesale markets as grid operators prepare for significant load growth and an increasingly distributed and intermittent resource mix.
ISO-NE is undergoing a major effort to reform its capacity markets, which includes resource accreditation updates and changes to the timing and format of capacity auctions. FERC accepted similar accreditation changes for NYISO in July, which will take effect in 2026. (See FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay.)
Chris Geissler, director of economic analysis at ISO-NE, said the RTO is trying to design the accreditation methodology so “everyone is essentially selling the same product.”
The proposed accreditation framework is intended to quantify how a resource would perform during the periods with the greatest reliability risks, meaning that assumptions related to the resource mix, outages and demand profile could have major effects on how different resources are valued.
For example, adding wind capacity would improve grid reliability during the periods with high wind, reducing the reliability value of subsequent additions of wind resources, Geissler said.
Meanwhile, energy storage likely will be complementary to weather dependent resources. Increasing the amount of solar or wind power on the system could improve the reliability contributions of energy storage, Geissler noted.
Michael Borgatti, senior vice president of RTO services and regulatory affairs at consulting firm Gabel Associates, said the nearly 10-fold increase in prices in PJM’s most recent capacity auction should serve as “a cautionary story for all other RTOs across the country, including NYISO and ISO-NE.” (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
Capacity prices are “a symptom of how you set the underlying supply and demand fundamentals,” Borgatti said, adding that PJM determined its capacity need on an unprecedented extreme scenario.
“PJM built its capacity model on the backs of Winter Storm Elliott,” Borgatti said. “They wanted to make sure their model reflected the possibility of these big dangerous storms matching up with the highest load.”
Despite the high prices in PJM, uncertainty regarding potential changes to PJM’s capacity market makes it hard for developers to invest in new resources that could help address the lack of capacity, Borgatti said.
New Market Mechanisms
While ISO-NE’s capacity accreditation reforms likely will increase compensation for dispatchable resources that provide winter reliability benefits, ISO-NE has indicated new market mechanisms may be needed to support resources that are called upon only in extreme situations. (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.)
The RTO’s Economic Planning for the Clean Energy Transition (EPCET) study, published in October, found a major need for dispatchable resources to meet a higher and increasingly variable winter peak. The resources, ISO-NE noted, “may only run once every few years.” (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.)
The EPCET study also found ISO-NE’s energy market likely will decrease in value as renewables supported by power purchase agreements (PPAs) come online, with the capacity market and PPAs increasing in importance. The RTO also outlined concerns that the current PPA model will struggle to support new resources starting in the mid-2030s.
“We’re going to need steel in the ground,” said Jeff Turcotte, assistant vice president of government affairs at the Electric Power Supply Association. “Markets are going to have to continue to signal that investment.”
“If we are thinking about big ideas and big investments … some of those answers are already out there.” Turcotte said, pointing to the Pathways Study, which Analysis Group conducted for ISO-NE in 2022.
The Pathways Study considered several strategies for decarbonizing the grid to meet state goals and ultimately concluded that net carbon pricing would be the most cost-effective way to reduce power sector emissions in the region. (See Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE.)
However, adopting net carbon pricing would require buy-in from all six New England states, which so far has prevented further development of this proposal.
“ISO-NE has made it very clear that it thinks net carbon pricing is the most efficient way to decarbonize the grid,” said Ashley Gagnon, senior director of Massachusetts’ office of Federal and Regional Energy Affairs. “From Massachusetts’ perspective, we’re always interested in having conversations about new market mechanisms to in connection with the future grid.”
Cutler Cleveland, associate director of the Institute for Global Sustainability at Boston University, emphasized the importance of rapid decarbonization.
“It’s quite clear that we’re not moving quite as fast as we need to avoid the wheels coming off the bus,” Cleveland said, outlining the wide range of severe consequences climate change is projected to have on human mortality, disease vectors, air and water quality, and labor productivity.
“Business as usual with decisions driven only by market forces will not work,” he said, adding opposition from politicians and the public to climate policies — including carbon pricing — “is a real problem.”
Demand Response and Load Flexibility
Another major topic of the conference was how the region can unlock savings by shifting demand away from peak hours as the electrification of transportation and heating accelerates.
Across the region, utilities are working on advanced metering infrastructure (AMI), which should enable incentives for residential customers to decrease peak demand. In Massachusetts, the utilities plan to complete their rollout of AMI by 2030, which likely will be followed by some form of time-varying rates. (See Mass. Electricity Rates Working Group Issues Recommendations.)
While there was some disagreement between speakers about whether policymakers should focus on automating demand response or rely on real-time pricing to incentivize behavioral changes, most agreed automating demand response for willing customers will be an important piece of the puzzle.
George Twigg, executive director of the New England Conference of Public Utilities Commissioners (NECPUC), said residential demand response likely needs to be automated to reach a wide scale. He noted that the commercial and industrial sectors — despite the attention given to the residential sector — likely hold the greatest potential for demand response.
Austin Dawson, deputy director of energy supply and rates at the Massachusetts Department of Energy Resources, said the state likely will need “some significant reforms” to rate design to make the most of advanced metering infrastructure, adding that long-term recommendations from the state’s Interagency Rates Working Group should be released later in January.
While electric vehicle load probably is the easiest to shift, “I don’t think we can write off heating load as a flexible end use,” Dawson noted.
He emphasized the importance of research and pilot programs to prepare for the transition to a winter-peaking system, which ISO-NE expects to occur in the mid-2030s.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Jan. 23. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:20)
B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange to conform to FERC‘s approval of PJM’s second phase of hybrid generation rules. The package also includes changes identified through the manual’s periodic review.
C. Endorse proposed revisions to Manual 1 to establish alternative communication protocols for use during an unexpected outage of PJM’s EMS Real Time Assessment (RTA) capabilities. (See “Several Manual Revisions Endorsed,” PJM MRC/MC Briefs: Dec. 18, 2024.)
D. Endorse proposed revisions to Manual 27: Open Access Transmission Tariff Accounting and Manual 29: Billing resulting from their periodic review. The changes include removing outdated references and spelling corrections.
E. Endorse proposed revisions to Manual 38: Operations Planning drafted through its periodic review.
Endorsements (9:20-11:05)
Manual 14H: New Service Requests Cycle Process Revisions (9:20-9:45)
PJM’s Jonathan Thompson will present revisions to Manual 14H: New Service Requests Cycle Process to add to PJM’s site control requirements for projects in the interconnection queue. Renewable developers have objected to the changes, arguing that they will require them to hold onto land not necessary for their projects, while PJM has held that a common standard is needed. Voting was delayed from the committee’s December meeting. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.)
The committee will be asked to endorse the proposed Manual revisions at this meeting.
PJM’s Jeff Schmitt will review a proposed charter that would convert the Data Management Subcommittee (DMS) to the Modeling Users Forum. The change would facilitate having more frequent meetings that focus on modeling tools and more long-term initiatives.
The committee will be asked to approve formation of the Modeling User Forum at this meeting.
Deactivation Enhancements Senior Task Force (DESTF) (10-10:25)
PJM’s Chantal Hendrzak is set to present a proposal to rework how generators operating on reliability-must-run (RMR) agreements are compensated, the advance notice generation owners must provide PJM ahead of bringing a unit offline, and added transparency around related processes, such as the RMR revenue allocation zonal rate and Independent Market Monitor determinations of market power. The DESTF supported the PJM-sponsored proposal over two others offered by the Monitor and RTO.
The committee will be asked to endorse the proposed solution and corresponding tariff revisions. Same-day endorsement will be sought at the Members Committee.
PJM’s Michele Greening will present revisions to an issue charge addressing how PJM’s effective load carrying capability (ELCC) framework is used in resource accreditation. The change would add a key work area examining how market participants can hold greater certainty in ELCC ratings between the Base Residual Auction (BRA) and delivery year.
The committee will be asked to approve the revised issue charge upon first read at this meeting.
2025/2026 RPM 3rd Incremental Auction Installed Reserve Margin (IRM) and Forecast Pool Requirement (FPR) (10:40-11:05)
PJM’s Josh Bruno will present a proposal to revise the IRM and FPR parameters for the third 2025/26 Incremental Auction (IA). Rising load growth in the 2025 Load Forecast has led to shifting ELCC ratings for resources participating in the third 2025/26 Incremental Auction (IA). (See “Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction,” PJM PC/TEAC Briefs: Jan. 7, 2025.)
The committee will be asked to endorse the 3IA IRM and FPR upon first read at this meeting. Same-day endorsement will be sought at the Members Committee.
Members Committee
Endorsements (11:55-12:35)
Manual 34 Revisions (11:55-12:05)
Greening will present revisions to Manual 34: PJM Stakeholder Process to codify a process for the RTO and members to follow after FERC rejects a stakeholder-endorsed proposal.
The committee will be asked to approve the proposed revisions at this meeting. Lynn Horning, of American Municipal Power, will move the motion and Ruth Price, of the Delaware Division of the Public Advocate, will second the proposed revisions.
Deactivation Enhancements Senior Task Force (DESTF) (12:05-12:20)
Hendrzak is set to present the DESTF-endorsed proposal to the Members Committee should the MRC approve the changes.
The committee will be asked to approve the proposed solution and corresponding tariff revisions at this meeting. Same-day endorsement will be sought at the Markets and Reliability Committee.
2025/2026 RPM 3rd Incremental Auction (3IA) Installed Reserve Margin (IRM) and Forecast Pool Requirement (FPR) (12:20-12:35)
Bruno will present the proposal to revise the IRM and FPR parameters for the third 2025/26 IA, should the MRC endorse the proposal.
MISO and SPP have asked FERC for a temporary departure from sections of their joint operating agreement to be able to conduct a more comprehensive interregional planning study to land on mutually beneficial transmission projects.
MISO and SPP filed the limited waiver request Jan. 15, asking for a one-time reprieve from a multiyear modeling requirement and a restrictive benefit valuation directive for their 2024/25 interregional planning cycle (ER25-943). The pair of grid operators said they don’t want to be constrained by certain sections of their joint operating agreement (JOA) when conducting their in-progress Coordinated System Plan (CSP) study and requested a response from FERC by March 15, 2025.
MISO and SPP said current JOA wording limits them to using only the value of avoided regional projects to measure the reliability and public policy benefits of interregional projects. The JOA also requires MISO and SPP, when conducting a CSP, to use multiyear modeling, which the RTOs interpret to mean using multiple model years, like two, five and 10 years out.
For their 2024/25 CSP, MISO and SPP instead want to use several differing scenarios all 10 years into the future using a combination of their respective 2034 modeling. They said they’re hopeful the study will turn up more potential projects than a broad-brush study with pit stops at five, 10 or 15 years.
MISO and SPP added that 2034 is a pivotal point, on the other side of many utilities and states’ 2030 decarbonization goals and on the road to bigger net-zero goals.
MISO and SPP also said establishing the reliability value of a project solely on its ability to avoid regional projects likely hamstrings them from analyzing projects’ usefulness in other areas, like expanding interregional transfer capability or standing the grid up to weather extremes.
“The requirement to value reliability or public policy interregional projects as the cost avoidance of pre-existing regional projects will hinder such projects from being proposed based on additional or alternative benefits. It is likely that reliability needs will be identified along the seam in the analysis, yet not observed in prior regional processes due to modeling differences or because the planned study offers a more robust evaluation of the 10-year horizon,” MISO and SPP explained.
MISO and SPP said they’re casting a wider net for interregional projects in the current CSP and want to use comprehensive reliability, economic and transfer analyses using 10-year forward modeling. They said using detailed, long-term views will help them move beyond solely “studying and resolving transmission issues” and better line up with FERC Order 1920.
This CSP would prioritize “immediately actionable enhancements,” MISO and SPP said, like upgrades in existing rights-of-way, terminal equipment, transformers or greenfield development that might not be contemplated in regional studies.
MISO and SPP decided months ago that this year’s CSP “would not yield different results” from fruitless past studies unless it considers “near-term upgrades that incrementally enhance transfer capability and yield multiple benefits across the RTOs’ respective footprints without limiting upgrades to the replacement of regional projects.”
“The RTOs believe that, unless the study scope is broadened as proposed, the 2024/25 CSP study would become a futile, pro forma exercise that would not result in recommended interregional projects,” MISO and SPP said. “History has proven that there have been high-potential projects considered, but ultimately not recommended, as cost shared interregional projects in the MISO-SPP CSP studies, and many projects have not been able to pass the interregional project criteria as narrowly defined in the MISO-SPP JOA.”
CARMEL, Ind. — MISO hopes to mete out different reserve margin obligations to its load-serving entities as it sees bigger perils on the horizon.
The grid operator says because of shifting and growing risks to the system, its reliability requirement should be reallocated among LSEs based on periods that contain the highest reliability risks. Today, MISO divvies up its planning reserve margin requirement (PRMR) based only on LSEs’ 50/50 load forecast for its coincident peak.
MISO instead would like the PRMR spread among load-serving entities based on historical load during MISO’s set of predefined risky hours that already are used to gauge capacity accreditation values.
At a Jan. 15 Resource Adequacy Subcommittee meeting, MISO’s Neil Shah said the RTO would look back one year to get an idea of historical load. The RTO first mulled using three years of historical load data but said a one-year lookback should be sufficient in an era of expanding load.
Shah said the demand uncovered in MISO’s loss of load expectation study — which is used to set the PRMR — diverges from the demand it sees in its capacity auctions. He said MISO’s probabilistic modeling “observes risks at load levels that are much higher than 50/50 coincident peak load.”
A recalibration of the PRMR distribution should remove a “misalignment” between LSEs’ obligations and the load LSEs are consuming at the times of highest need on the system, Shah said.
Shah said MISO hopes to make a filing with FERC on LSEs’ PRMR values sometime in 2025 after workshopping the proposal with stakeholders.
MISO also said portioning out the PRMR to LSEs based on demand during system risk will line up with its recently approved resource accreditation, which accredits resources based on their availability during risky hours. (See FERC Approves New MISO Probabilistic Capacity Accreditation.) MISO originally considered including a PRMR reallocation as part of the early 2024 capacity accreditation filing to FERC but later decided to hold off and make a separate filing.
On the eve of the U.S. presidential changeover, the head of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) warned that the cyber threat from China and other international rivals remains a serious concern.
In a blog post Jan. 15, outgoing CISA Director Jen Easterly noted several recent cyber campaigns targeting U.S. infrastructure by actors linked to China, such as the Volt Typhoon hacking group that CISA last year said had been actively infiltrating U.S. infrastructure organizations for at least five years. (See CISA Highlights China Threat in 2024 Priorities Report.) She also mentioned the Salt Typhoon group that breached the networks of dozens of telecommunications firms, along with federal government organizations.
Easterly recalled her testimony last year at a hearing of the House Select Committee on the Chinese Communist Party, when she warned that China’s cyber warfare forces were intent on causing “societal panic” in a future conflict over the U.S. (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.) Specifically, she reiterated her concern that China’s ambition to take over Taiwan could precipitate such a conflict.
“Chinese leader Xi Jinping has pledged on numerous occasions … to achieve ‘reunification’ with Taiwan, a move analysts assess will likely occur, either peacefully or militarily, by the end of this decade,” Easterly wrote. “Such action could be accompanied by disruptive attacks against ‘everything, everywhere, all at once:’ our transportation nodes, our telecommunications services, our power grids, our water facilities and likely much more — all with the goal of inducing societal panic and deterring our [willingness] … to expend American blood and treasure in defense of Taiwan.”
While Easterly praised the work of CISA and its partners in the public and private sectors to neutralize China’s cyber ambitions, she acknowledged that what the agency has found “is likely just the tip of the iceberg” and that facing down this growing threat will require “robust cyber defense and vigilance” from all sectors. She said CISA has three lines of effort underway to address the cyber risk:
Help victims identify and remove Chinese cyber actors from their networks.
Plan cyber defense with key partners in the information technology, communication and cybersecurity industries.
Deliver cyber threat reduction services to critical infrastructure operators.
However, Easterly also called these efforts “necessary but insufficient,” noting that the China-backed cyber actors are “largely taking advantage of known … defects” in information technology products. She also called the U.S. technology base “inherently insecure” because the industry has “prioritized features and speed to market over security” for years. Easterly warned that infrastructure partners and technology manufacturers must play their part in improving security by:
Reporting every cyber incident to CISA.
Establishing a relationship with the local CISA team and enroll in the agency’s services.
Committing to cyber resilience at the executive level.
Designing, building and deploying technology products using CISA’s Secure by Design guidance.
Easterly reportedly plans to step down Jan. 20 when former President Donald Trump is inaugurated for his second term, along with other political appointees in the agency. Trump, who fired CISA’s founding director Chris Krebs in 2020 for contradicting his claims of cyber interference in the presidential election that he lost, is said to be considering Sean Plankey, a former official of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, as Easterly’s replacement. (See After Contradicting Trump, Krebs Out at CISA.)
SPP reached a key milepost in its Western efforts Jan. 16 when FERC conditionally approved the RTO’s tariff for Markets+, a highly anticipated decision likely to ramp up the competition with CAISO’s Extended Day-Ahead Market (ER24-1658).
“We agree with SPP and various commenters that Markets+ has the potential to yield a range of benefits to market participants and customers in the Western Interconnection,” FERC wrote in the 154-page order. “We find that Markets+ will make more efficient use of the transmission capability and generation resources that participate.”
The commission said it expects Markets+ will provide its participants with “important economic and reliability benefits” and help them manage the impact of “increasing levels of variable energy resources, load growth and extreme weather events in the region.”
The order comes nearly six months after the commission issued the RTO a deficiency letter outlining 16 problems it needed to address in the tariff, which it filed last March after an intensive stakeholder process. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)
The decision indicates SPP sufficiently addressed most of those deficiencies, with FERC asking the RTO to provide clarity where the tariff “lacks specificity on key points,” as Commissioner Judy Chang noted in a concurrence, such as in protocols covering “market and resource dispatch mechanics to account for state greenhouse gas programs and the ability for resources to be aggregated when participating” in the market.
“FERC’s approval of the Markets+ tariff is an important achievement for SPP,” SPP CEO Barbara Sugg said in a press release issued after the decision. “It reiterates what we know to be true about Markets+: It’s a superior market design that recognizes and values the needs of all participants.”
“We’re thrilled to see the Markets+ tariff approved,” said Antoine Lucas, SPP’s vice president of markets, who has been instrumental in the development of the market and was promoted to become the RTO’s COO on Jan. 14. “Markets+ is a collaborative, stakeholder-driven market, which will enhance reliability and provide significant economic benefits to participants across the Western Interconnection, and we look forward to the next phase of market development.”
Seams Issues Left Unaddressed
In the order — released around 6 p.m. ET, well after it was approved at the commission’s monthly open meeting — FERC dismissed a protest by the Colorado Office of the Utility Consumer Advocate, which argued that long-term trends show regional markets such as Markets+ generally do not provide savings for consumers despite claims that they foster competition and reduce electricity prices.
The commission countered that the office “provided no evidence that regional markets result in higher costs to consumers or that costs in regional markets are higher than they would be absent the regional market itself.”
FERC also dismissed concerns expressed by the Navajo Tribal Utility Authority (NTUA) regarding the “significant costs and operational complexity associated with participating in Markets+” and rejected NTUA’s request that SPP implement a mechanism such as CAISO’s metered subsystem to ease the financial and operational impacts of participating in the market.
“We do not believe that the lack of a metered subsystem model renders this proposal unjust and unreasonable or unduly preferential or discriminatory,” the commission wrote. “Markets+ is voluntary and should NTUA decide that a metered subsystem model is necessary for its own participation, it can choose not to join.”
The commission also largely rejected complaints by NV Energy, Idaho Power, Portland General Electric and PacifiCorp regarding the Markets+ “transmission contributors” option, agreeing with SPP that the tariff “will not force changes in the operations of nonparticipating transmission service providers’ systems.”
But FERC did find the tariff “insufficiently clear” on some points raised by the protesters and directed SPP to address those issues in a compliance filing.
Perhaps most significantly, the commission declined in the tariff proceeding to address various commenters’ concerns about potential issues at the seams between Markets+ and EDAM, agreeing with SPP that the affected parties and scope of the issues remain unknown.
“While borders between organized markets (and non-market areas) in the West are likely to arise, we disagree with commenters who argue that action is necessary at this time,” it wrote. “Consistent with our experience in the Eastern Interconnection, we anticipate that seams between centrally cleared markets (e.g., EDAM and Markets+) and between markets and non-market areas will necessitate agreements between parties that will address issues such as data sharing, congestion management, and transmission rights and use.”
‘Not Accurate’
Perhaps as significant as the content of FERC order is its likely near-term financial impact: Now, the biggest backers of Markets+ can start paying to fund its next phase — the Phase 2 implementation stage, which SPP estimates will cost about $150 million.
One of those backers, the Bonneville Power Administration, has previously committed to contributing its $25 million (over 17%) share of Phase 2 funding but has said also that it would not do so until FERC approved the tariff. That funding commitment has stirred controversy in the Northwest, both among the region’s EDAM supporters and the U.S. Senate delegation representing Oregon and Washington, which has urged the federal power agency to delay its final day-ahead market decision, slated for May. (See In Letter to Senators, BPA Tempers Markets+ Leaning.)
“BPA is pleased that the Federal Energy Regulatory Commission has approved SPP’s Markets+ tariff, which was crafted through a robust stakeholder process,” Rachel Dibble, BPA vice president of bulk marketing, said in SPP’s release. “This guarantees BPA has two viable day-ahead markets to consider as we make our way toward a day-ahead market decision later this year.”
SPP’s release indicated also that BPA had “announced they would fund their share of Phase 2 development while they continue to collaborate with customers to develop a policy direction toward a day-ahead market option.”
But BPA spokesperson Doug Johnson told RTO Insider that is “not accurate.”
“At this point, we continue to work with SPP and all the other participants to finalize the timing of Phase 2 commitments. No executed agreement yet,” Johnson said in an email.
In a comment provided after publication of this article, SPP’s Lucas said: “FERC’s approval of the Markets+ tariff clears the way for entities to share in funding phase two of Markets+ development. SPP is working with entities, including BPA, on finalizing phase two funding agreements. SPP expects the agreements to be signed by interested parties over the coming days and weeks.”
BPA also followed up with a further clarification, saying: “BPA has previously expressed its intent to fund Phase 2 of Markets+ to ensure market development continues as Bonneville proceeds with its public process to determine which, if any, market to join. BPA remains committed to funding Phase 2 of Markets+. At this stage, BPA is actively working with SPP and all other Markets+ participants on finalizing Phase 2 funding agreements.”
The tariff approval also comes nearly two months after Markets+ notched another important victory when it simultaneously received its first firm participation commitments from four Arizona utilities: Arizona Public Service, Salt River Project, Tucson Electric Power and UniSource Energy Services. (See 4 Arizona Utilities Commit to Joining Markets.)
The 2,600 GW of wind, solar and storage sitting in RTO/ISO interconnection queues across the U.S. represent a major imbalance in energy resources that could lead to brownouts or blackouts, former North Dakota Gov. Doug Burgum (R) said during his Senate confirmation hearing Jan. 16 to be President-elect Donald Trump’s secretary of the interior.
“We are in an energy crisis in our country,” Burgum said in response to a question on permitting from Sen. Jim Justice (R-W.Va.), member of the Senate Energy and Natural Resources Committee. “Electricity is at the brink. Our grid is at a point where it could go completely unstable. We could be just months away from having skyrocketing prices for Americans.”
Burgum argued for an infusion of “baseload” power from fossil fuel generation to ensure grid stability, affordability and sufficient electricity to power the data centers the U.S. needs to win the “AI arms race” against global competitors.
“Right now, in some queues in FERC, it’s 95% intermittent resources and only 5% baseload,” Burgum said. “We need baseload to be able to allow renewables on the system. … We’ve stacked the deck where we are creating roadblocks for people who do baseload, and we’ve got massive tax incentives for people that want to do intermittent and unreliable. … The balance is out of whack, and we’ve got to bring it back in line.”
Burgum apparently was under the assumption that FERC manages generator interconnection queues. In response to another senator’s question, he said, “You take a look at a FERC queue that’s got 95% intermittent and unreliable, that probably tells us we’re a little bit out of balance, and we’ve just got to bring it back and then keep moving forward.”
Electricity and the grid were among several of the high-priority issues Republicans and Democrats raised during Burgum’s three-and-a-half-hour confirmation hearing. Both Sen. Mike Lee (R-Utah), the committee’s chair, and Sen. Catherine Cortez Masto (D-Nevada) spoke of the challenges of living in states where two-thirds or more of the land is federally owned and quizzed Burgum on his views on residential development on federal property.
One solution could be public-private land swaps, Burgum said, pointing to trades of state and private land in North Dakota “to provide better outcomes for both of those pieces of land.”
Other concerns raised included local consultation in the designation of national monuments, protecting hunting and fishing rights on public lands, improving relations with tribal nations, and addressing the maintenance backlog at national parks, all of which he said he would support if confirmed.
On another energy-related issue, Burgum gave assurances to Republican lawmakers he would increase auctions for oil and gas drilling on public lands, both on and offshore, noting that as governor of North Dakota, he repeatedly fought Bureau of Land Management efforts to restrict drilling on federal land.
Public lands should be viewed as national assets, Burgum said. “The Department of the Interior has got close to 500 million acres of surface [land], 700 million acres of subsurface and over 2 billion acres of offshore. … That’s the balance sheet of America.
“If we were a company, they would look at us and say, ‘Wow! You are really restricting your balance sheet.’ … It’s our responsibility to get a return for the American people.”
The ‘Clean Coal’ Argument
With an MBA from Stanford, Burgum started out as a computer entrepreneur, growing a local company, Great Plains Software, from an accounting software startup to a publicly traded firm with 2,200 employees across the state. Microsoft acquired the company in 2001.
Before winning his first election as governor in 2016, Burgum worked for Microsoft for several years and then started a real estate development company and a venture capital firm.
Sen. Angus King (I-Maine) | Senate Energy and Natural Resources Committee
Re-elected in 2020, Burgum had supported an all-of-the-above approach to energy, prioritizing innovation over regulation. North Dakota is the third-largest producer of crude oil in the U.S. but gets close to 40% of its power from wind.
In 2021, hours before Energy Secretary Jennifer Granholm landed for a state visit, Burgum issued a challenge for North Dakota to become carbon-neutral by 2030, primarily through carbon capture and sequestration. A press release from the governor’s office at the time stated that North Dakota has “252 billion tons of underground storage capacity — enough to store 4,400 years’ worth of the state’s carbon output or 50 years’ worth of the nation’s energy-related carbon output.”
With CCS, North Dakota now is producing “clean coal,” Burgum said at the hearing.
But he downplayed wind’s role in the state’s energy mix in an exchange with Sen. Angus King (I-Maine), who asked for assurances that existing leases for offshore wind projects in the Gulf of Maine would be allowed to continue. Trump has railed against wind energy, and offshore wind in particular.
Those projects “will produce enough energy for all the homes in Maine, New Hampshire and Vermont. … The capacity factor of offshore wind is significantly higher than terrestrial wind,” King said. “I hope you can talk to [Trump] about the fact that wind has its virtues and can contribute significantly, because we are … facing a huge energy challenge over the next 15 to 20 years.”
Burgum’s response again was to call for “balance” between intermittent and baseload resources. Most of North Dakota’s wind power is exported, he said. “We need more, and the thing we’re short of most right now is baseload.”
Democrats Push Back
In addition to interior secretary, Burgum also has been tapped by Trump to lead a still-to-be-formed National Energy Council, where he could have more authority to implement Trump’s agenda and his own views on the need for balance, more baseload power and the national security impacts of energy policy.
Burgum said the council will be formed under an executive order he expects Trump to issue soon after his inauguration.
“Today, America produces energy cleaner, smarter and safer than anywhere in the world, and when energy production is restricted in America, it doesn’t reduce demand,” Burgum said in his opening remarks. “It just shifts production to countries like Russia and Iran, whose autocratic leaders not only don’t care at all about the environment, but they use their revenues from energy sales to fund wars against us and our allies.”
Producing enough oil and gas to sell to U.S. allies means “they don’t have to buy it from our adversaries. That’s how we reduce tensions in the world,” he said.
With overwhelming support from Republicans, Burgum seems headed for approval by the committee and the Senate, but he did get pushback from some Democratic senators on some of his statements.
Cortez Masto challenged his definition of baseload energy, noting that solar is a major source of power in Nevada, “and that’s why battery storage is important. So, let me ask you this … isn’t the combination of renewables plus battery storage baseload?”
Sen. Catherine Cortez Masto (D-Nev.) | Senate Energy and Natural Resources Committee
When Burgum suggested that “storage is still a few years out,” Cortez Masto quickly countered that “it’s happening in Nevada right now. I’ve been to facilities. If we don’t have those incentives, then we’re never going to get there.”
Cortez Masto was referring to the incentives for storage and clean energy in the Inflation Reduction Act, which Trump and Republicans could target for rollbacks. Sen. Ron Wyden (D-Ore.) also raised concerns about IRA tax credits, and in particular, Burgum’s level of support for the technology-neutral tax credits for emerging clean energy technologies that he wrote into the law.
“Nobody knows what the big carbon reducers are going to be 30 years from now, and so the reason I insisted on that provision is it creates what I call an innovation lane,” Wyden said. “It’s an opportunity to send a message to people … that you’re going to have a chance, if you innovate, to be part of a very bright future.”
While agreeing with Wyden in principle, Burgum again argued that “these things have been so successful as it relates to the electric grid that we have got now a significant imbalance in the amount of projects that are intermittent.”
