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December 5, 2024

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FERC-State Collaborative Holds 1st Meeting on Gas-electric Coordination

FERC and a group of regulators from 10 states began discussing gas-electric coordination at the first meeting of the new Federal-State Current Issues Collaborative on Nov. 12 on the sidelines of the National Association of Regulatory Utility Commissioners’ Annual Meeting in Anaheim, Calif.

The new collaborative comes after a similar effort on transmission, which contributed to FERC Order 1920, FERC Chair Willie Phillips said at the meeting. Phillips said he was not tied to any outcome from the effort: It could lead to regulatory changes or suggestions for a legislative response.

“But I am wedded to one basic and, I think, irrefutable fact: In a nation that today is heavily invested in and dependent on natural gas as a dominant fuel in our electric supply portfolio, it is unacceptable for that fuel to not be available to meet our energy supply needs, especially during emergencies,” Phillips said.

While many disagree over the future of natural gas, the fact is that it is leading to reliability issues now and will into the foreseeable future, he added.

The issue has been kicked around for decades. (See RTOs Jointly Call for Improved Gas-electric Coordination and NAESB Forum Chairs Push for Gas Reliability Organization.)

“This forum or collaborative does not need to necessarily end with any specific action,” said North Carolina Utilities Commissioner Kimberly Duffley. “Rather, the purpose is truly discussing the current issues in a roundtable format so each of the NARUC regions and FERC can understand each other’s perspectives and positions and views, along with all of the regional differences.”

Winter storms in recent years have highlighted the risks around failing to improve coordination, which include huge costs as commodity prices spike and can lead to premature deaths when customers lose their heating at the height of winter, Duffley said.

While previous efforts have made some improvements around scheduling and opening up lines of communication between the two interdependent energy markets, they are largely siloed, said New Hampshire Public Utilities Commissioner Pradip Chattopadhyay. Ideally the end result of the task force will be to achieve “greater seamless interaction” between the two markets, he added.

One issue that has cropped up repeatedly is when cold snaps fall on long, holiday weekends, which can lead to significant issues because of the fewer opportunities to schedule delivery of fuel to generators, FERC Commissioner Judy Chang said. ISOs and RTOs increasingly factor risks on the natural gas side as they plan for and forecast reliability, she added.

While no silver bullet is going to solve the longstanding issues, Chang offered a few areas where things could improve, including information sharing and market signals to generators in restructured wholesale markets.

“The nomination process … could be better aligned between the electricity market and gas markets,” Chang said.

Many spoke about the need to expand pipeline capacity as the power sector uses more and more natural gas. But Maine Public Utilities Commission Chair Phil Bartlett said that New England has tried to do that, and it did not work out. The region’s politics also do not support major new pipelines.

“We are seriously constrained at our ability to bring in natural gas by pipeline, forcing us to rely significantly on LNG to try to get us through,” Bartlett said. “The system in New England was built largely to serve heating demand as well as to serve industrial loads. It was not designed to support gas generation, but gas generators have been able to successfully take advantage of excess capacity of the system, which exists for much of the year, most days, in order to power their operations.”

The issues come during winter cold snaps, when the pipelines are at full capacity and many of those generators cannot produce power. “If you have 10 to 14 days of really cold arctic temperatures, there’s a real concern that we’re not going to have access to the gas,” Bartlett said.

ISO-NE is working on capacity market changes that will aim to incorporate those gas constraints, which could lead to generators signing up for firmer gas supply, but Bartlett said success there was not guaranteed.

New England has been dealing with this for 20 years, as its position at the end of the pipelines and its cold winters made the issue obvious in the early days of its electric markets, ISO-NE CEO Gordon van Welie said at the Aurora Energy Transition Forum in New York in October. (See Future of Power Markets Discussed at Aurora Energy Conference.)

“I would have expected Winter Storms Uri and Elliott to have shifted the conversation. I’m shocked that it hasn’t,” van Welie said. “So, I’ve now resigned to ‘we need a 2003 blackout event’ before Congress will wake up and give somebody at the FERC, I think, responsibility for overseeing both of these networks.”

The 2003 blackout led to FERC and NERC’s reliability regime under the Energy Policy Act of 2005. Uri was responsible for hundreds of premature deaths and huge costs in February 2021, but van Welie argued it was written off as something unique to Texas, and for change to happen nationally, some major disaster needs to hit the Eastern Interconnection to move the politics of gas-electric coordination to a place where the issues will be addressed.

“We’ve got all these frictions and resistances in the system, so it’s not going to happen until something really bad happens,” van Welie said.

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RWE Pauses Investments in US Offshore Wind

RWE, which holds offshore wind leases off the Atlantic, Pacific and Gulf coasts, said it is pausing capital expenditures on development there for two years due to increased risk and uncertainty. 

The world’s second-largest wind power developer says it expects complications in the U.S. market in the wake of Donald Trump’s re-election as president.  

RWE Chief Financial Officer Michael Muller said during a Nov. 13 conference call with financial analysts that the company still sees a long-term need for offshore wind power. It still sees value in its projects, and wants to keep its options open, but it needs to be careful about its investments, he said. 

CEO Markus Krebber said: “In particular, we see higher risks and delays in U.S. offshore wind, and in the ramp-up of the hydrogen economy in our core European market.” 

RWE is developing the Canopy Wind project off the California coast and holds a lease off the Louisiana coast. It also is developing Community Offshore Wind in the New York Bight in a joint venture with Natural Grid Ventures. 

All of these projects are only in planning and are at best several years away from starting construction. But they give RWE exposure to a wide range of the technical, political and economic considerations facing the offshore wind industry as it tries to overcome recent challenges and get steel in the water in the U.S. 

With the election last week of a strident wind power opponent as president, new challenges loom. 

RWE expects its two-year pause on capital investments in U.S. offshore wind and European hydrogen projects will save it about 2 billion euros. 

Krebber said RWE is more optimistic about U.S. onshore renewables. 

The company sees very strong U.S. demand for types of power, and a particularly strong demand for green power through power purchase agreements (PPAs) — more than it can meet, in fact. 

Potential loss of the investment tax credit under the second Trump administration would not reduce the demand for new electricity, Krebber said, although it might change the economics of developing generation to meet that demand. 

Might that mean higher PPAs for RWE? The company cannot predict the future, Krebber said, as there are too many variables.

However, he said RWE has de-risked its supply chain and would undertake only de-risked investments. 

An analyst asked what impact would be felt from higher tariffs, another possibility floated by Trump.  

Krebber said RWE evaluates the supply chain risk on every U.S. project before it makes a final investment decision. And on each project, it has taken steps to protect itself, such as buying domestic products, shifting the risks onto suppliers, buying from suppliers not vulnerable to tariffs, or buying components early and stockpiling them in the United States. 

“We feel very comfortable that we can expect no negative impacts [from] very harsh measures on our projects under construction,” he said. 

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NARUC Board Passes Resolution Advancing Grid-enhancing Tech

ANAHEIM, Calif. — The National Association of Regulatory Utility Commissioners board has adopted a resolution to emphasize the role grid-enhancing technologies (GETs) and high-performance conductors (HPCs) can play in reducing customer costs and improving reliability. 

Board members passed the resolution Nov. 13 at NARUC’s annual conference in Anaheim.  

The resolution encourages Congress to appropriate more funding for programs that support GETs and HPC deployment, including two initial rounds of funding allocated to Grid Resilience and Innovation Partnerships Program grants that will benefit 29 states.  

“State regulators nationwide support using technologies to get more value out of the transmission grid,” Julia Selker, executive director of the WATT Coalition, said in a press release. “Continuing federal programs would help grid-enhancing technologies double capacity for new generation and integrate new load in the coming years.”  

GETs are another “tool in the toolbox” that can help address some of the grid’s biggest challenges — unprecedented load growth, clogged interconnection queues and rising prices — said FERC Commissioner Judy Chang during a Nov. 10 panel at the NARUC conference.  

“There are many potential benefits associated with advanced technologies and grid-enhancing technologies, and here at FERC, we’ve been really asking some of those questions,” Chang said. “What’s currently available, what’s possible in the future, what are the costs and how can grid operators and owners facilitate the use of these technologies?” 

FERC is exploring different GETs, including dynamic line ratings, advanced power flow controls and topology optimization. The commission has opened a docket looking into dynamic line ratings and is also exploring simpler solutions such as tower-lifting, which can increase the rating of the transmission line by allowing more sag and less risk.  

Many of the technologies include benefits without engaging in new transmission siting and permitting — an added benefit given the difficulty of building new transmission. 

The tools can unlock the “dynamic capabilities of the grid,” finding transmission capacity for new generation or electric demand at a lower cost than traditional upgrades. Regardless, benefits still need to be balanced with costs, Chang said.  

“What else can we do to squeeze more out of the existing infrastructure?” Chang said. “But we as regulators need to think about the balance between adopting new technology and the risk and cost to consumers associated with these things.”  

‘Remove the Disincentive’

A challenge in advancing GETs is ensuring proper and established incentives. At FERC, regulators also are grappling with whether they should incentivize or mandate new technologies. Chang said she’s cautious of mandates given the amount of information a regulator needs to establish one properly.  

“I’m a big fan of finding ways to remove the disincentive of investments in the right things,” Chang said. “How do I remove the barriers of adoption and remove the disincentive of making that technology available?”  

But the success of advancing GETs and HPCs will depend heavily on whether regulators can balance costs. Adequate cost containment for transmission and other investments has yet to be achieved, Chang said, and doing so will require more collaboration between the states and FERC.  

“We need to make sure we contain the costs while expanding our grid to accommodate all the needs we have,” Chang said. “This is where FERC and states and transmission owners should come together and find solutions so that we can transparently explain to the consumers what costs we’re spending. Because ultimately, this is the consumer’s pocket we’re talking about.” 

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Wash. Dems Save Inslee’s Climate Legacy, Prepare for Challenges

SEATTLE — Washington Gov. Jay Inslee’s biggest anti-global warming measure — and probably greatest political legacy — remains intact after the state’s voters on Nov. 5 rejected a ballot initiative to repeal the nation’s second cap-and-trade program. 

The Republican-led Initiative 2117 would have eliminated the cap-and trade program while also forbidding its revival, with supporters arguing the system has increased the state’s gasoline prices. But Washingtonians voted 62%-38% to keep the program. (See Wash. Voters Resoundingly Reject Cap-and-Invest Repeal Attempt.)   

“That was a fanny whipping,” Inslee said at a Nov. 6 press conference. 

“Legislatures around the country have been watching this. States have never mattered more than now,” Reuven Carlyle, former Democratic state senator and architect of Washington’s “cap-and-invest” program, told NetZero Insider.  

New York and possibly other states are considering implementing their own cap-and-trade programs and have watched the Washington referendum to see how the state’s voters reacted to it, Inslee noted.  

“This win is doubly important because we’ll have a person in the White House who denies climate change,” Inslee said.  

In a separate press conference, Washington’s current Attorney General and Gov.-elect Bob Ferguson and Attorney General-elect Nick Brown said the attorney general’s office has been preparing for months to do battle with the Trump administration on numerous issues, including climate change. 

As attorney general, Ferguson — frequently in collaboration with other attorneys general — filed several dozen lawsuits against the first Trump administration, losing only two or three.  

“No one has a record like that except Perry Mason,” Inslee said. 

However, Carlyle noted that the first Trump administration’s legal efforts were sloppy, leading to failures. “This administration may be better prepared,” he said. 

‘Immovable Force’

After 12 years as governor, Inslee leaves office in January. For about eight of those years, he worked to get the cap-and-invest through the state’s legislature, which approved it in 2021. Since 2023, he has fought to save it from elimination. 

The concept of using cap-and-trade measures to deal with corporate pollution has been around for about 100 years, but it did not begin to receive serious consideration until the 1980s, when American power plants were emitting vast clouds of sulfur dioxide, which was falling back to earth in the form of acid rain. 

Congress wrestled with acid rain, and roughly 70 bills to deal with it were proposed in the 1980s, only to all die. In 1988, the Environmental Defense Fund (EDF) proposed a cap-and-trade system that would have a market to determine the costs of the permits to emit sulfur dioxide, while allowing polluters to figure out on their own how to accomplish reductions. 

EDF convinced the then-new George H.W. Bush administration to try the cap-and-trade approach. The proposal became law in the Clean Air Act of 1990. The concept proved its effectiveness in 1995, when acid rain-related emissions fell by 3 million tons, ahead of the 1990 law’s schedule. Europe soon began adopting the concept. 

Meanwhile, in the early 1990s, Carlyle, then a Harvard master’s degree student in public administration, wrote a paper on the topic, but was not yet passionate about it. In 2007, Inslee, then a congressman from Western Washington, wrote about the concept in a book on clean energy called Apollo’s Fire.  

A 2008 Washington law mandated that the state reduce its carbon emissions to 5% of 1990 levels by 2050. In 2009, then-Gov. Christine Gregoire first proposed that Washington set up a cap-and-trade system for carbon dioxide emissions, but it went nowhere. 

Beginning in his first term in 2013, Inslee began proposing a cap-and-trade system on CO2 emissions, with the details taking years to hash out. But Washington’s legislature became divided between a Democratic-controlled House and a Republican-dominated Senate that opposed almost everything Inslee wanted, including cap-and trade.  

“We faced an immovable force which was the Republican caucus,” Inslee said. 

In late 2017, the Democrats took control of the Senate, opening the way for to cap-and-trade to make it through the legislature. But several Democrats in the House and Senate had to be convinced to support cap-and-trade to ensure the proposal would get the majority of the votes in both chambers. That took a while. 

Carlyle introduced the bill in 2020, intending to get it passed in 2021. “I wanted ample time for public discussion,” he said. 

‘Grand Bargain’

The environmental justice legislators had to get buy-in for the plan. They had to address concerns about Washington industrial companies spending money to cut carbon emissions while keeping up with foreign competitors who wouldn’t face those extra costs. Carlyle met with BP, which owns one of five oil refineries in Washington, to ask it what it wanted in a cap-and-trade program. BP’s answer: predictability.  

The bill’s designers addressed how to spend the money raised through the carbon allowance auctions: The cash would go to numerous programs that addressed climate change, including building hybrid diesel-electric ferries for Puget Sound, plus provide electric vehicle chargers, electric fire engines, buses and other government vehicles. The money would also be used to pay to preserve forest lands, build trails, and make public schools and universities more energy efficient. It would fund purchase of solar panels to generate electricity in public and private buildings and salmon recovery efforts and many health programs. 

Thirty percent of the revenue would go to helping low-income communities affected by carbon pollution. Also, Washington’s cap-and-invest architects in 2021 already wanted to link their program with those of California and Quebec to lower allowance and gasoline prices. That alliance is expected to be solidified in the second half of 2025. 

“This was more comprehensive than anything we considered before,” House Majority Leader Joe Fitzgibbon (D) — the former chair of the chamber’s Environment and Energy Committee — told NetZero Insider. 

“We came up with the concept of a grand bargain to get it over the line together. Most serious challenge at the time is that it had to be technically perfect,” Carlyle said. 

Drafting and tweaking Carlyle’s bill — the Climate Commitment Act, with cap-and-trade dubbed “cap-and-invest” — took two years. The bill had 10 times as many pages as the bill that created California’s carbon cap-and-trade program in 2012. Washington’s legislature passed the bill in 2021 with Democrats supporting it and Republicans opposing it.  

‘On the Take’

The cap-and-invest program began auctioning allowances in February 2023. By June, Washington posted the highest gasoline prices in the nation. Many people pointed to cap-and invest as the culprit, claiming the program added 50 cents per gallon to the price of gasoline. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.) 

Writing for Seattle-based news organization Cascade PBS, this author examined what caused Washington gas prices to rise and concluded numerous factors contributed to the fluctuations, making it difficult to pinpoint any single cause. The analysis concluded that the cap-and-invest program could be adding 21 to 50 cents per gallon at the pump. 

Meanwhile, the state Republican Party and a new conservative initiative organization, Let’s Go Washington, gathered signatures to include I-2117 on the Nov. 5 ballot.  

Supporters of that initiative and seven other conservative measures spent $12 million to gather signatures and get placed on the ballot. Most of the money came from one individual, hedge fund manager Brian Heywood of Redmond, who also founded Let’s Go Washington. The organization had little money left in 2024 to spend on campaigns to pass the four initiatives that made it to the ballot, including the one repealing cap-and-invest.  

Meanwhile, supporters of cap-and-invest raised $35 million to campaign for maintaining the program, swamping television stations with ads saying the program had raised $2.1 billion to fund over 100 projects. Supporters included billionaire Bill Gates, several Seattle business leaders, labor unions, environmental groups and BP — about 500 entities in all. The companies owning the four other Washington oil refineries were neutral on this issue. 

“They’re on the take,” Heywood told Cascade PBS in October. “This is a huge grift.”  

He painted a picture of those 500 organizations receiving the cap-and-invest money mainly because they are political allies of Inslee. 

“We took [the repeal effort] very seriously,” Fitzgibbon said. 

“There was no guarantee that [repeal] would make gas prices come down,” Carlyle said, adding that Washington’s gasoline prices have dropped by more than $1 per gallon since the summer of 2023. 

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NJ BPU Updates Proposal for Storage Incentives

New Jersey’s Board of Public Utilities (BPU) on Nov. 7 released an update to its proposed Storage Incentive Program (SIP) that changes how the subsidies for utility-scale, or “grid supply,” projects are determined as the state shoots for 2,000 MW of total capacity by 2030.

The proposal is a revision of a draft released in September 2022. It retains the original version’s segmented structure, with different incentives for grid supply projects and those behind the meter. (See NJ Seeks Stakeholder Input on Pending Storage Program and New Jersey Offers Plan to Boost Lagging Storage Capacity.)

But the original version would have paid utility-scale projects through an “administratively determined fixed incentive plus performance incentive structure” based on the amount of carbon emissions abated through their operation. In the new version, “grid supply energy storage systems will be awarded fixed incentive payments through an annual competitive bidding structure.”

“Grid supply storage resources will initially receive only a fixed upfront incentive, as the [program] will defer an avoided emissions-based performance mechanism until suitable datasets become available,” the proposal says.

The grid supply segment would be launched early in 2025, while the BTM incentives, to be set administratively by the BPU, would begin in 2026.

According to the proposal, the board based its decision to change the structure in part on “the number of storage projects that have remained in the PJM interconnection queue following the imposition of stricter readiness requirements.”

Under the competitive structure, “the board would release a solicitation with the specific amounts, or ranges of amounts, being sought for a given fiscal year. The solicitation would ask participants to identify the level of fixed incentive needed to support project revenue requirements,” the proposal says.

Another change is that the fixed payments for both segments would be paid upfront, as soon as the project begins commercial operations, rather than spread out over 10 to 15 years as was stipulated in the previous proposal.

“Upfront incentives provide a lower level of risk to system owners and developers and reduce the overall administrative burden of the program,” the proposal states.

There will be a public hearing on the plan on Nov. 20.

The BPU’s goal is to encourage the development of storage systems that charge using clean, off-peak energy and improve system reliability. The proposal anticipates a reduction in costs as “New Jersey’s deployment of storage systems increases.”

“Energy storage resources are critical to bolstering the resilience of New Jersey’s electric grid, reducing carbon emissions and enabling New Jersey’s transition to 100% clean energy,” the proposal says.

A BPU spokesperson said the state currently has 560 MW of installed storage, but those projects will not be counted toward the 2,000-MW goal. And the proposed incentives will not be retroactive, according to the proposal. “Only energy storage projects placed into service after the date of the board order establishing this program will be eligible for incentives.”

BTM Incentives

Incentives in the distributed segment would be allocated using a “declining block structure,” in which the BPU would establish an initial capacity of storage sought, measured in megawatt-hours. Once that block is fully subscribed, the board would set a lower incentive for the next block, according to the proposal.

“If a block remains unsubscribed or under-subscribed, the board would have the option to increase the incentive,” according to the proposal. The system would give the BPU “flexibility to establish block sizes, reset incentive levels (if necessary) and adjust programmatic elements on an annual basis, as needed, to meet policy goals and budgetary considerations.”

To evaluate an appropriate incentive level, a consultant hired by the BPU conducted a “gap analysis” of the “revenue and savings potential of behind-the-meter storage projects for a variety of different building types, rate classes and tariffs associated with the New Jersey” utilities, according to the proposal.

The results showed a “consistent shortfall” of revenue of about $220 to $330/kWh, which amounted to between 37 and 47% of the cost of the systems. In response, the proposal suggests a starting incentive of $300/kWh for a small storage system (less than 100 kW) and $200/kWh for a medium project (100 to 500 kW). A large project (over 500 kW) would get an incentive of $150/kWh.

On top of that, distributed projects could get performance incentives, which would be awarded when they respond to dispatch events.

To further encourage developers to build in overburdened communities, the proposal suggests an additional incentive of $100/kWh for small, $67/kWh for medium and $50/kWh for large projects.

“Distributed storage plays an important role in reducing emissions and enhances the resilience of the electric grid — both important factors in meeting Gov. [Phil] Murphy’s environmental justice and equity directives,” according to the proposal. “Because distributed storage resources are customer-sited, energy storage projects serving overburdened communities will provide improved energy resilience to the local communities and may help offset ‘dirtier’ backup generation options during emergency conditions.”

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ISO-NE Updates Plans for Capacity Reforms for CCP 19 and Beyond

ISO-NE has reiterated its plans not to include in its capacity auction reform (CAR) project the development of ambient temperature modeling capabilities or a new simultaneous seasonal auction clearing engine. 

Presenting to the NEPOOL Markets Committee (MC) on Nov. 13, the RTO said it instead plans to consider these reforms for a second phase of work, targeting implementation after the 2028/29 capacity commitment period (CCP 19).  

The CAR project encompasses ISO-NE’s work to improve capacity accreditation, reduce the time between capacity auctions and CCPs, and break up annual CCPs into distinct seasonal periods. The initial CAR changes are intended to take effect for CCP 19, with more work planned for CCP 20 and beyond. 

In previous MC meetings, representatives of the generation and end-user sectors expressed interest in developing a simultaneously clearing seasonal auction format allowing bidders to incorporate annual costs into their seasonal bids. (See ISO-NE Refines Scope, Schedule for Capacity Auction Reforms.) 

Implementing simultaneous seasonal auctions “would require the development of a new clearing engine and new offer/bid parameters to allow resources to offer separately into each season as well as across the year,” said Chris Geissler, ISO-NE’s director of economic analysis. 

No other RTO has developed a comparable clearing engine, Geissler said, adding that it would be challenging to complete development in time for CCP 19.  

He noted that ISO-NE is still considering how to account for generators’ annual costs within a sequential seasonal format and “will spend time with stakeholders discussing competitive offer prices and mitigation … as part of the seasonal accreditation reforms.” 

Regarding ambient temperature adjustments, Geissler said ISO-NE will base capacity accreditation on resource performance at 90°F for the summer and 20°F for the winter and will model the effect of temperature on winter gas availability. However, the RTO is not planning to include any further temperature adjustments in the CAR project.  

Clean energy advocates have argued that ISO-NE should model correlated outages associated with ambient temperatures, noting that forced outages pose risks to the grid during periods of extreme cold weather.  

Geissler said the RTO is constrained by its modeling capabilities and “limitations in data availability related to audited, temperature-based output ratings for applicable resources.” 

Instead, ambient temperature adjustments have been added to the RTO’s post-CAR road map, which also includes consideration of a simultaneous auction clearing mechanism, he said.  

“Evaluating this as part of the post-CAR road map will allow the ISO and stakeholders more time to thoughtfully assess the various approaches to ambient temperature adjustments that could be considered, including the pros and cons associated with each approach,” Geissler added.  

Capacity Accreditation Concerns

Prior to the MC, the clean energy trade association Advanced Energy United, along with 12 renewable developers, issued a memo expressing concern that ISO-NE has not allotted enough time in the CAR project to reviewing the resource accreditation changes.  

ISO-NE had already completed substantial work with stakeholders on proposed capacity accreditation reforms prior to pausing accreditation discussions and broadening the scope of the project to include changes to the auction format. 

However, clean energy developers had substantial concerns about the accreditation framework at the time, as impact analysis results released prior to the pause showed a significant loss of revenue for battery storage resources. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11% and ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.) 

“We believe accreditation will continue to be the most complex and impactful piece of the CAR project,” the groups wrote.  

They advocated for stakeholder sessions in early 2025 to discuss resource adequacy modeling and marginal reliability impacts and called on ISO-NE to conduct its final impact analysis earlier in the process to provide time for more changes if needed. ISO-NE plans to resume accreditation work with stakeholders in late 2025, aiming to file the accreditation aspects of the CAR project with FERC in late 2026.  

“While we recognize that aspects of accreditation cannot move forward without an informed prompt and seasonal design, there are many aspects of the current accreditation framework that will remain relevant and applicable,” the groups added. 

Geissler said ISO-NE is still evaluating how accreditation in the CAR project will compare to the previous resource capacity accreditation (RCA) framework and said the RTO “will bring items related to accreditation to stakeholders as soon as they are ready for discussion” and “will prioritize explaining how the design is the same or how it has evolved since the RCA presentations.” 

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MISO to Devise Express Lane in Queue for Generation Projects that Keep Lights On

CARMEL, Ind. — MISO said it will design an expedited resource adequacy study process so generation projects in the interconnection queue that are needed for capacity sufficiency will get grid treatment sooner.

MISO Director of Resource Utilization Andy Witmeier said MISO “needs a way to get generation online faster” because its capacity forecasts warn of shortfalls within a few years. The RTO told stakeholders to expect more details in coming weeks on how it will expedite the queue approval process for generation needed for resource adequacy.

“We really need generators to get a [generator interconnection agreement] faster to get them online to meet resource adequacy needs that are coming in the next three to five years,” Witmeier told stakeholders at a Nov. 13 Planning Advisory Committee meeting.

MISO said the expedited avenue for RA projects would be a temporary measure and would be discontinued when MISO’s queue processing is cleaned up enough that urgent projects can reach the construction phase quicker. Witmeier said MISO may retire the study process sometime in 2028 or 2029, when queue processing might be closer to one year instead of the current three to four years.

MISO pledged to craft an express lane for priority generation projects after it finalized a proposal to place an annual megawatt cap on its interconnection queue cycles.

The queue cap proposal is set to go before FERC this month without an exemption for generation projects that state regulators deem essential to a solvent supply. Some regulatory staff have implied states cannot support a cap without a regulator exemption. (See MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects.)

The regulator exemption “is not the solution that would get projects studied in a matter of months instead of years and get them started on building to meet those RA needs,” Witmeier said. He explained that the scrapped exemption only guaranteed RA projects’ entry into the queue and didn’t address the queue’s “accumulating backlog, or time it takes to do studies,” leaving critical generation projects languishing in the queue for three to four years.

Witmeier said MISO will ask stakeholders to suggest “the proper gates” that will get a generation project expedited treatment. He said MISO might consider projected zonal capacity deficiencies or known load growth.

“I myself want to limit this process to known, ready projects that need to be built,” Witmeier said.

Witmeier said the study structure could take a page from MISO’s expedited project avenue available to transmission projects that need to begin before MISO’s annual approval of its Transmission Expansion Plans (MTEPs). MISO also could use MTEP modeling to inform studies, he said.

Invenergy’s Arash Ghodsian asked if the resource adequacy fast track is a reaction to FERC’s Order 2023, which aims to streamline grid operators’ interconnection processes.

“It’s a reaction to reality,” Witmeier responded. He said MISO years ago aspired to shorten queue processing time down to a calendar year; instead, the sheer volume of projects coming in cycle after cycle has spawned numerous project dropouts, queue restudies and a wait time that can last as long as high school.

Ghodsian said he harbored concerns that the new framework might lead to “queue jumping on either interconnection customers’ side or the transmission owners’ side.”

Witmeier said MISO could limit eligibility to load-serving entities’ projects that need to be commercially operable in the next three to five years and are recognized by regulatory authorities as essential to resource adequacy.

MISO will host two stakeholder workshops on how it will craft expedited resource adequacy studies on Nov. 18 and Dec. 6.

At last count, project proposals in MISO’s queue totaled about 300 GW, and projects that have signed generator interconnection agreements but are still unbuilt have grown to about 57 GW.

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Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process

The Bonneville Power Administration should be allowed to decide on a day-ahead market without outside federal interference, a group of Northwest publicly owned utilities (POUs) that favor SPP’s Markets+ told the U.S. Department of Energy in a Nov. 12 letter. 

The letter, addressed to DOE Deputy Secretary David Turk, seems intended to head off any DOE attempt to lean on BPA to either delay the agency’s May 2025 market decision or withhold its $25 million share of funding for the Phase 2 implementation stage of Markets+ as developments play out around the governance of CAISO’s Extended Day-Ahead Market (EDAM). (See Pathways Backers Express Confidence on Calif. Legislation.) 

“We respectfully request your support for BPA’s independent decision-making as it considers market options. Enabling BPA to act without external pressures will ensure its continued alignment with its statutory responsibilities and enduring mission to serve the Northwest,” the utilities said in the letter. 

As a federal power marketing administration, BPA is housed within DOE but self-funds its operations from the revenue it earns from selling low-cost power from Northwest’s extensive, federally owned hydroelectric system and operating around 70% of the region’s transmission. The letter’s signatories include the vast majority of BPA’s base of “preference” customers for that power, composed mostly of rural municipal utilities and public utility districts.

A representative for the signatories told RTO Insider the “primary intent” of the letter is “to remind DOE and the [Northwest] Congressional Delegation of the important role of BPA customers in BPA decision-making.”

“Although many are interested in BPA’s decision on markets and count themselves among BPA’s stakeholders, not all stakeholders are similarly situated,” the representative said in an email, which noted that BPA is unlike other taxpayer-funded federal agencies because it is “financed entirely” through funding from customers who have “invested heavily in the agency and the Federal power system to ensure that BPA can continue to provide power and transmission services to its customers and timely repay its Treasury obligations.”

“BPA’s customers – and not other stakeholders – will ultimately bear the economic consequences of BPA’s decisions on market participation,” the representative said.

The letter comes nearly two weeks after BPA released the results of a production cost model study conducted by Energy and Environmental Economics (E3) showing that, under most scenarios across multiple market footprints, the agency stands to realize significantly greater financial benefits from participating in EDAM than Markets+. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)  

BPA officials have played down the significance of those findings, saying production cost models don’t provide the full picture of market benefits that are harder to predict or quantify. 

While the officials noted the study results will weigh in BPA’s final decision, they’ve said they’re holding to a staff recommendation that the agency choose Markets+ over EDAM for more qualitative reasons, such as a governance framework independent from California state influence and a market design BPA contends is rooted in that independence — a stance causing increasing consternation among the Northwest’s EDAM supporters. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop.) 

The Nov. 12 letter to Turk reiterates BPA’s perspective and elaborates further by pointing to “unforeseen” consequences the POUs could face from the agency’s decision. 

“While production cost models can offer some broad insights, they also suffer considerable deficiencies,” the letter says. “First, they are limited in scope because they cannot assess critical governance and market design risks that impact BPA’s long-term reliability and cost-effectiveness. Second, production cost models that rely on oversimplified inputs produce imprecise results, failing to capture the complete costs and benefits of day-ahead market decisions. A risk-informed governance evaluation is essential to protect BPA and its customers from unforeseen risks.” 

The letter reinforces another repeated contention by BPA officials: that the agency must continue to fund Markets+ so BPA — and the rest of the West — have two “viable” markets from which to choose.  

The POUs note that they have encouraged the agency to fund the next phase of Markets+ “as a prudent investment for BPA’s long-term strategic goals and the only path that aligns with BPA’s mission. Only Markets + offers both a competitive, independently governed structure and a fair market design alternative to CAISO EDAM.” 

New Angle?

The letter’s signatories also see an apparent longer-term benefit in two Western markets sitting side-by-side. 

“The existence of both Markets+ and CAISO EDAM fosters a competitive environment in which governance and market design can evolve in ways that will ultimately yield more balanced outcomes for Western utilities and their customers,” the utilities said. 

But the letter makes clear that for the POUs, the key element comes down to governance — and continued “autonomy” for BPA within a market framework.  

“Markets+ is uniquely positioned to support BPA’s autonomy while addressing these governance factors,” the letter says. “It also offers fair market design elements that ensure durable and equitable outcomes for BPA’s preference customers and the region. This has been evident throughout the development of Market+; stakeholders have adopted design elements that enable BPA to meet its statutory obligations yet remain accessible to all participants.” 

The letter appears to introduce an angle to the Western market debate that has not been publicly aired before: that BPA’s preference customers would reexamine its relationship with BPA if they are dissatisfied with the agency’s market decision. 

The letter contends that the publicly owned utilities “have been the foundation of BPA’s funding, entirely supporting the agency through rates” for 80 years.  

“This historic partnership has enabled BPA to fulfill its mission and meet statutory commitments to its customers, the region and the U.S. Treasury. BPA’s sensible stewardship of our investments that aligns with our communities’ needs is critical to our continued willingness to sustain the agency financially,” the utilities wrote. 

Asked whether that meant the POUs would seek alternative power supplies if BPA chose EDAM, a representative of the letter’s signatories said, “Not at all. The statement emphasizes the foundational role of BPA’s alignment with the priorities and needs of its preference customers in sustaining a strong, collaborative partnership.”

“It does not suggest that we are considering other sources of generation if BPA were to join EDAM. On the contrary, we are focused on ensuring the long-term stewardship of BPA’s resources for the benefit of our ratepayers for generations to come,” the representative said.

Seattle City Light, a POU and BPA preference customer that has publicly supported the agency joining EDAM rather than Markets+, told RTO Insider that it disagrees with the letter’s assertion that BPA customers will be better served in Markets+.   

Noting the results of the recent E3 study, the utility said in an email that “BPA’s analysis found that EDAM or opting for WEIM-only participation would result in considerably greater economic benefits than Markets+, and it is unlikely that Markets+ governance or market design will produce better outcomes.”   

“City Light continues to believe our customers are best served with an efficient, well connected and integrated market, and should not rely on misrepresentations about the risks of EDAM market design and governance to obscure the results of its economic analysis. BPA’s end-use customers deserve a day-ahead market decision that does not ignore the physics and economics of the grid, and the impacts on their rates,” the utility said. 

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White House Releases Plan to Triple US Nuclear Power by 2050

The Biden administration on Nov. 12 rolled out a new plan to triple nuclear power in the U.S. by 2050, with a multipronged strategy of building new large and small modular reactors, adding power to and extending the life of existing plants, and bringing recently closed installations back online.

The U.S. has 94 reactors in operation at 54 sites in 28 states, most of them built in the 1970s and 1980s, the plan says. But the Department of Energy estimates the country will need 200 GW of new nuclear capacity “to keep pace with future power demands and reach net-zero emissions by 2050,” according to a Nov. 12 blog accompanying the release of the report.

The White House wants to jumpstart a “nuclear deployment ecosystem” by getting 35 GW of new nuclear power online or under construction by 2035 and then build to a steady pace of deploying 15 GW per year in the U.S. and globally by 2040 ― targets the report calls “ambitious yet achievable.”

For example, the report notes that “uprating” existing plants ― increasing their capacity through plant upgrades and the use of advanced fuels ― could increase their power output by 10% to 20%. Other DOE research suggests building new reactors at existing plants could add 60 GW or more of new capacity.

DOE also supports the development of SMRs through its Advanced Nuclear Reactor Demonstration Program, which received $2.5 billion in the Infrastructure Investment and Jobs Act. The department’s Loan Programs Office in September announced a $1.52 billion loan to Holtec to support the reopening of the 800-MW Palisades nuclear plant in Michigan.

Nuclear currently provides about 20% of all U.S. power and close to half of its carbon-free electricity, and interest in the clean, 24/7 power that reactors produce has intensified as companies like Microsoft, Google and Amazon look for power for their hyperscale data centers.

In October, Google signed a first-of-its-kind contract to buy power from a series of SMRs being developed by Kairos Power, and Microsoft is partnering with Constellation Energy on the controversial reopening of a reactor at Three Mile Island. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

The report notes that “a diverse set of technologies” will be needed to meet the different needs of customers and calls for “customers with large power needs and carbon-free commitments to work creatively with utilities to help share project risks commensurate with resulting benefits of successful deployment.”

The Need for Standardization

The report also makes an argument for nuclear expansion as critical for national security.

The majority of new reactors built worldwide in the past decade have been either Russian or Chinese, the report says. “It is imperative that the United States and allied countries compete effectively to supply the world with clean and safe nuclear energy. Yet, countries abroad typically want new reactor technologies demonstrated in the supplier country before building them in their own country.

“Domestic deployments will enable exports and provide a pathway for the United States to regain leadership in the international nuclear energy market and supply chain.”

According to DOE, a majority of existing U.S. nuclear power plants could add up to 60 GW of new capacity with large-scale light water reactors. | DOE

A major challenge moving forward, for both large-scale and SMRs, will be overcoming investor and utility concerns about time and cost overruns, with the report calling for better standardization of reactor designs.

The existing U.S. nuclear fleet did not move down the cost and time curves “in large part because most plants were built with unique, bespoke designs,” the report says. “The 94 currently operating reactors in America represent over 50 different combinations of reactor types, nuclear steam supply systems, models, power levels, containment types and balance-of-plant architecture.”

The next generation of reactors “must feature greater standardization, along with integration of modern design, project management and construction techniques, and a wealth of lessons learned from past deployments,” the report says.

Out but not Down

Any plans by the Biden administration would appear to be moot given the incoming Republican administration, but nuclear energy is one of the rare points of bipartisan agreement, as exemplified by the passage of the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy Act of 2024 (S. 870), signed by President Joe Biden in July.

The law aims to accelerate the licensing of new reactors with provisions that reduce licensing fees for SMRs and require the Nuclear Regulatory Commission to streamline licensing for microreactors and cut the timelines for licensing new reactors planned for existing plant sites.

The report lists 30 actions the U.S. government can take “within existing statutory authorities,” along with recommendations for industry and customers. The NRC has issued its own License Renewal Roadmap to streamline reactor relicensing, but the report encourages plant owners to coordinate with the commission on the timing of their relicensing applications “to produce a more consistent workload for NRC … and ensure resources are in place and priorities are shifted as necessary.”

The administration also is following through on a U.S. commitment to the Declaration to Triple Nuclear Energy made by more than 20 countries in 2023 at the 28th U.N. Climate Change Conference of the Parties (COP28) in the United Arab Emirates.

Speaking at COP29 in Azerbaijan on Nov. 11, White House Senior Adviser John Podesta acknowledged that President-elect Donald Trump would pull the U.S. out of the Paris Agreement again, but that would not stop states, cities and businesses from continuing their commitments to cut emissions to limit global warming to 1.5 degrees Celsius.

“The economics of the clean energy transition have simply taken over,” Podesta said in a White House release. “New power generation is going to be clean. The desire to build out next generation nuclear is still there. … The hyperscalers are still committed to powering the future with clean energy, including safe, reliable nuclear energy. … All those trends are not going to be reversed.”

Trade associations sought to focus on the economic and bipartisan appeal of nuclear in their reactions to the report.

“Nuclear generation is uniquely positioned to help the United States achieve our climate and national security goals, while creating a reliable energy system to meet growing demand,” said Maria Korsnick, CEO of the Nuclear Energy Institute. “We look forward to continuing to advance strategies that extend the lives of existing nuclear reactors, usher in a new era of advanced technologies and support a global marketplace for U.S. exports.”

While welcoming the report’s aggressive targets, Judi Greenwald, executive director of the Nuclear Innovation Alliance, said the “next steps are up to the incoming administration and Congress. We look forward to continuing bipartisan and public-private cooperation to build on our shared accomplishments and increase investment and innovation in the next generation of advanced nuclear energy.”

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NERC: Board’s 321 Authority on the Table for Cold Weather Standard

NERC Vice President of Engineering and Standards Soo Jin Kim on Nov. 12 said the ERO’s ongoing cold weather standards project could supply the next opportunity for the Board of Trustees to exercise its authority to streamline the normal stakeholder approval process. 

Speaking at a technical conference about Project 2024-03 (Revisions to EOP-012-2), Kim acknowledged “there’s a little bit of industry fatigue” around the effort. She was referring to the fact the cold weather standard is undergoing its second set of revisions after FERC approved the original version, EOP-012-1 (Extreme cold weather preparedness and operations), in 2023 and its successor, EOP-012-2, this year but ordered changes each time. (See FERC Orders Further Cold Weather Standard Modifications.) 

The deadline for the FERC-ordered revisions to EOP-012-2 is next March, but the replacement standard EOP-012-3 recently failed to gain industry approval in its first formal ballot period that concluded Nov. 5. The standard received 70 supportive votes from industry stakeholders but 129 negative votes with comments; 55 respondents either abstained or did not vote. The result was a segment-weighted 42.29% in favor of passage, well short of the two-thirds majority needed to put it before the board. 

A similar situation caused the board to invoke for the first time its authority under Section 321 of NERC’s Rules of Procedure at its last open meeting in August. On that occasion, the failure of PRC-029-1 to receive industry approval led the board to direct the Standards Committee to host a technical conference in September to hear industry feedback on the proposed standard. Convening a tech conference is among the options in the section available to the board if stakeholders do not pass a proposed standard directed by FERC or NERC. 

In the case of PRC-029-1, FERC had ordered NERC to develop standards governing inverter-based resources. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Following the conference, NERC used the input to revise the standard, and it subsequently passed a final ballot, which was submitted to FERC along with four other standards governing IBRs. 

Following the success of the new process, NERC indicated it might convene technical conferences for other projects that have faced difficult ballot processes, in hopes of proactively addressing stakeholder concerns. At this week’s conference, Kim said additional action — including another use of the Section 321 powers — has not been ruled out. 

“I have gotten a lot of questions with regard to [whether] this project [would] be a candidate for 321 action,” Kim said. “The answer is ‘yes.’ We do feel this risk is very critical, and this is one of those projects where, if we are at an impasse … would be a candidate for 321 recommendations.” 

Kim emphasized that NERC’s board has not made any decision about whether to invoke the Section 321 authority at this point and will “probably” not discuss the issue at its open meeting in December; the standard’s “next ballot will be the determining factor,” she added.  

She explained she wanted to be “very transparent” about the possibility of special action after NERC received feedback from industry that the ERO had not been forthcoming about its consideration of using Section 321 for the IBR standards.  

“I don’t want anyone to ever come back and say that we were not very upfront about whether or not this is a potential risk for us moving forward,” Kim said. “We are very concerned [about] making sure that industry is able to mitigate these risks with regard to certain timelines.”