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November 5, 2024

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Retired NYISO COO Rick Gonzales Shares Stories from Long Career

When former Chief Operating Officer Rick Gonzales looks back on his more than two decades at NYISO, two events stand out among all else: the Northeast blackout in 2003 and Superstorm Sandy in 2012.

The 2003 blackout cut power to 55 million people in the U.S. and Canada and reduced the ISO’s load by 80%. Gonzales found himself continuously on the control room floor performing engineering support duties and working with the control room operators to restore power. The key was getting the ISO’s biggest line reconnected with PJM.

“I worked 24 hours straight that day,” Gonzales, who retired Dec. 31, said in an interview with RTO Insider. It was “probably the best day of my career, even though it’s probably the event that most people dread when they think about it.”

The blackout prompted Congress to enact the Energy Policy Act of 2005, which gave FERC authority to set mandatory reliability rules.

Gonzales remembered three long days of work following Superstorm Sandy, which severely impacted New York, particularly New York City, killing more than 50 people and destroying thousands of homes and an estimated 250,000 vehicles.

“[The storm] caused significant loss of generation and load, but we were able to keep the New York state grid up,” he said. “That was another really interesting event — really challenging event — but we came through it pretty well.”

Gonzales, who has been with NYISO since its inception in 1999, began working in the New York energy industry in 1987 when the ISO’s predecessor, the New York Power Pool, was responsible for grid operations. He was replaced as COO by Executive Vice President Emilie Nelson, effective Oct. 1. (See Emilie Nelson Named NYISO COO, Replacing Rick Gonzales.)

Reflecting on the early years at NYISO, he recalled “a lot of growing pains” and “regulatory uncertainty.”

“Getting [NYISO’s] markets up was a great thing from a reliability perspective” he said, since under NYPP, “we didn’t have the level of control of operating resources that we have today. … It really was a great step in the right direction and a major improvement to reliability.”

Gonzales recalled the debate over whether ISOs should be large, multistate regional transmission owners like PJM or ISO-NE. Gonzales said he and other staff concluded that “there really wasn’t a lot of cost savings” in being a large, multistate operator, since the generating fleets of New York’s neighbors were similar to its own at the time.

At one time, “being a single-state ISO was viewed as a negative, when compared to the broader multistate ISOs,” he said. Now, however, being a single-state entity “makes things easier because we only have one regulator and one set of policies to try and implement.”

“It’s been really intriguing to me over the years, how [being a single-state ISO] has turned from almost a negative into a positive attribute for the organized market in New York,” he added.

Asked for an insight he wanted to share with the next generation of leaders, Gonzales responded that “having a good technical foundation” and “being able to interact with regulators and stakeholders” are keys to success.

“So much of the energy industry is now charged with policy and regulatory directives,” he said. “So, it’s great to have a strong technical understanding of whether these new policies can work.”

NYISO’s Evolution

As the ISO has evolved from a basic grid operator responsible for keeping the lights on to a key player in New York’s clean energy shift it has been increasingly charged with providing unbiased technical information.

“I’ve seen a tremendous increase in the amount of information flowing out of NYISO to the state regulators primarily, but also to the Legislature,” he said, adding that ISO staff has been “doing a lot more outreach to these folks to provide them with unbiased information.”

Gonzales said he is optimistic about NYISO’s ability to adapt to the challenges of transitioning from fossil fuels to renewable energy resources.

From an engineering perspective, the biggest risk is “maintaining the expected level of reliability under this grid in transition,” he said.

He said New York should study how other regions transitioning away from fossil fuels, such as California, have faced reliability challenges.

“I think that regulator’s fear is that if reliability is compromised and people’s lights go out, and it can be linked in any way, shape, or form to the new set of resources or policy initiatives, then the public may not be supportive [of this transition] in the long term,” he said.

Gonzales said regulators “seem to understand that this [transition] is a difficult balance” and that the public broadly understands this challenge as well.

Gonzales also was asked about the role emerging clean energy resources, such as distributed energy resources (DERs) or dispatchable emissions-free resources (DEFRs), have in New York’s transition and the grid of the future.

Gonzales responded that these resources will be critical to achieving the goals of the state Climate Leadership and Community Protection Act (CLCPA), which calls for an 85% reduction in greenhouse gas emissions by 2050 and a 40% cut by 2030.

“The DEFR question is really interesting because it could be anything,” he said. “It could be modular nuclear; it could be some iron-based battery or other long-term battery. But it’s such an unknown that it is difficult to opine on.”

He added that the ISO is close to implementing the software necessary to integrate DERs into the ISO’s markets, which should help significantly with the state’s transition.

“Anything that’s dispatchable, however, is going to be a good thing for grid operations,” he added. “And even though [DEFRs] may be subject to operational limitations, if we can model it, then we can make it work.”

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MISO Year in Review: 2023 — and Likely 2024 — Dedicated to Deflecting Reliability Issues

MISO juggled several projects over 2023 designed to fend off imminent reliability problems and will keep up the multitasking in 2024.

“I’m still concerned about pace. We still have a lot to do to stay ahead of our reliability issues,” MISO CEO John Bear said during MISO’s final board meeting of the year in December.

However, Bear said MISO accomplished much over 2023, including the largest MISO Transmission Expansion Plan (MTEP) it’s ever produced, a plan to install a sloped demand curve in the capacity auction, work on a future availability-based capacity accreditation for all resources and analyzing the system in preparation for a second cycle of long-range transmission projects.

“Thank you, thank you, stakeholders, for all the work you’ve done this year, and thank you in advance for all the work that you will do in 2024,” Bear said.

Outgoing Organization of MISO States President and Chair of the Michigan Public Service Commission Dan Scripps said MISO has come a long way in the short time since the 2022/23 capacity auction returned a regionwide shortfall in the Midwest.

“Sitting here today, I want to congratulate you on how far we’ve come since last spring,” he told members and directors.

Staff Issue Warnings: 1st Seasonal Auctions Measure up

Despite the grid operator raising alarms over future reliability, MISO’s first four-season capacity auction returned adequate supply, clearing capacity mostly between $2/MW-day and $15/MW-day. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

MISO conducted the more complex seasonal auction a month later than usual in 2023, impeded by a FERC show-cause order because the RTO incorrectly calculated an unforced capacity-to-intermediate seasonal accredited capacity ratio that it uses to determine supply ahead of the auction.

“The implementation wasn’t completely smooth. There’s always a tradeoff between moving more deliberately and faster, so I’m not particularly worried about that,” MISO Independent Market Monitor David Patton reflected in June on MISO’s seasonal auction.

MISO Executive Director of Resource Planning Scott Wright said the 2022 capacity auction spurred members into adjusting plans that “changed the complexion of the footprint” in the 2023 auction and allowed all zones to meet their reserve targets.

The year ultimately held one maximum generation emergency for MISO at the end of August. (See MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave.)

MISO staff is clear the footprint’s current status as capacity-sufficient is temporary and that thermal plant retirements can be held off for only so long. They spent late spring repeating that the economical capacity prices belied MISO’s mounting resource adequacy risk.

Vice President of Operations Renuka Chatterjee said MISO has a five-year market redefinition plan focused on ensuring its markets can better anticipate growing load uncertainty and output variability.

“Getting to seasonal was so important,” Chatterjee said of MISO’s capacity auction, adding that it’s also valuable to accredit all resources based on when they’re likely to be available over a season.

Last month, MISO reported that over the last five years, its installed wind capacity has increased by 74%, while solar has increased by 1,261%. Combined, MISO’s wind and solar fleet is nearing 30 GW.

MISO’s annual resource adequacy survey in conjunction with the Organization of MISO States this year showed the potential for a 2.1-GW total shortage in the summer of the 2025/26 planning year that could escalate to a 9.5-GW shortfall by the 2028/29 planning year.

Queue Scrutiny

In spite of the RA survey results, the MISO footprint continues to sit on 50 GW of new generation projects that are cleared to connect to the system but are languishing unconstructed. The unrealized gigawatts have added more concern to MISO’s resource adequacy problems. (See “50 GW in Greenlit and Unfinished Projects Haven’t Budged,” MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries.)

“Once we get supply chain issues figured out, we’ve got good projects that will make reliability contributions. … But the timing is pretty unclear, when these technologies can be deployed at scale,” Wright told the Advisory Committee at its Sept. 13 meeting.

The Cardinal-Hickory Creek line under construction | ATC and ITC Midwest

Fresh Energy’s Mike Schowalter said MISO is on “the tip of the iceberg” in terms of renewable energy and intermittent output. He also predicted distributed energy resources are going to be “bigger than we appreciate.”

At the same meeting, Michigan Public Power Agency’s Tom Weeks said the threat a warming planet presents means MISO members must come up with answers quickly on how to reliably accomplish a decarbonized fleet. He said members of the Advisory Committee should devote meetings to discussing emerging issues.

At last count, MISO’s queue contains more than 1,300 mostly renewable energy projects at nearly 230 GW — or about double its footprint-wide load on a hot summer day. Most of the proposed projects in the study phase of MISO’s interconnection queue are delayed.

“I think looking into the future, the queue is the future. If you want to know what’s coming in 10-15 years, look at the queue,” Wisconsin Commissioner Tyler Huebner said at the September Advisory Committee meeting.

MISO, hoping to cut back on speculative projects in the queue, proposed to establish an annual megawatt cap on projects, enforce stricter proof of land use, enact automatic and escalating monetary penalties for withdrawals, and increase milestone fees for its generator interconnection queue. That filing is awaiting FERC’s approval, with many stakeholders saying there’s no proof a megawatt cap will speed up MISO’s study processing times. (See MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries.)

As the holidays came and went, MISO still hasn’t closed its window on accepting proposed generation projects for its 2023 interconnection queue cycle. It said it’s holding off on rounding up new projects until FERC renders a decision on the measures.

“You shouldn’t be in the queue if it’s not your intent to build as soon as you have a [generator interconnection agreement],” MISO’s Andy Witmeier said during the August Planning Advisory Committee meeting.

MISO expects members will add 369 GW of new, mostly renewable resources by 2042 and have retired about 103 GW of their existing fleets, bringing the RTO’s total installed capacity to 466 GW. However, only 202 GW of that capacity is assumed to be accredited; staff assumes a declining effective load-carrying capability for the renewable additions. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.) MISO today operates with about 194 GW in nameplate capacity.

MISO

MISO’s prediction of installed capacity in gigawatts by 2042, including new and retired resources based on its members’ plans | MISO

MISO similarly is waiting to hear from FERC if it can move ahead with a sloped demand curve in its capacity auction. (See FERC Wants More Detail on MISO Sloped Demand Curve Plan.)

During MISO’s June Board Week, Illinois Commerce Commissioner Michael Carrigan thanked MISO for moving toward a sloped demand curve in its capacity auctions. He said then RTO “cannot ignore portions of the footprint that use different planning approaches,” referring to Illinois’ status as a retail choice state.

“We’ve been in market failure for 20 years because we have a demand curve that doesn’t produce any signals for developers,” Patton said of MISO’s existing vertical demand curve at the beginning of 2023.

New LTRP Portfolio Recommendation

Lastly, MISO is forging ahead with a second long-range transmission (LRTP) portfolio despite a standoff between it and its Independent Market Monitor over their differing visions of the RTO’s resource mix in 20 years. (See IMM Criticizes MISO’s Modeling Software Used for Long-range Tx Planning; MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio.)

MISO has said it will reveal line recommendations next year and has emphasized lines will be needed for reliability’s sake to support its members’ energy transition. The RTO is accepting transmission project suggestions from stakeholders.

During a Dec. 6 Advisory Committee meeting, ITC’s Brian Drumm said “rocket fuel” is being poured on the energy transition, requiring major transmission planning of MISO. Drumm told fellow members the “risks of falling behind are much greater” than taking a stab at new line recommendations.

In midyear, MISO proposed a 50/50 split on its third LRTP portfolio, where costs would be allocated 50% regionally and 50% to local zones where the projects are located. The new cost allocation design is tailored specifically to the upcoming transmission projects MISO will recommend for its South region. It’s unclear whether FERC will sanction a separate cost allocation for different LRTP portfolios. So far, Midwestern LRTP projects use a 100% postage stamp to load allocation.

MISO long has said allocation negotiations are a major challenge to raising new transmission towers.

“We can come up with projects, but the allocation is typically the most challenging part of addressing the needs of the fleet evolution,” Vice President of System Planning Aubrey Johnson told board members at a June 13 System Planning Committee meeting.

The grid operator this year also began seriously discussing the possibility of installing HVDC lines to meet broad regional needs. (See Experts Urge MISO to Consider New 765 kV and HVDC Lines.)

In June, Director of Expansion Planning Jeanna Furnish said MISO might consider stringing long-distance, high-voltage lines to allow transfers between load centers like the Twin Cities to St. Louis to Des Moines.

“Staying where we are is not possible. Staying where we are is fraught with [reliability] risks,” Senior Vice President of Planning and Operations Jennifer Curran said at a March board meeting.

“We’ve got 40 million people depending on us for their lives and livelihood, so we have to get this right in this transition,” Bear added.

Bear said the widespread winter storm in December 2022 was in fact a positive because it tested the system, control room and staff. He said it’s important for MISO to be able to test its limits.

“There’s a whole lot in front of us, next year, next year and probably the year after that,” Bear said. “Just in case we get complacent, there’s another extreme weather event every 18 months to keep us on our toes.”

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IMIP Approves SPP Markets+ Governance Tariff Language

SPP’s Markets+ senior leadership closed out 2023 by approving the day-ahead market’s proposed governing document, a significant milestone in the grid operator’s drive to file a tariff with FERC in early 2024.

The Interim Markets+ Independent Panel (IMIP), composed of three of SPP’s independent directors, signed off on the document during a Dec. 19 conference call.

The stakeholder-driven Markets+ Participants Executive Committee (MPEC) endorsed the governance structure earlier in December. However, the structure received only 73% of the favorable votes over concerns by independent stakeholders that weighted voting factors could lead to unintended consequences in their sector. (See SPP’s MPEC Approves Markets+ Governance Plan.)

The IMIP accepted a friendly amendment to defer consideration of the independents voting structure until a future meeting. SPP general counsel Paul Suskie said he will work with MPEC Chair Laura Trolese to set up more discussions before its Jan. 23-24 meeting in Westminster, Colo.

“We’re encouraging the MPEC to have additional conversations and a discussion before the meeting itself regarding those voting within the independent sector,” IMIP Chair Steve Wright said. (The IMIP is serving as an interim governance body until a MIP is agreed upon in a later phase of Markets+.)

Under the governance rules adopted by MPEC on Dec. 7, votes by the investor-owned utilities and public power member sectors will be weighted based on their load share. Voting among the independents will be structured to ensure that participants contributing generation to the market receive two-thirds of the sector vote, while those without generation receive one-third.

The Northwest and Intermountain Power Producers Coalition (NIPPC), representing independent generation developers and storage, power marketers and affiliated companies, was unsuccessful in seeking to continue the status quo of giving each independent member a single vote within the sector.

NIPPC’s executive director, Spencer Gray, reminded those on the call that the MPEC’s governance vote was on the attachment as a whole.

“I don’t want to guess how the rest of the sector who voted no would have voted if the issue were just narrowly on this part of the governance attachment,” he said. “I wouldn’t want an amendment to the motion and approval of that to constrain us to the degree we can’t address that connected issue to the intersector voting, but it’s not narrowly limited to what the weighting of the vote is. It’s a secondary important issue anticipating tensions in the future in the market.”

“All we’re doing is acknowledging more work needs to be done on this particular section,” the IMIP’s John Cupparo said. “That doesn’t preclude conversations on the rest of it, even with the approval.”

The approved language also spells out Markets+’s functions, including: the makeup and roles of SPP’s Board of Directors, permanent MIP, MPEC, Markets+ State Committee and other standing committees; the MIP election process; meeting policies; the voting process for market policies; and process for appealing decisions. It also covers the establishment of working groups and task forces, the role of SPP staff, and attendance and proxy voting policies.

The Markets+ Greenhouse Gas Task (GHG) Force reported progress in its effort to incorporate GHG emissions-related information in the market’s reporting, price formation, commitment and dispatch processes. The Public Generating Pool’s Mary Weincke, who chairs the task force, told the IMIP the group reviewed and updated its conceptual design and tariff language during two December meetings.

The task force, which next meets Jan. 3, has created an ad hoc group to start working on a concept for nonpricing programs, separate from the more important task of developing a pricing program solution.

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Study Examines Critical Minerals Potential in West

In the quest to increase U.S. domestic production of critical minerals needed for clean energy technologies, there have been successes and setbacks, researchers said during a recent webinar.

One success is the Gibellini vanadium mine near Eureka, Nev., which will be the first primary vanadium mine in the country.

Nevada Vanadium Mining Corp.’s Gibellini mine received approval from the Bureau of Land Management in October, “which is huge,” said Taylor Quinn, a graduate student in the mineral and energy economics program at the Colorado School of Mines.

Quinn spoke during a critical minerals webinar hosted by the Western Interstate Energy Board (WIEB) on Dec. 13. She was joined by Ian Lange, director of the mineral and energy economics program.

Vanadium is used in long-duration energy storage systems, as well as in steel manufacturing and aerospace applications. The U.S. Geological Survey has deemed it a critical mineral.

The Gibellini project is expected to produce almost 10 million pounds of vanadium a year, enough to meet about 60% of U.S. demand.

Quinn also gave an example of a critical minerals setback: Rare Element Resources’ proposed Bear Lodge mine in Wyoming. The Bear Lodge site features high-grade deposits of rare earth elements that are important in green technologies such as electric vehicles, solar panels and wind turbines, the company said on its website.

The mining project was suspended in 2016 after more than $140 million was invested, Quinn said, due to the falling prices of rare earth elements and struggles with the permitting process.

Now, Rare Element Resources has revived the project with a new rare earth processing method. But the company still must navigate the permitting process, Quinn said.

“So while the Bear Lodge mine is not a failure by any means, it’s just an example to show you how long these processes can take and the setbacks that you can experience,” she said.

The federal government has created a streamlined permitting process for certain infrastructure projects through the FAST-41 initiative. The name is a reference to Title 41 of the Fixing America’s Surface Transportation Act of 2015.

Infrastructure projects may be eligible for the FAST-41 process if they’re in one of 18 designated sectors, which include renewable or conventional energy production, electricity transmission, carbon capture and mining.

Although offshore wind and solar projects have been accepted for FAST-41 streamlining, so far only one mining project has been covered, Quinn noted. In May, the federal Permitting Council announced FAST-41 coverage for the South32 Hermosa project, a proposed $1.7 billion zinc and manganese mining and processing operation near Tucson, Ariz.

Requested Research

The researchers’ work was funded by WIEB’s reserve expenditure plan, which is designed to reduce the organization’s long-term financial reserves to targeted levels through the funding of various projects. WIEB member states proposed the project.

The U.S. is now dependent on other countries to supply critical minerals needed for the clean energy transition, WIEB said in explaining the research. According to the International Energy Agency, clean energy technologies will account for 90% of global lithium demand over the next two decades, 60% of demand for nickel and cobalt, and 40% of demand for copper and rare earth elements.

“This project explores the potential for Western states and provinces to supply these critical minerals and materials domestically to support this transition,” WIEB said.

In addition to traditional mining techniques, such as open pit mines, Quinn also pointed to new technologies being explored.

One of those is recycling of tailings, which are materials such as ground rock left over after ore is processed. The tailings may contain significant amounts of high-grade minerals, especially at mines that were decommissioned long ago, she said.

In addition, the Department of Energy has been supporting efforts to extract critical minerals or rare earth elements from coal production waste, such as fly ash.

Recycling of minerals from used batteries is another option that’s expected to gain momentum as more batteries reach the end of their lives.

Sustainable Mining

Meanwhile, sustainable mining practices are being adopted, Quinn said.

Caterpillar is developing battery-electric mining trucks and has entered into electrification agreements with mining companies including BHP, Freeport-McMoRan and Newmont Corp.

Nevada Vanadium Mining’s Gibellini mine will be powered by clean energy from solar panels and battery storage built at the site. Haul trucks and other mine equipment will be electric, according to BLM.

The storage system will include a vanadium flow battery — a technology that’s viewed as being relatively safe and having a long lifespan.

Interest in vanadium flow batteries is growing. In October 2022, the California Energy Commission approved a $31 million grant through its long-duration energy storage program for a project that includes vanadium flow batteries from Invinity Systems and zinc hybrid cathode batteries, paired with carport solar panels. (See California Energy Commission Grants Long-Duration Storage Project $31M.)

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Biden Admin. Releases Proposed Rules for Hydrogen Tax Credits

To qualify for the Inflation Reduction Act’s tax credit for clean hydrogen, a plant’s power will have to be new clean energy generated in the same region as the plant and, by 2028, be matched to demand hour-for-hour, according to proposed rules the Treasury Department and Internal Revenue Service released Dec. 22.

Those three “pillars” — additionality, deliverability and time matching — are at the core of Treasury’s Notice of Proposed Rulemaking, which details all the definitions and conditions hydrogen producers will have to meet to cash in on the IRA’s 45V production tax credit. Meeting all the proposed requirements in the NOPR could be worth $3/kg of clean hydrogen produced for 10 years from the date a new clean hydrogen plant goes online.

The 45V credit is technology agnostic but requires that a plant’s lifecycle greenhouse gas emissions — measured from “well to gate,” or up to the point of production — must be between .45 kilograms and 4 kg per kilogram of hydrogen. As with other IRA tax credits, the plant also must pay prevailing wages and participate in registered apprenticeship programs.

The base amount of the tax credit has four tiers, beginning at $0.60/kg for emission of less than .45 kg per kilogram of hydrogen, and bottoming out at $0.12/kg for emissions of 2.5 kg to 4 kg. Those rates then can be multiplied by five if the prevailing wage and apprenticeship requirements are met.

To qualify for the credits, the clean hydrogen must be produced in the United States or a U.S. territory.

The NOPR’s provisions on measuring a plant’s lifecycle emissions are where things get complicated, especially if a plant is using electricity off its local grid, which in most cases will include some power generated with higher-emitting fossil fuels. The electrolyzers that split hydrogen off water molecules to make green hydrogen are “very energy intensive,” according to a senior administration official, speaking at a prerelease press call Dec. 21.

“If you put a lot of energy into [making hydrogen], and you’re taking those resources off of powering homes and industry and buildings, then that power has to come from someplace, and if it’s being backed up with fossil fuel power, you’re adding to emissions.”

Treasury worked with the Department of Energy and EPA to develop a workable strategy for measuring lifecycle emissions, Developers or plant owners will be able to use DOE’s Greenhouse Gases, Regulated Emissions and Energy Use in Transportation (GREET) platform, a computer modeling tool, modified for hydrogen, according to the Treasury press release.

The new model and a user’s manual were scheduled to be publicly available Dec. 22.

Treasury, DOE and EPA officials at the prerelease briefing stressed that the rules being released are only proposals. The NOPR includes questions on issues that are still unresolved and need more input from stakeholders, they said.

The release Dec. 22 begins a 60-day comment period. A public hearing is scheduled for 10 a.m. EST March 25.

Energy Attribute Credits

Under the proposed rules, producers would use energy attribute credits (EACs) to demonstrate that they are, in fact, purchasing clean power based on the three criteria. The goal here is to provide rigorous standards for clean energy, while also allowing flexibility to account for emerging and evolving technologies.

In a DOE white paper also released Dec. 22, EACs are defined as “legal instruments that represent an exclusive claim to the attributes of a unit of energy. … In the case of electricity, EACs verify that a certain unit of electricity was generated by a specific entity and has specific associated attributes.”

EACs include renewable energy credits but are not limited to renewable generation.

For the EACs used for the 45V tax credits, the critical attributes include:

    • New clean energy is defined as any generation that went online within three years of the hydrogen plant going into operation. It could also include existing plants that expand capacity.
    • The proposed rule on deliverability would be based on the transmission regions identified in DOE’s recent National Transmission Needs Study. Because California, New York and Texas are self-contained transmission regions, Treasury may consider allowing clean power from an adjacent region to qualify.
    • Technology to provide hourly time matching is not yet widely available, so Treasury is proposing a transition period to allow annual matching until 2028, “when hourly tracking systems are expected to be more widely available.”

The exact transition timeline for time matching is one of the questions raised in the NOPR for additional stakeholder input.

Others include whether electricity from existing clean power projects or power plants that otherwise might be retired, such as nuclear plants, might be classified as new clean energy under certain conditions, and whether hydrogen produced from renewable natural gas or “fugitive methane” might qualify.

“We’re looking for pathways that will create the environmental integrity that we’re seeking, but that we believe will allow the nuclear industry to participate in the clean hydrogen economy,” the senior official said. “There are a series of potential pathways, including upgrading the facility, relicensing pathways that anticipate losses in generation as a result of retirements that could happen and including a carveout that would create a safe harbor essentially, where a percentage of their production can go into clean hydrogen.”

What They’re Saying

The U.S. has a well-established hydrogen industry, based on “gray” hydrogen technologies that use methane or natural gas (which is predominantly methane) as feedstocks. Speaking at the prerelease briefing, DOE Deputy Secretary David Turk noted that at present, clean hydrogen production in the U.S. is under 1 million metric tons (MMT) per year. President Biden’s goal is an industry that can produce 50 MMT per year by 2050.

“The 45V clean energy, hydrogen production tax credit is an important part of our strategy to unlock private investment across sectors and build a clean energy economy and tackle the climate crisis,” White House Senior Advisor John Podesta said at the briefing. “Clean hydrogen will be critical for reducing emissions from hard-to-decarbonize sectors like heavy industry and heavy transportation.”

“There is significant industry support for this [three-pillar] approach, as well as billions of dollars being invested in projects that have already announced they will follow this basic structure,” said Deputy Treasury Secretary Wally Adeyemo. “In addition to industry, investors have made it very clear that they’re looking to invest in projects that produce clean hydrogen, as well. … Allies and partners have already put similar structures for hydrogen in place, [so] having clear rules to ensure the U.S. develops a clean hydrogen industry will help drive innovation and demand for more advanced American-made electrolyzers.”

Backing up such statements, Treasury also has released additional statements from industry stakeholders voicing mostly positive support for the NOPR in general and the three pillars.

A recent letter from seven clean hydrogen and electrolyzer companies, including Air Products, Nordex Green Hydrogen and Electric Hydrogen, expressed “confidence that proposed 45V guidance requiring … additionality from day one, strong deliverability standards and a phase-in of hourly matching by 2028 … will support scaled industry growth.”

Laura L. Luce, CEO of Hy Stor Energy, a Mississippi-based green hydrogen producer, also supported the three pillars as critical foundation for long-term off-take agreements for clean hydrogen. The time-matching provisions in the NOPR “ensure the production of competitively priced hydrogen advanced organizations that are fully committed to the most timely and efficient industrial decarbonization,” Luce said.

But U.S. lawmakers are split on how strictly the three pillars should be formulated and enforced. Sen. Maria Cantwell (D-Wash.) led a group of 11 Democratic senators in a recent letter to Treasury, DOE and the White House, warning that overly strict definitions of clean hydrogen in the proposed rules might hamper industry growth.

The seven hydrogen hubs being funded with $7 billion from the Infrastructure Investment and Jobs Act include projects that would use natural gas or nuclear, which might not qualify for the tax credits.

In an Oct. 16 letter, Sen. Sheldon Whitehouse (D-R.I.) and seven other Democratic senators lobbied for a strict definition of clean hydrogen, excluding any produced with natural gas.

The lawmakers expressed grave concern about “the risk posed by weak standards for what constitutes clean hydrogen. Fundamentally, the 45V tax credit must not be applied to any projects that directly or indirectly increase power sector GHG emissions. Without safeguards, 45V risks creating a shell game in power markets, where existing clean generation gets nominally claimed by hydrogen electrolyzers, but the resulting gap in grid capacity is backfilled by fossil fuel generation.”

Disagreements over Hourly Matching

The proposal’s timeline for requiring hourly matching won praise from environmental organizations but drew fire from industry groups, including the American Council on Renewable Energy (ACORE), the American Clean Power Association and the Edison Electric Institute.

ACP CEO Jason Grumet called it a “a fatal – but fixable – flaw.”

“Imposing an hourly matching provision too early for first-wave green hydrogen projects will discourage a significant majority of clean power companies from investing in green hydrogen manufacturing and facilities,” he said. “ACP is encouraged to see that the Treasury Department has specifically requested comment on the adequacy of the transition schedule.”

Richard McMahon, EEI’s senior vice president for energy supply and finance, said the proposal lacked the flexibility to allow a rapid scale up to support a hydrogen economy.

The 2028 matching requirement “would undermine the commercial viability of this nascent domestic sector and severely limit the widespread adoption of hydrogen that is produced using grid-connected facilities,” he said. “As a result, the cost-reducing benefits for hydrogen included in the Inflation Reduction Act would be squandered, and an important new tool that electric companies and customers could be using to drive down carbon emissions and costs would be sidelined.”

But the Union of Concerned Scientists praised the proposal, calling it a “a strong foundation for accurately capturing the true climate impact of hydrogen production projects.”

“Rigorous guardrails are necessary to ensure the hydrogen tax credit incentivizes the scale-up of the right hydrogen, not just any hydrogen,” said Julie McNamara, senior energy analyst and deputy policy director of UCS’s Climate and Energy Program. “No less than whether or not hydrogen actually serves as a tool for climate progress hangs in the balance.”

The Natural Resources Defense Council also endorsed the hourly matching proposal.

“Anything less than the climate and consumer protections proposed today would be a giveaway to legacy energy companies eager to hijack hydrogen at the direct expense of the climate and consumers,” said Rachel Fakhry, NRDC’s policy director for emerging technologies. “Broad loopholes would be disastrous for the climate, kneecap our efforts to clean up the power grid, and harm the global potential of the U.S. clean hydrogen industry. Treasury must hold firm and finalize this strong guidance.”

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ISO-NE Details Order 2023 Tariff Changes

WESTBOROUGH, Mass. — ISO-NE outlined key components of tariff changes it plans to make to comply with Order 2023 at the Dec. 21 Transmission Committee (TC) meeting, including cluster timelines and storage study assumptions. 

Al McBride, director of transmission services and resource qualification, outlined the RTO’s proposed timeline for the cluster process, which would span 582 days before the initiation of a subsequent cluster. This is longer than the process proposed by FERC due to a 270-day cluster study period, 120 days longer than FERC’s proposal. To help reduce the total timeline, ISO-NE has cut the cluster restudy period to 90 days compared to its initial proposal of 150 days. (See ISO-NE Details Proposed Order 2023 Compliance.) 

McBride said the RTO will allow letters of credit for the commercial readiness deposits, in response to a stakeholder request at the November TC meeting. ISO-NE is proposing a $5 million commercial readiness deposit for large generators seeking to enter the transitional cluster study, and a smaller fee for small generators.  

Customers with a valid interconnection request as of May 1, 2024, will be able to proceed with a transition study or withdraw from the interconnection queue without penalties. 

ISO-NE is also proposing to incorporate its existing cluster enabling transmission upgrade (CETU) process into the new interconnection procedures. ISO-NE can initiate CETUs for state resource procurements that seek interconnection in similar locations, as well as for withdrawn interconnection requests in the same part of the New England Control Area. 

For ongoing affected system operator studies, which look at the effects of distributed generation projects on grid reliability, ISO-NE is proposing to allow transmission owners to continue studies if they are on track to be completed within 90 days of the start of the transitional cluster study.  

McBride also outlined ISO-NE’s proposal for studying storage resources, which differs from the approach taken by Order 2023. The order would let interconnection customers choose the maximum system load at which batteries will be studied, while requiring control technologies to prevent batteries from charging when load exceeds these limits. 

ISO-NE is proposing an approach that would avoid the need for control technologies, instead relying on energy market bidding to determine which batteries can charge. During the study process, the RTO is proposing to study batteries at an 18,000-MW “shoulder” net system load. 

NEPOOL will turn its focus to stakeholder amendments to the RTO’s Order 2023 compliance proposal at its Jan. 4 meeting. 

Longer-Term Transmission Planning

Brent Oberlin of ISO-NE introduced tariff changes associated with the second phase of ISO-NE’s Longer-Term Transmission Planning project. The project is aimed at enabling forward-looking transmission projects that can prepare the region for the load growth and changing resource profile associated with the clean energy transition. (See ISO-NE Updates Longer-Term Tx Planning Proposal.) 

The new process will allow ISO-NE to issue a request for proposals (RFP) at the direction of the New England States Committee on Electricity (NESCOE) to address reliability needs identified in longer-term transmission studies.  

To be selected in the RFP, bids will first be evaluated on whether they solve the identified reliability needs. ISO-NE will then consider a quantification of a project’s benefits relative to its total costs. The quantified benefits of a project must outweigh its costs over a 20-year period for the project to be eligible for selection, Oberlin said.  

Once these thresholds are met, the cost-benefit ratio will be one of the aspects considered by ISO-NE when selecting the preferred solution, along with factors like operability and expansion capability.  

Oberlin noted that NESCOE can cancel the project at any time throughout the process. This could introduce uncertainty for transmission developers, as the process would be contingent on the states agreeing on a cost allocation method. 

David Burnham of Eversource said that some longer-term reliability concerns should be exempted from the RFP process and assigned to incumbent transmission owners. He said that an “overreliance on competitive RFPs” could incentivize greenfield projects over upgrades of existing infrastructure, reduce flexibility in the solutions selected and “increase risk of duplicative transmission investment,” such as overlap between the longer-term process and asset condition projects.

The proposed exemptions would be focused on “needs that can be addressed cost-effectively by upgrades to existing facilities or by maximizing use of existing properties/[rights of way].” 

In Eversource’s proposal, ISO-NE could identify exemptions for “qualifying low-impact projects.” This definition would extend to upgrades or replacements of aging equipment, new infrastructure sited largely on existing rights of way and the deployment of grid-enhancing technologies. 

ISO-NE initially floated the possibility that some reliability projects could be assigned to incumbent transmission owners but said at the November TC meeting that it would abandon this aspect of the proposal. The RTO said it received mixed feedback from stakeholders on assigning needs to incumbents and was concerned the development of these RFP exemptions would delay the overall longer-term transmission planning effort. 

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CAISO Wins (Nearly) Sweeping FERC Approval for EDAM

CAISO marked a key milestone in its Western expansion efforts Dec. 20 after FERC approved nearly every aspect of its proposed Extended Day-Ahead Market (EDAM). 

The commission’s 181-page ruling rejected only one provision in the extensive proposal: a temporary measure designed to ensure interim compensation for any transmission providers that suffer financial losses during their transition into the new market (ER23-2686). 

“CAISO’s proposal to improve the performance of its existing day-ahead market with new products, and to offer balancing authority areas outside CAISO’s current footprint the opportunity to participate in and benefit from a new day-ahead market, will create significant savings for consumers in Western states,” FERC Chair Willie Phillips wrote in a concurring opinion. 

The ISO filed the EDAM proposal in August, not long after SPP began making significant inroads in the West with its own Markets+ day-ahead offering, setting the stage for a competition that could see the region divided into two different markets in the coming years. (See CAISO Files EDAM Proposal with FERC and Regulators Propose New Independent Western RTO.) 

EDAM, an extension of CAISO’s real-time Western Energy Imbalance Market (WEIM), is the product of a nearly five-year initiative by the ISO and Western electricity sector stakeholders. The ISO paused the effort for a year after persistent heat waves in August and September 2020 caused rolling blackouts in California and strained grid conditions in the wider West. (See CAISO Promotes EDAM Effort in Forum.) 

FERC’s relatively clean ruling signaled a solid endorsement of those efforts.  

“Yesterday, we accepted CAISO’s extended day-ahead market (EDAM) proposal and the accompanying improvements to its day-ahead market,” FERC Commissioner Allison Clements posted on X (formerly known as Twitter) on Dec. 21. “I am excited by the continued developments in the West and am happy to support today’s [sic] order.” 

CAISO CEO Elliot Mainzer said in a statement that he was “deeply appreciative of FERC’s decision and grateful for all the hard work that got us to this important milestone. As we turn the corner into 2024, we are excited to keep our momentum on implementation and to immediately begin working with stakeholders to address the one area FERC has asked for additional information for its consideration.” 

Andrew Campbell, chair of the WEIM’s Governing Body, hailed the approval as “a landmark moment for cooperation in the West.” 

“EDAM builds on the success of the WEIM real-time market by allowing participants to lower costs, reduce environmental impacts and improve reliability during the critical day-ahead planning period,” Campbell said. “With this market, the West will also be more resilient to unexpected changes in weather and other grid conditions.” 

DAME Products

CAISO’s proposal consisted of two broad sections: one outlining a set of Day-Ahead Market Enhancements (DAME) intended to better align day-ahead market outcomes with real-time conditions, and the other comprising measures needed to implement the EDAM itself. 

The DAME provisions create two new products designed to reduce “load imbalances” between the day-ahead and real-time markets. Resources with awards for either product will have to provide economic energy bids for the full range of their awards. 

The first product category consists of “imbalance reserves,” a “flexible reserve product” the ISO will procure “up” or “down” in the day-ahead market to reduce uncertainty between the day-ahead and real-time net load forecasts and deal with real-time ramping needs not addressed by hourly day-ahead market schedules. 

In approving the introduction of imbalance reserves, the commission said the product represents a “reasonable approach to help CAISO address new system needs brought on by the changing resource mix, such as large differences between CAISO’s day-ahead net load forecast and real-time system needs.” It said it was not persuaded by protests from NV Energy and the Western Power Trading Forum (WPTF) that imbalance reserves would be over-procured or “adversely affect the procurement of other ancillary services.” 

The commission also set aside concerns by WPTF and others in agreeing with CAISO that imbalance reserves should be procured on a nodal — rather than zonal — basis to avoid the potential for the reserves to be undeliverable to transmission-constrained areas. 

“Although the cost of procuring imbalance reserves nodally could be higher than if they were procured zonally, this does not render CAISO’s proposal to use nodal procurement unjust and unreasonable. Nodal procurement of imbalance reserves is intended to increase the probability that the capacity will be deliverable in real time,” FERC wrote. 

The commission additionally approved CAISO’s proposed $55/MWh offer cap for imbalance reserves, saying it agreed with the ISO and its Department of Market Monitoring “that it is appropriate to impose market power mitigation on imbalance reserves offers to address market power concerns and ensure competitive market outcomes.” 

The second new product category proposed under the DAME provisions is a “reliability capacity” product to be implemented into the ISO’s residual unit commitment process, a day-ahead process designed to ensure enough resources are committed to meet real-time needs. Under CAISO’s plan, reliability capacity will also be procured on an “up” or “down” basis “to meet positive or negative differences between cleared physical supply in [the ISO’s Integrated Forward Market] and the load forecast,” FERC explained. 

“We find that the proposal will aid CAISO in reducing the need for out-of-market operator actions, thus improving the transparency of market prices,” the commission said in approving the product proposal, which elicited no protests. 

Participation Model OK’d

FERC also largely approved the ISO’s participation model and implementation provisions for EDAM. 

Just as with the WEIM, participation in the EDAM will occur at the balancing authority area level rather than at the level of individual utilities. 

“Similar to participation in the WEIM, EDAM participation is voluntary, and an EDAM entity has flexibility in determining how much of its resource’s capacity it is willing to offer into the day-ahead market,” the commission wrote. “We agree with CAISO that WEIM entities (i.e., balancing authorities participating in the WEIM) are the appropriate participants in EDAM because in many cases, the EDAM entity will be the only or most significant transmission service provider in a BAA.” 

The commission disagreed with the contention by Tri-State Generation and Transmission Association that roles within EDAM require further clarification. 

“Although Tri-State argues that resources operating within an EDAM entity should not be forced to participate in EDAM, the commission’s obligation is to determine whether CAISO’s proposal is just and reasonable, and not whether it is superior to alternatives. Further, to the extent Tri-State’s arguments criticize the WEIM participation framework, we find that such arguments are outside the scope of the EDAM proposal,” FERC wrote. 

The commission also deflected Bonneville Power Administration’s request that FERC emphasize the need for CAISO to develop a strategy for addressing market-to-market seams and acknowledge that entities such as BPA may require special provisions in agreement with the ISO with respect to EDAM and that such agreements should be required before the market can go live. 

The commission said that request fell outside the scope of the proceeded and noted “that CAISO has agreed to work with Bonneville to revise the Coordinated Transmission Agreement as necessary to facilitate Bonneville’s participation in EDAM.” 

The commission also approved EDAM provisions related to external resource participation; market design, market settlement and accounting, congestion and transfer revenue, market power mitigation, market monitoring, and governance. On the issue of governance, FERC dismissed concerns by BPA and Powerex regarding the lack of independence of the CAISO Board of Governors, the members of which are appointed by the governor of California. Powerex additionally contended that the ISO stakeholder process is biased in favor of California interests. 

“We note that CAISO’s proposed EDAM governance structure is consistent with the existing WEIM governance, which the commission previously concluded is just and reasonable,” FERC wrote. 

Access Charge Denied

The only portion of the EDAM proposal rejected by FERC was a provision that would have allowed transmission owners to recover shortfalls in short-term or non-firm transmission revenues that they could attribute to the transition of their assets into the market. 

CAISO proposed the “EDAM access charge” as a temporary measure to smooth adoption of the day-ahead market. It would have allowed TOs to recover three different components of lost transmission revenues: 

    • The difference between historical short-term revenues that would have been earned without joining EDAM and the actual amount earned; 
    • Eligible network upgrade costs for projects that increase transfer capability between EDAM BAAs; and 
    • Revenue shortfalls stemming from EDAM wheel-throughs in excess of an EDAM TO’s net transfers, represented by imports and exports. 

But in proposing the provision, CAISO also said the access charge was “severable” from the rest of the EDAM plan, arguing that rejection of the mechanism should not hinder passage of the broader proposal. 

FERC rejected the access charge despite a lack of protests from stakeholders, finding that CAISO had failed to justify its reason behind the three components. In her post on X, Clements emphasized the rejection was made “without prejudice.” 

“While yesterday’s order rejects CAISO’s proposed EDAM access charge, it does so without prejudice to a future filing in which CAISO provides additional support for the proposal,” she wrote. “I encourage CAISO to work with its stakeholders to timely submit a new proposal with sufficient support for consideration by the commission.” 

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Analysis Shows No Contamination from NY BESS Fires

A state review has found no sign so far of environmental damage or health risks from three battery energy storage fires in New York in mid-2023. 

State officials said Dec. 21 that analyses of air, soil and water data collected in the days after the fires do not show harmful levels of toxic substances or significant off-site migration of contaminants. No injuries were reported, they said. 

Gov. Kathy Hochul (D) in late July convened a fire safety working group to reduce the likelihood of fires in utility-scale battery energy storage systems (BESS) and ensure the safety of emergency personnel who respond to BESS fires.  

Thursday’s report is the first announced result of that effort. On-site assessments of BESS facilities and reviews of fire codes will continue into early to mid-2024. Fire code recommendations are expected to be released for comment in the first quarter. 

The task force was created after three BESS fires within two months in three different parts of the state. Lithium-ion battery fires are difficult to extinguish and can emit toxic smoke. 

There were no known injuries in the three BESS fires, but they came as battery fires were taking a terrible toll in New York City. Seventeen people have been killed and 124 injured in 239 blazes this year through Nov. 15. 

The New York City fires are being caused by micromobility batteries, which are entirely different from grid-scale batteries. But both use lithium-ion technology, and they are sometimes conflated in the public mind. (See Battery Storage Developers Bump Against Perception of Risk.) 

In the wake of this, numerous municipalities statewide have proposed or enacted BESS moratoria in 2023. 

Meanwhile, the state Public Service Commission is in the late stages of reviewing a proposed expansion of the state’s Energy Storage Roadmap from 3 GW to 6 GW installed by 2030. Many more gigawatts of capacity will be needed in the 2030s to supplement intermittent renewables. 

The New York Power Authority’s new battery energy storage system near Chateaugay, N.Y., is shown in May 2023. | NYPA

With storage forming an indispensable part of New York’s clean energy strategy, a large-picture review of safety practices became a pressing need.  

“As we continue to advance New York’s clean energy transition, maintaining this safety is of the utmost importance,” Hochul said Thursday as she announced the first results of that review. “Thankfully, the Working Group’s analysis shows no notable lasting impacts on the health or safety of the first responders or the communities they serve.” 

Hundreds of pages of data shared with NetZero Insider show an extensive array of tests performed at the three fire sites, with variations due to circumstances of the fires and conditions at the sites.  

For example, groundwater sampling was not performed at the site of the first fire, in East Hampton, because there was no sign of soil contamination by lithium or any of the other 25 metals that were targeted in testing. 

Groundwater also was not tested at the site of the second fire, in Warwick, because no water was used in firefighting efforts. But the nearby school district performed surface sampling in buses and facilities, and that came back negative. 

Testing is not complete at the site of the third fire, a 22.5-MW solar-storage facility in Chaumont.  

This fire drew the largest state response, with spill response teams, advisors, environmental law enforcement personnel, infrared-capable drones and air quality monitors sent to the rural area near the Canadian border. 

Over five days, large volumes of water were pumped onto the fire and adjacent equipment, leading neighbors to worry about their wells.  

The initial round of testing in 11 wells used for drinking water came back negative for fire contaminants. Results are expected in early January for tests on follow-up samples collected in early December. Collection of soil samples has been delayed until the damaged equipment is removed from the site. 

Air testing during the fires showed low levels of certain toxic substances.  

Carbon monoxide and hydrogen cyanide were present within a meter of the burning battery containers in Warwick but not outside the fence line. At the Chaumont fire, trace amounts of carbon monoxide and volatile organic compounds were detected. 

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EPA, FERC Hear from Stakeholders on Reliability

Both EPA and FERC received comments Dec. 20 on how reliability can be maintained under the former’s power plant rule that requires fossil fuel-fired units to curtail their emissions. (See New EPA Standards Designed to not Jeopardize Grid Reliability.)

EPA took comments on a supplemental request it issued in November seeking additional input on how to ensure reliability under its proposal. FERC took comments on its annual reliability technical conference, which featured testimony from EPA and others on the rule. (See FERC Dives into Reliability Implications of EPA’s Power Plant Rule.)

The two leading Republicans on the agencies’ oversight committees, Sen. John Barrasso (R-Wyo.) of the Energy and Natural Resources Committee and Sen. Shelley Moore Capito (R-W.Va.) of the Environment and Public Works Committee, filed a letter that expressed their continued doubts about the power plant’s feasibility.

“We urge the EPA to rescind its Clean Power Plan 2.0 proposal and make affordability, reliability and the limits of its authorities under the Clean Air Act cornerstones of any future proposal,” the two senators said. “The more time that has passed since the proposal, the more issues with the Clean Power Plan 2.0 have been uncovered. The proposal is beyond repair and must be withdrawn.”

The senators had also reached out to all four FERC commissioners for their thoughts on the rule and its impact on reliability, and those responses were filed with EPA. Both of the Democratic appointees indicated they are taking reliability seriously but did not bash the proposal like their Republican colleagues.

“The most significant threat to resource adequacy does not stem from a particular rule of any agency but rather from an energy system that was not built for the combination of challenges we face today, including extreme weather and a corresponding increase in unplanned outages, a changing resource mix, rising demand and more,” Commissioner Allison Clements (D) said in her response.

Commissioner Mark Christie (R) repeated his assertion from his testimony before the Energy Committee this year that the country was headed for a reliability crisis. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.)

“It is clear that the wave of retirements of dispatchable [electric generating units], especially coal but also gas — which is already happening at an unsustainable pace — will be intensified if Rule 2.0 ever goes into effect,” Christie said. “Even the threat of the pending Rule 2.0 is exacerbating the pace of retirements and having a chilling effect on the planning of new EGUs, because of its negative effect on the ability of existing dispatchable EGUs to obtain financing and its effect on state-level integrated resource plans.”

The Electric Power Supply Association’s members own 150,000 MW of those EGUs; it told EPA it was disappointed the agency did not reach out to those generation owners whose units will be directly impacted by the rule.

EPSA argued the hurdles to a nationwide buildout of the infrastructure needed to implement the “best system of emissions reduction” proposed — carbon capture and storage, or hydrogen — make the rule infeasible. It said that would need to be tackled in any “permitting reform” efforts.

“One need not look further for evidence of this view than recent announcements from two carbon pipeline developers (Navigator CO2 and Wolf Carbon Solutions U.S.) that they have canceled or temporarily withdrawn applications for major carbon pipeline investments citing the ‘unpredictable’ or ‘stringent’ nature of the regulatory process,” the trade group said.

On top of the need for additional infrastructure, retrofitting thousands of turbines will require a substantial supply chain of physical materials.

“The CCS/hydrogen industry will be built from scratch, requiring years to develop the supply chain for both the manufacturing of materials and a transportation network to deliver them,” EPSA said. “Even if physical materials are available, a trained, skilled workforce with the requisite knowledge to successfully install these upgrades doesn’t exist.”

EPSA also seconded Christie’s concerns about being able to finance the needed upgrades, noting the Inflation Reduction Act’s 45Q tax credit for carbon capture requires construction to start by the end of 2032, years before several compliance deadlines proposed by EPA.

The Edison Electric Institute told FERC that its investor-owned utility members are already in the middle of a long-term transformation in how electricity is generated, and they are committed to continuing that as fast as they can, while keeping reliability and affordability “front and center.”

The sector’s emissions were already at 1984’s levels as of the end of 2022 because of the growth in renewables, efficiency and demand-side resources, and a significant portion of the coal-fired fleet has been replaced by green energy and natural gas. EEI agrees with the long-term clean energy vision embodied in EPA’s proposal.

“With respect to reliability and in the development of such tools, EPA should be focused on compliance flexibility,” EEI said. “Compliance flexibility can help to limit the need for the use of any reliability mechanism, as well as the impact of extreme reliability events, by providing states and units with additional regulatory pathways and tools for compliance.”

Key compliance flexibilities include using mass-based approaches, annual and multiyear averaging, allowing states to recognize how plants will be operated in the future and the emissions benefits of retiring exiting units through appropriate subcategories. EPA’s subcategories give grid planners, and others in charge of reliability, concrete information on when specific units are going to retire, allowing them to be replaced in an orderly fashion.

However, when reliability issues cannot be addressed with those tools, EPA needs to have a mechanism available so generators can stay in compliance with the rule and reliability standards. While the subcategories give an idea of when units will retire, whether their closure will lead to reliability risks will not be known until later on, and that could require an additional mechanism to preserve reliability, EEI said.

It argued that EPA needs a mechanism that would allow for units needed for resource adequacy to stay open — more urgent emergencies can be covered under the Federal Power Act’s Section 202(c), which allows the Department of Energy to issue an order keeping plants running without being liable for violations of environmental regulations.

“The reliability challenges might require resources to increase their generation above forecasted levels or to delay a planned retirement until other assets (including transmission assets) are brought into service,” EEI said. “These scenarios often are time limited but may extend beyond the 90-day window envisioned by FPA 202(c).”

The Clean Air Task Force and Natural Resources Defense Council filed joint comments, agreeing with EEI that the industry is already changing significantly under business-as-usual regardless of EPA’s rule.

“Existing trends away from the most polluting plants, reinforced by the IRA incentives, mean that the most stringent performance standards under this rule will apply to a small portion of the fleet,” they said. “Experience demonstrates that transitions to a cleaner grid can be achieved reliably.”

EPA’s proposal is only modestly incremental to those changes that are already baked in, and it is designed to accommodate reliability while cutting emissions, the groups said.

“It is imperative for EPA to issue standards as required by the Clean Air Act to protect public health and the environment, to secure and extend the emission reductions expected from current trends and incentives,” they said. “EPA has a long history of fulfilling its environmental statutory mandate in the context of an evolving power sector without jeopardizing reliability. In fact, the extreme weather caused by climate change has been a major factor in many reliability events in recent years, in which fossil sources frequently proved to be the least effective at addressing shortfalls in electricity supply.”

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Western RTO Initiative Outlines Governance Options

Members of the West-Wide Governance Pathway Initiative working to establish a single Western RTO last week heard summaries of five potential options for creating a new governing body that could be independent of CAISO.  

Members of the initiative’s Launch Committee emphasized that the options are not formal proposals or recommendations, but rather should be used to further discussion.  

The group is seeking input on whether each option is independent, what the benefits and costs are, and whether it offers what California Community Choice Association’s Evelyn Kahl says could be the most important factor — equitable representation across the West. 

“That’s been an issue to date and it’s certainly something we’re looking to solve,” said Kahl, CalCCA’s general counsel and director of policy, at the Dec. 15 meeting.  

The launch committee hopes to address a host of other questions in the consideration of each option, including if the proposed governance structure facilitates growth of market services, allows participants autonomy to choose from those services and allows balancing authority areas to maintain independence.  

Spencer Gray, executive director of the Northwest and Intermountain Power Producers Coalition, said the committee spent the last few months scoping out governance structures.  

Five Governance Options

The five options offer varying degrees of independence from CAISO on a continuum between two “bookends”: the status quo and what it called “an abrupt full transition to an RTO.”  

The current rules, all under CAISO’s tariff, give the WEIM governing body shared voting authority with the CAISO board, but CAISO holds a limited veto, with the right to file proposed market rules with FERC under Federal Power Act Section 205.  

“Option 0” would continue the CAISO board’s and WEIM Governing Body’s shared authority over market rules but eliminate CAISO’s veto rights, requiring the filing of both proposals if the ISO and WEIM differ. Other examples of such a dual filing mechanism include the “jump ball” provision between ISO-NE and the New England Power Pool, and 205 filing rights held by the Regional State Committee of SPP and the Organization of MISO States over transmission cost allocation. 

The four remaining options require the creation of a new corporate entity, referred to in the Initial Evaluation Framework as a regional organization (RO).  

Option one is “the least amount of change possible to incrementally increase the autonomy of the EIM Governing Body,” according to Gray. It would place governance explicitly under the structure of the new RO, which would have primary voting rights and shared filing rights with CAISO, meaning they could file competing proposals.  

Option two, although still under the CAISO tariff, gives the RO sole authority over market rules and eliminates CAISO’s filing and voting rights. 

Option three starts to “pull apart the tariff,” according to Gray. In addition to having sole authority over market rules, voting and filing, the RO would establish its own tariff, while contracting with CAISO to operate its markets and services. CAISO also would maintain responsibility for balancing authority area operations, transmission planning and generator interconnection procedures. Gray raised the concern that this model could require duplication of interrelated tariff provisions for the RO and CAISO.  

Under the final option, rather than contracting CAISO for services, the RO would absorb CAISO staff and operate the markets and services itself.  

Gray said the committee rejected consideration of the “abrupt RTO transition” bookend following the failure of legislative efforts to transform CAISO into a multistate RTO independent of California.  

“We’ve tried to absorb more seriously the lessons of the recent legislative effort for an abrupt transition to a full RTO from the CAISO,” Gray said. “It doesn’t leave California and the CAISO balancing authority the kind of decision of whether to join the new regional organization that other balancing authorities outside of California … would be able to exercise or enjoy. So, we’re trying to think through as a Launch Committee the options that we’ve scoped and if they preserve that option both within California and outside.”  

The committee is planning to hire legal counsel to provide advice on potential legal barriers associated with the options. Key questions include, “does the option we’re considering require California legislative action, and if it does, what’s the scope of the action?” said Kahl. But the first question they’ll consider is whether the options they’re considering are consistent with existing FERC orders and regulations.  

Stakeholder Feedback

There was wide approval of the overall process among stakeholders.  

“This is really giving us the best and clearest path to markets to maximize value to the ratepayers,” said Conner Reiten, vice president of government affairs with PNGC Power. “We’re really encouraged by the quick pace that this is coming together … but I think what’s clear and what we’re finding is that there is a really new, really good opportunity for a single West-wide market to come into place.” 

Marc Joseph, the Launch Committee’s labor representative, echoed Gray’s concerns about the bookend option. He said he opposed the legislative effort to transform CAISO into a regional organization because it would have resulted in exporting thousands of the jobs required to build new generation and transmission outside of California.  

“We’re supporting the Pathways Initiative because the options that are under consideration could create cost savings and increase reliability without exporting California jobs,” he said.  

California Public Utilities Commission President Alice Reynolds also showed support.  

“California is very engaged in this effort and thinking about the West-wide benefits for reliability and for customers,” she said. “I just wanted to emphasize how important that is to California and how interested we are in increasing cooperation among Western states.”