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.
SPP did not respond to a request for a comment on the matter.
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.”
FERC has accepted MISO’s second try at Order 2222 compliance, allowing MISO time to prepare through mid-2029 before it fully accepts aggregators of distributed energy resources into its markets in 2030.
The commission said in a Jan. 16 order that MISO this time provided adequate explanation for the delay into 2030 and pledged that creating a multiple configuration resource model will take a backseat to finishing Order 2222 (ER22-1640-003).
FERC accepted MISO’s rationale that its underlying computer systems need work over the next four years and called the wrap-up date a “reasonable effective date that is appropriately tailored for its region and implements Order No. 2222 in a timely manner.”
FERC also decided MISO this time around provided enough additional analysis to support its call to limit aggregations to a single pricing node. FERC directed in Order 2222 that aggregations should be as locationally broad as technically feasible.
The commission disagreed with some stakeholders that MISO’s effective date is essentially the original 2030 timeframe MISO proposed. FERC said this time, MISO prioritized Order 2222 compliance on its to-do list over its initiative to create a multi-configuration resource model but had to account for several more months to roll out its new market platform and get its systems ready for DER aggregations’ registration and enrollment and settlements.
MISO said, “additional systems enhancements and process updates that were not contemplated at the time of MISO’s initial compliance filing are now also required to achieve … final implementation.”
MISO expects to have its new, modular market platform fully operational in late 2025. Beyond that, MISO said improvements to its locational enrollment system needed for DER registration are underway and expected to be completed in mid-2026. It also said updating its settlement systems to accommodate DER aggregations will take until mid-2028.
In its first decision in 2023 on MISO’s plan, FERC said MISO’s 2030 finish date wasn’t timely enough. The RTO explained it first needed to replace its market platform before it has the technological capability to register, enroll and facilitate offers from DER aggregations. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.) In response to the order, MISO divided its plan to allow DER aggregations in its markets into two stages.
MISO proposed a two-step approach to Order 2222 compliance. First, it would use an existing demand response resource participation category to get aggregations of distributed resources participating sooner — albeit on a limited basis — and providing energy, contingency reserves and capacity through behind-the-meter generation or controllable load. MISO would begin registering DER aggregations under its demand response resource (DRR Type I) participation model by Sept. 1, 2026, and begin participation by June 1, 2027. DER aggregations would be limited to 1 MW or larger under the demand response participation.
MISO would roll out its comprehensive Distributed Energy Aggregated Resource model at the beginning of 2030. It plans to register aggregations beginning June 1, 2029, allow DER aggregations to participate in its energy and ancillary services by Jan. 1, 2030, and finally open full market participation to aggregations by June 1, 2030. (See MISO Offers 2-stage Plan for DER Aggregations in Markets.)
FERC: Demand Response Participation Doesn’t Fit with Order 2222
In its Jan. 16 order, however, FERC said MISO’s prerogative that a DRR Type I participation approach could serve as the first phase of Order 2222 compliance is wrong. The commission said MISO’s proposed 1-MW size threshold doesn’t line up with Order 2222’s 100-kW size minimum.
FERC also said MISO’s demand response placeholder doesn’t address the coordination, data requirements or means to discourage double counting of resource contributions required under Order 2222.
“We recognize that MISO’s DRR-Type I proposal was intended to be responsive to the commission’s directives on the effective date and locational requirements of Order No. 2222,” FERC said, but added that MISO nonetheless missed the mark on leveraging an existing participation model to eke out partial Order 2222 compliance.
FERC gave MISO 180 days to either file how the DRR Type I participation model can comply with Order 2222 or strike the first phase of participation altogether from its compliance plan. FERC said if MISO decides to remove the DRR Type I component, it’s free to make an independent filing to FERC to seek approval of the temporary participation method for DER aggregations.
MISO did not return RTO Insider’s request for comment on whether it would salvage the DRR Type I aspect for a separate filing to allow DER aggregations to provide some services by the middle of 2027.
A new report by Americans for a Clean Energy Grid (ACEG) makes the case that the speed of transmission development often is commensurate with the level of trust that has been built with communities affected by the project.
Released Jan. 15, “The PACE of Trust” lays out a framework for engaging communities during the development of transmission lines in order to ensure the industry can expand the infrastructure on time. The “PACE” framework organizes best practices to four core topics:
Participation and engagement of communities.
Accountability and good governance.
Communication, transparency and trust.
Economic and noneconomic benefits.
The report was prepared alongside DNV, which convened a roundtable with ACEG and representatives from agriculture, environmental advocacy, labor, indigenous communities and transmission developers, among others. Through group meetings, surveys and individual interviews, DNV gathered and refined best practices based on the consensus of the roundtable.
“The PACE framework serves as a guide for developers, policymakers and communities to work together in advancing transmission projects,” ACEG Executive Director Christina Hayes said in a statement. “By adopting these best practices and recommendations, transmission planners can support earlier and more effective community engagement, resulting in an energy grid that meets the needs of our communities.”
The first group of recommendations, participation and engagement of communities, involves utilities doing early, ongoing and consistent engagement and fostering representation of broader community interests in decision-making.
Accountability and good governance involves creating a safe forum for gaining representative knowledge and feedback, along with supporting mutual understanding in community benefit plans and agreements. The best practices include streamlined negotiations and enabling local communities to engage in the transmission planning process early.
The third bucket includes providing all parties with accurate and timely information, empowering communities to provide informed feedback, enabling developers to anticipate community needs, addressing feedback and allowing open communication.
The last topic involves community benefit plans and agreements; providing equitable and responsive financial and resource support; and local workforce development.
The roundtable participants did not come to a consensus on everything, however; they deferred on three areas: pathways to enable workforce development, balancing local and union hiring and training, and forging bipartisan partnerships. Local workforce development is a key priority for affected communities, but it is hard for developers to make that happen given the specialized labor required to build transmission lines, the report says.
The report includes some more specific policy recommendations, such as setting up offices of public participation (like the one at FERC) for all of the regional planning entities. The industry also should facilitate a national roundtable to explore challenges of targeted hiring and local workforce development, it says.
The public should get notice when regional planners are working on large projects, especially when that involves a portfolio of projects, the report recommends. The planning process should include working groups that include representatives from local communities, and it should consider a program that funds local workforce development.
On transmission routing, planning processes should identify route-specific environmental mitigation measures, and routing should start at least a year before a formal siting process — possibly even more for the most complex projects.
“Expanding and modernizing the transmission grid is essential to achieve climate goals and mitigate the effects of climate change,” Richard Barnes, DNV region president for energy systems in North America, said in a statement. DNV “forecasts an almost fully decarbonized electricity grid by 2050, but this will not be possible without transmission infrastructure that can manage the influx of renewable energy. Community support for transmission projects is essential, and the best practices outlined in this report will enable the necessary project development now and in the future.”
CARMEL, Ind. — MISO revealed it will crack down on demand response testing requirements ahead of its spring capacity auction, while some stakeholders argued the stepped-up measures amount to a change that requires FERC approval.
The announcement at the Jan. 15 Resource Adequacy Subcommittee meeting follows FERC doling out several million dollars in penalties across a string of companies for invented demand reductions in recent years.
MISO’s Joshua Schabla said before its late March capacity auction, MISO will require all load-modifying resources (LMR) and demand response resources that haven’t submitted real power tests demonstrating 100% of their registered capability to provide documentation explaining why complete reductions couldn’t be achieved and submit 10 days of meter data before, during and after seasonal coincident peak loads.
Load-modifying resources that contain aggregated retail customers must show a contractual relationship for their megawatt capability, Schabla added. MISO said contracts must be active for all seasons an LMR offers their services and detail response time, how the LMR achieves demand reduction and specify how many megawatts or to what firm service level end-use customers agree to curtail. MISO said those entering aggregations of households must “submit a detailed report describing how the load reduction is achieved, how the load reduction works and how the load reduction value is calculated.”
Further, resources using a firm service level threshold to measure reductions must show in testing that they can cut use to that level.
Schabla said the testing and documentation requirements aren’t new and have been in MISO’s business practice manuals. He said beginning with the upcoming Planning Resource Auction (PRA), MISO will begin disqualifying resources that fail to provide required information.
MISO said it “continues to see testing inconsistencies” among its demand response fleet.
Some LMRs already are registered for the upcoming auction; MISO said some of those may need to resubmit registrations if they lack detail.
Representatives from Voltus — the latest company to agree to a multimillion-dollar civil penalty to settle demand response violations — voiced the most opposition to MISO’s doubling down on enforcement. (See Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO.)
“A lot of these are changes and they’re being delivered to stakeholders at the 11th hour,” Voltus’ Sean Shafer said. “This does feel like a last-minute surprise.”
Shafer said it appeared MISO was trying to “push through” testing changes that stand to affect rates without FERC approval.
MISO staff at the meeting disagreed and said the RTO already is authorized to administer rules on its books. “We are going to start enforcing them based on behavior from market participants over the last several years,” Schabla said.
“We don’t like the situation we’re in either,” Executive Director of Market and Grid Strategy Zak Joundi told stakeholders.
Jim Dauphinais, representing a collection of MISO end-use customers, said MISO should have raised more stringent enforcement back in September. He said at this point, MISO has appeared to issue conflicting guidance on testing requirements. Dauphinais pointed out that some load-modifying resources already have performed testing for the upcoming auction.
“You can pursue a more aggressive approach, but you’re going to have to be patient and flexible. Unfortunately, this is going to cause a big scramble,” Dauphinais said, advising MISO to allow testing deferrals.
“This is a 13th-hour change,” Voltus’ Luke Metcalf argued. “We are 40% of the way through registration. … There is a change here, and MISO should be going through the stakeholder process to codify this.”
Metcalf said MISO should have communicated a more stringent testing process to stakeholders at least a year in advance. He said until MISO introduces a proposal to bolster testing requirements, market participants should be free to rely on the more lenient LMR testing guidance MISO issued in previous years.
Schabla said MISO’s chief concern is that resources have cleared the PRA without ever intending to perform. He said some demand response can “effectively take payment from ratepayers” while even opting out of testing requirements.
“We believe that’s not acceptable,” Schabla said.
IMM Presses for More Near-term LMR Rules
As some stakeholders say MISO is going too far in requirements, the Independent Market Monitor pushed MISO to enact further edicts on LMRs.
IMM Carrie Milton said MISO should make a short-term filing to hold LMRs to more stringent rules by the 2026/27 capacity auction.
Milton said some LMR rules should be rolled out faster than MISO’s ongoing, longer-term effort to move to an availability-based accreditation for its LMRs, demand response and behind-the-meter generation. She advised MISO to draft a separate FERC filing for short-term fixes.
The IMM said MISO’s filing should strengthen penalties for unavailability and overstating capability, eliminate dual registration of LMRs and emergency demand response, require exclusive contractual rights for LMR output and do away with mock testing.
“Unfortunately, mock tests have been abused in the past,” Milton said, adding that real performance testing is best.
MISO in late 2024 announced it would put an end to allowing LMRs to also register as emergency demand response. The RTO plans to make a filing sometime in the coming months.
Milton said the filing also should rework the tariff’s Attachment TT to become a singular how-to for measuring and verifying demand response and load modifications. Attachment TT should be expanded to include testing and deployment rules and should define firm service levels and their application in use reduction.
Joundi said MISO is evaluating the IMM’s recommendations and will return to the February meeting of the Resource Adequacy Subcommittee with a response.
Auction Preparations
Meanwhile, MISO is full steam ahead on other capacity auction preparations. Market participants have until Feb. 1 to question MISO about their resources’ accreditation values. MISO is targeting mid-February to post final accreditation values for resources.
The auction window will open March 26 and close March 31. MISO plans to publish auction results at the end of April.
Using summer data, MISO anticipates a 122.66-GW coincident peak and will require a 7.9% planning reserve margin at 135.3 GW. However, the RTO so far estimates it has 124.6 GW in total seasonal accredited capacity despite 159.8 GW in total installed capacity.
“Today’s data is the first cut, very preliminary and will change,” Manager of Resource Adequacy Andy Taylor said, adding that the current data is only an indication for stakeholders. “There is a whole lot that’s still missing.”
MISO will finalize accredited capacity values in mid-February and post updated versions of auction data periodically until it opens the offer window.
LMR Replacements in Capacity Auctions?
Finally, MISO is considering switching up its auction rules in the future to permit load modifying resources to make substitutions when originally contracted load reductions can’t honor reduction promises.
MISO allows its more traditional resource types to replace zonal resource credits, but that allowance doesn’t extend to LMRs. The RTO uses zonal resource credits to measure its resources’ capacity.
MISO is contemplating allowing LMRs to make similar, limited replacements if the end-use customers it contracted for reductions must terminate contracts.
Shafer said MISO’s replacement proposal is “encouraging” and will be helpful in the event facilities close and zonal resource credits need to be replaced.
New Jersey Gov. Phil Murphy and the state Board of Public Utilities are pushing ahead with plans to reach zero emissions by 2035, create a new energy master plan and get more electric vehicles on the road even as they face the reality of President-elect Donald Trump, a fierce skeptic of clean energy, taking office Jan. 20.
Giving his State of the State speech Jan. 14, Murphy (D) called on state legislators to enshrine his “clean energy standard into law.” Without it, the goal — at present set out in an executive order — could be changed relatively easily by any successor to Murphy, who will leave office in a year.
“As you know, our administration has already set one of the most ambitious clean energy goals in the country: running New Jersey on 100% clean energy by 2035,” Murphy told lawmakers. He called on them to “make sure our state remains on track to reach that goal.”
The statement was the only substantive mention of clean energy in the speech, which was characterized by his pledge that although he is a lame duck governor, “I’m not done yet.” State law requires the governor to step down after two terms.
Murphy’s move is part of a delicate dance. Like other states that have adopted aggressive clean energy policies, New Jersey must manage the new political environment: to continue the state’s shift to clean energy while hoping to work with the federal government when necessary and reap whatever help they can.
Opening the Board of Public Utilities’ (BPU) first meeting of the year Jan. 15, board President Christine Guhl-Sadovy cited Murphy’s comments and reaffirmed the governor’s intent. She also mentioned Trump’s looming inauguration.
“You know, we are committed to finding common ground with the federal administration as we move forward, and we hope that we will be able to do that,” she said. “So, I am personally wishing the best for our incoming president next week at his inauguration.”
Anjuli Ramos-Busot, director of the Sierra Club’s New Jersey Chapter, welcomed the governor’s statement as a critical element in maintaining the clean energy course.
“That tells me that the administration is going full force for energy procurement in all types of clean energy and renewable energy,” she said.
Ramos-Busot interpreted Murphy’s lack of other comments on energy as meaning the commitment to 100% clean energy by 2035 is all-encompassing. But Murphy also likely was treading carefully around Trump until it’s clear where the new administration stands on different clean energy issues, she said.
She added that a new bill would need to be drafted to put the executive order into law because an earlier bill, S237, faced opposition from some unions and other parties concerned it allowed the state to buy clean energy from out of state, instead of sourcing in-state.
EV Trucks and Chargers
The speech preceded the announcement by the New Jersey Department of Environmental Protection (DEP) on Jan. 15 that it would spend $35 million of funds from the state’s participation in the Regional Greenhouse Gas Initiative (RGGI) program to put more medium and heavy-duty vehicles (MHD) on the road. The money will pay for incentives for local governments to buy electric shuttles, transit buses, garbage trucks and other electric vehicles (EVs).
In a separate announcement, the DEP on Jan. 14 issued a solicitation for applicants seeking to provide support for the Clean Corridor Coalition Program. The coalition, which consists of representatives from New Jersey, Connecticut, Delaware and Maryland, is administering a $249 million grant from the federal Climate Pollution Reduction Grant (CPRG) program to install heavy duty zero-emissions vehicle chargers along the Interstate 95 corridor. (See NJ To Install 167 Heavy Truck Chargers with $250M Federal Grant.)
Murphy’s biggest clean energy gambit, and one that could be most disrupted by Trump, is his goal of the state installing 11 GW of wind power by 2040. The state has held three solicitations for offshore wind (OSW), approving three projects with a combined capacity of 5.252 GW. The outcome of a fourth solicitation is pending: The BPU was expected to announce approvals for the fourth solicitation by the end of 2024 but has yet to do so. And the agency plans to launch a fifth solicitation this year. (See Uncertainty Clouds NJ Clean Energy in 2025.)
The state’s most advanced project, 1,510-MW Atlantic Shores, received its Construction and Operations Plan approvals from the federal Bureau of Ocean Energy Management in October 2024. It now has all its federal permits and can advance regardless, said Ramos-Busot, of the Sierra Club. However, Atlantic Shores is awaiting the results of the BPU’s fourth solicitation, in which the developer submitted a rebid.
Trump has spoken out against OSW and says he does not believe in climate change. U.S. Rep. Jefferson Van Drew (R-N.J.) underlined that opposition Jan. 13, issuing a press release stating he’s “working closely with President Trump on drafting an executive order that would halt offshore wind turbine activities along the East Coast.”
Van Drew, a former Democrat who switched parties in 2020, represents a district in South Jersey that includes Atlantic City and several shore towns that are closest to the state OSW project, and where opposition to the projects is strongest.
He said he expects the proposed order to be finalized within the next few months and the draft would “lay the groundwork for permanent measures against the projects.”
Master Plan Concerns
On Jan. 15, the BPU pushed ahead with other clean energy projects. The board agreed to send out a Request for Quotation for a contractor to administer the state Energy Storage Incentive Program, which the board expects to launch in 2025 in support of its goal for the state to reach 2,000 MW of installed storage by 2030. (See Developers Seek Deadline Extension in NJ Storage Plan.)
The board also approved a modification to the contract for Energy and Environment Economics, which is helping the state develop its 2024 Master Plan. The state’s last plan, released during Murphy’s first term in 2019, formed the basis for his aggressive clean energy strategies. Clean energy supporters see the next Master Plan as key to setting out Murphy’s updated clean energy priorities and providing the foundation for future policies.
Commissioner Zenon Christodoulou said he was unclear whether the consultant understood the importance of some parts of the project.
“I’m very concerned that this work product needs to be delivered on time, on budget,” he said. “A lot depends on this, and I haven’t been thoroughly impressed yet with our consultant, and I’m concerned that they don’t understand our time requirements, and that pricing is something that we all pay for.”
He urged BPU staff to “take additional charge of this to make sure that they deliver on time and not to keep moving this scale as a moving target on budgeting.”
Guhl-Sadovy said “I know folks are eagerly awaiting” the plan’s release. But she added that “we do want to make sure that we get it right and have all the information that we can utilize and ultimately share with the public.”
The International Energy Agency concludes in a new global review that high cost, long delays and other challenges must be addressed before nuclear power can experience the sustained growth many people expect.
In its announcement Jan. 16 of “The Path to a New Era for Nuclear Energy,” IEA said the rebound it predicted several years ago is well underway, with 70 GW of nuclear capacity under construction worldwide and a new record for generation likely to be set in 2025.
The report also flags a marked leadership transition: Most of the existing nuclear fleet is within countries with advanced economies, and most of it is decades old. The majority of projects under construction are in emerging markets and developing economies, most notably China. Of 52 reactors that have started construction since 2017, 25 were designed in China and 23 in Russia.
China is on course to displace the United States as the leader in installed nuclear capacity by 2030, but many other nations are seeking lesser amounts of capacity of their own.
“More than 70 gigawatts of new nuclear capacity is under construction globally, one of the highest levels in the last 30 years, and more than 40 countries around the world have plans to expand nuclear’s role in their energy systems,” IEA Executive Director Fatih Birol said in a news release.
But enthusiasm alone will not make those plans a reality, he said:
“Governments and industry must still overcome some significant hurdles on the path to a new era for nuclear energy, starting with delivering new projects on time and on budget — but also in terms of financing and supply chains.”
A more diverse fuel supply, shorter development timelines and a pile of money are key to nuclear’s success in its new era, the report says.
More than 75% of mined uranium comes from just four countries and more than 99% of enrichment capacity is concentrated in four countries as well — one of them Russia. Diversifying this key supply chain “needs to be given much greater attention,” the report urges, particularly by nations that import enriched uranium.
Cost and schedule overruns are equally thorny problems, and they are intertwined: The predictability of return on investment is key to attracting private capital. And private capital will be needed, the reports states, because public funding alone would be insufficient to create a new nuclear era.
Small modular reactors could be a solution to the issue of speed and cost, the report indicates, if their promise of standardization comes to pass.
Many people already are betting on SMRs, years before they come to market: IEA reports that 25 GW of plans in varying degrees of maturity already have been floated publicly.
If the evolution of the technology and the business model is successful, IEA writes, far more SMR capacity could be built:
“With the right [government] support, SMR installations could reach 80 GW by 2040, accounting for 10% of overall nuclear capacity globally. However, the success of the technology and speed of adoption will hinge on the industry’s ability to bring down costs by 2040 to a similar level to those of large-scale hydropower and offshore wind projects.”
FERC issued a pair of orders on SPP’s markets at its regular meeting Jan. 16, accepting new price formation rules while setting reforms to capacity certification for additional hearings.
The first order approves new rules to address price formation during load shedding and emergency assistance events, which SPP started working on after Winter Storm Uri in 2021 (ER25-138).
During the storm, SPP had to shed load and bring in emergency imports, but those also cut resource obligations, causing “a steep decline in the market price of energy.” While the grid was in an emergency, prices did not reflect that.
To ensure the right prices are there to attract supplies during emergencies, SPP proposed changing its tariff to provide that if load is shed or emergency imports are requested due to a system-wide capacity issue, then prices would be set as if those imports and load shedding did not occur.
“SPP explains that the pricing solution will continue to reflect the value of energy and ancillary services that exist in the absence of the balancing authority action of shedding load and initiating emergency imports,” the order said. “SPP asserts that its proposed tariff revisions will not impact market prices if market prices naturally increase or decrease due to a non-directed decrease in demand or additional imports being initiated by market participants without balancing authority action.”
FERC found the proposal to be just and reasonable, saying it will produce market prices that better reflect the grid’s condition and incent additional supplies. The rules will go into effect after SPP works out some issues with the Western Area Power Administration to avoid unintended financial harm to the federal entity.
The second order was about implementing effective load carrying capability accreditation for wind, solar and storage and a performance based accreditation for traditional resources that was followed by a fuel assurance proposal for traditional resources (ER24-1317 and ER24-2953). The order accepted and suspended both sets of revisions and consolidated them for paper hearings. Parties will have the opportunity to make another round of comments.
The two cases at FERC deal with the same question — whether the RTO’s proposed resource accreditation methods satisfy the Federal Power Act — and raise common issues of law and fact. Once the later fuel assurance policy was filed, several parties renewed or modified arguments they presented in the accreditation filing.
“Noting the extensive comments previously filed in the two proceedings, parties need not repeat arguments raised in earlier pleadings,” FERC said. “This is an opportunity for parties to provide additional comment on the effect of evaluating the accreditation filing and fuel assurance filing together.”
Public interest organizations filed a complaint on SPP’s accreditation policies in EL24-96, which they asked to be consolidated with the two Section 205 dockets. FERC declined to include the complaint in the joint proceeding, saying it deals with whether the RTO’s current policies are just and reasonable, not the reforms proposed in the two consolidated dockets.
The U.S. Department of Energy has made conditional loan commitments totaling $22.9 billion to utilities for transmission, pipeline and clean power investments.
An estimated 14.8 million customers in 12 states stand to benefit from the lower-cost debt issued through DOE’s Loan Programs Office.
The LPO said Jan. 16 that the projects planned will add much-needed transmission capacity; provide new wind, solar and hydropower generation on the gigawatt scale; and replace more than 3,000 miles of leaky gas mains and distribution lines that pose a threat to public safety and to the climate.
LPO listed the following details about the guarantees:
AEP — $1.6 billion to benefit 3.8 million customers in Indiana, Michigan, Ohio, Oklahoma and West Virginia by reconductoring or rebuilding almost 5,000 miles of transmission lines, increasing transmission capacity by 70% and creating a more reliable and efficient system better able to meet growing energy demands.
Consumers Energy — $5.23 billion to benefit 3.1 million customers in Michigan through the CE Clean Energy project, a wide-ranging plan that includes more than 1.8 GW of new solar and wind capacity; battery storage; virtual power plants; and replacement of legacy gas pipelines.
DTE Electric — $7.17 billion to benefit 2.3 million customers in Michigan by building thousands of megawatts of generation and battery storage capacity that will be cleaner than existing generation.
DTE Gas — $1.64 billion to benefit 1.3 million customers in Michigan by updating older gas mains and lines and moving metering infrastructure outdoors.
Interstate Power and Light — $1.43 billion to benefit 500,000 customers in Iowa; parent company Alliant Energy retired a major coal-fired facility in Iowa in 2023 and plans to add approximately 2 GW of wind power and battery storage capacity in Iowa and Wisconsin.
Jersey Central Power & Light — $716 million to benefit 1.2 million customers through the New Jersey Clean Energy Corridor, a package of substation expansions and 40 miles of transmission upgrades that will increase capacity by nearly 4.9 GW and 20 MMWh.
PacifiCorp — $3.52 billion to benefit 2.1 million customers in California, Idaho, Oregon and Utah through Project WIRE, which is intended to augment system capacity and reduce curtailment of existing wind plants by building and reconductoring transmission lines to support existing and future power generation.
Wisconsin Power and Light — $1.62 billion to benefit 500,000 customers in Wisconsin; parent company Alliant Energy plans to stop burning coal at a Wisconsin plant before 2030 and plans to add approximately 2 GW of wind power and battery storage capacity in Wisconsin and Iowa.
The conditional loan commitments announced Jan. 16 are through the LPO’s Title 17 Energy Infrastructure Reinvestment Program, created by the Inflation Reduction Act of 2022.
DOE and the recipients must satisfy technical, legal, environmental and financial conditions before DOE finalizes and funds the loan guarantees.
AEP said in a news release that it expects to close on the loan this quarter.
President Bill Fehrman said: “AEP is investing $54 billion in transmission, distribution and generation projects over the next 5 years. Funds from this program will support these investments and save our customers money while we work to improve reliability and bring economic growth to our states. The funds we are able to save through this program enable us to make additional investments to enhance service for our customers.”
