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November 15, 2024

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4 Things Cathy Zoi Learned About the Car-charging Business as Head of EVgo

When Cathy Zoi joined charging company EVgo as its CEO in 2017, only a couple of electric vehicle models were for sale, and their range was limited to about 70 miles.

Founded in 2010 as a unit of NRG Energy, EVgo had only 50 employees and no revenue model. By the time Zoi retired from the company in November, it had about 300 employees, and more than 40 EV models were for sale in the U.S., many with a range over 300 miles. Although EVgo, now owned by LS Power, has yet to earn a profit, Zoi is bullish on the industry’s future.

“Now, there’s not a car company that is not investing significantly in electrifying its offerings — to the tune of a trillion dollars globally,” she said in an interview with Resources for the Future CEO Richard G. Newell on Nov. 29 as part of its Policy Leadership Series of webinars. “That is a once-in-a-century transformation of a major sector that is happening present tense. … I did not anticipate that amount of commitment by private capital would happen so quickly. And that’s really, really heartening.”

The industry’s biggest challenge now is creating the charging infrastructure needed to make new converts confident they won’t get stranded without power, Zoi said. “What is probably underestimated by everybody was the complexity of building a new ecosystem,” she said.

Zoi told Newell and an audience in D.C. she is unfazed by reports of automakers pulling back on their EV plans.

Former EVgo CEO Cathy Zoi spoke with Resources for the Future CEO Richard G. Newell during a webinar Nov. 29. | Resources for the Future

“I think it’s an ephemeral thing,” she said. “If they’re pulling back, they’re pulling back from a slope that was like this,” she said, pointing steeply upward, “to a slope that was like that” — less steep. “It’s still very, very fast compound annual growth rates. You know, maybe the new model was going to come out in Q1 next year, [and] it’s going to come out in Q3 instead.”

Nor is she concerned that a Republican president or Congress will seek to halt EVs’ growth, saying elected officials will not want to lose the jobs resulting from the EV and battery factories that have been announced since the Inflation Reduction Act and Infrastructure Investment and Jobs Act.

“There were elected members of office in this town that might have been hostile to clean energy because it’s environmental. And yet, their constituents — the farmers of Iowa — are making more money out of having wind turbines on their property than they are out of the corn they’re selling and the soybeans they are growing,” she said.

“On the consumer side, I have not talked to a driver who has experienced an EV and doesn’t adore it,” she continued. “And this is why you’ve got the market growing in Texas, in Florida, as quickly as it is. They are really great products. They’re fun to drive; it’s a better-performing technology. And you know, people say, ‘I love not having to go to a gas station anymore.’”

Reality check: While EVs have fewer moving parts than internal combustion engine (ICE) vehicles, and thus should need fewer repairs, Consumer Reports says EV owners continue to report far more problems than owners of conventional cars or hybrids. Many drivers of EVs other than Teslas have complained about nonworking chargers. S&P Global Mobility says half of EV owners — excluding those with Teslas — go back to ICE vehicles as either a replacement car or a second vehicle for their household.

Scaling Up

Zoi is optimistic the industry can meet the Biden administration’s target of making EVs half of new car sales by 2030.

The U.S., which has 30,000 fast chargers, will need 200,000 to 300,000 by 2030, she said.

EVgo — which has 3,400 DC fast-charging stalls in operation or under construction at more than 950 locations nationwide — has identified about 10,000 sites for additional chargers, assuming available capital.

“So I can tell you on the charging side, we’re up to the task. … But as I mentioned, it’s a whole ecosystem,” she said. That means utilities must upgrade distribution grids, and carmakers must transform from ICE vehicles to EVs. “So it’s ambitious, but achievable.”

Below are four things Zoi learned in her time at EVgo, with implications for the industry:

  1. People like to top off at the store even if they have home chargers.

The demand for DC fast chargers has grown faster than expected, Zoi said.

“We thought the whole idea was if you can charge at home, you’re only going to charge at home. Turns out that’s not the case. If you have a charging station conveniently located at your grocery store, people are topping up there. It’s a good parking space. [They will] spend five bucks while they’re going to get their weekly groceries.”

Another factor: “The … EVs that are being sold, [their] batteries are bigger, and they’re heavier. And so they’re a little less efficient … than we originally forecast, which means that the folks need to fill up more frequently.”

EVgo’s national use rate — the percent of time a charger is in use — is more than 15%, with some stations, such as one in Brooklyn, in use more than 50% of the time.

  1. Only some customers are price responsive.

The company has seen a wide range of price elasticity as it has adopted time-of-use pricing.

“Some of our drivers are very price responsive, like our rideshare drivers. Others do not care at all,” she said.

After joining the company, Zoi imposed a rule that it should make a profit on every kilowatt-hour dispensed, which required it to abandon its single national price.

“In order to not lose money in San Diego … we had to double our rates,” she said. “And the demand dipped a little bit for a couple of weeks, and then it went right back up.”

The average out-of-pocket spend per charging session is about $10, not including monthly subscription fees of up to $13. “So it’s two Starbucks things, right? It’s just not that much money. And you come out and you’ve got electrons in your car, and off you go, and you feel great.”

  1. It takes a long time to plug into utility distribution lines.

It takes between six and 18 months from site identification to having the station go live, Zoi said, far from hopes of a six-month turnaround.

“Because we’d like to build stations with at least 10 stalls, now it almost always requires a service upgrade, which means that the utilities buy a transformer … and the site host has to allow the utility access to the site. … It turns out that landlords — we don’t own the land — don’t like utilities tromping on their [property]. And then at the back end, in order for a station to go live, the utility has to come and do the final inspection before we enter. And we are often in the queue for something like six, eight, 12 weeks until they show up.”

EVgo is trying to shorten the timeline by providing utilities with its siting plans for the next 18 to 24 months. “We say this is where we’d like to build … and sometimes they say, ‘Oh my gosh, don’t build here, because we’re really constrained,’ or ‘We’re not going to upgrade that local connector until 2027.’ But they usually say, ‘Great. Now we’ll order transformers for all these locations.’

“As we get into larger, heavy-duty trucks being electrified, those are going to be megawatt[-scale] charging stations that need to be integrated into utility plans — like in a big way.”

  1. Chevron needs to improve its menu.

The biggest share of EVgo’s $35.1 million in revenue in the third quarter — up 234% year-over-year — was from retail chargers. It has partnerships with shopping center owners; Target; Chase Bank; Lowe’s; supermarkets Kroger, Safeway and ShopRite; and convenience store chains Sheetz and Wawa.

“We like to build where people are anyway. … So you can just plug in, go do something else and come back, and the car’s charged,” Zoi said.

It is also building depots with 20 or 30 stalls for fleet customers. And on highways, it has a partnership with Pilot Flying J truck stops for “white label” chargers owned by Flying J and built and maintained by EVgo.

And it’s experimenting with gas stations through 14 Chevron locations in California.

“I always used to joke with them … ‘You guys are going to need to improve the quality of your coffee if you’re going to get people to want to stay. Because we also partner with Whole Foods. And would you rather [hang] at Whole Foods, or [eat] beef jerky at Chevron?’”

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OPSI Urges Reliability Coordination Between PJM, States

PJM is taking a reactive stance in addressing the evolving grid, impacting ratepayers and reliability in a way that could be addressed by closer coordination with member states, the Organization of PJM States Inc. (OPSI) has told the RTO’s Board of Managers. 

OPSI leveled its contention in a Nov. 28 letter that said increases in both load and generation retirements are leading to reliability risks that require major “immediate need” transmission expansions with little time for exploration of alternatives.  

The group said the $5 billion Regional Transmission Expansion Plan (RTEP) project PJM presented its Transmission Expansion Advisory Committee (TEAC) on Oct. 31 highlights the “negative impact of siloed, reactive planning” that states have been concerned about for years. The TEAC is scheduled to discuss the proposal again on Nov. 5, and the board may consider approval in the coming weeks. (See PJM Recommends $5B in RTEP Transmission Projects.) 

“The reliability challenges that have recently presented themselves, coupled with the significant cost impact on customers associated with addressing these challenges, have amplified our concern that factors outside the transmission planning process may contribute to the high cost of transmission upgrades and warrant attention to ensure these costs do not become an undue burden to retail consumers,” the letter said. “As such, the OPSI board requests your support in working hand-in-hand, with the help of our respective staffs, to better understand the issues and explore solutions, tools and reforms that may more timely and cost effectively ensure grid reliability.” 

In addition to its concerns with the transmission planning process, OPSI said the need for reliability-must-run (RMR) contracts to keep generators online past their deactivation date threatens to saddle ratepayers with a second round of expenses on top of transmission needed to accommodate the retirement. 

“These concerns range from transmission projects designated as ‘immediate need,’ even though many of them have remained uncompleted past their required in-service dates, to multiyear reliability-must-run agreements that can cost customers hundreds of millions of dollars per year, all while the region waits for even costlier transmission upgrades,” OPSI wrote. “What’s more, the costs of these RMR agreements are not factored in selecting the most overall cost-effective reliability solutions. As such, the PJM board should not read this letter as a reaction to a single set of RTEP projects, but rather a culmination of concerns that is only growing and that has resulted in our resolve to timely seek solutions through our boards working together.” 

The letter was signed by 13 of the 14 OPSI member commissions, with only the Virginia State Corporation Commission voting in opposition. The Virginia agency did not respond to a request for comment on the letter. 

The letter notes that PJM has undertaken efforts to address the reliability concerns it has identified over the past year, including an overhaul of the capacity market through the critical issue fast path process and a long-term transmission planning working group, but OPSI said more work is needed to explore holistic solutions to grid reliability. 

‘Eye-popping’ Transmission Needs

Maryland Public Service Commissioner Michael Richard, who also serves as OPSI treasurer, said state policies have a central role to play in promoting the clean energy transition while maintaining reliability in the most cost-effective manner.  

Richard said if the states were brought on board with planning the response to data center growth in Northern Virginia and the retirement of the Brandon Shores generator outside Baltimore, both of which contributed to the $5 billion RTEP project, recent Maryland legislation requiring the development of 3 GW of storage could have provided a non-transmission solution at a lower cost for ratepayers. (See Maryland Legislature Ends Session with Big Wins for Clean Energy.) 

“There are things that we can do at the state level, at the distribution level, to help address and take action regarding demand and some of the distributed energy resources that we’re working to bring on,” he said. “We have a lot of storage projects in the queue and if we just had more visibility into where the reliability concerns are, it’s very possible we could tap some of those storage resources to address some of the concerns PJM has.” 

While Richard said the scale of the transmission PJM has proposed was “eye-popping,” he thinks it reflects longstanding issues the states have had with PJM’s planning processes. He said the move to a cluster approach to studying generator interconnection requests marks a significant improvement, but work remains to improve PJM’s governance and create opportunities for collaboration with the states. 

“We do have good dialogue between OPSI and PJM and the states. I think we have good discussions, so I’m hopeful and again this letter is presented as an invitation, a request to work collaboratively with PJM. I know they tell us they take OPSI dialogue very seriously and so I expect they will do so with this letter,” he said. 

Morris Schreim, senior advisor to the Maryland Public Service Commission, said transmission is looked at as the last solution for meeting demand when the market signals don’t produce an adequate supply of generation. He said PJM should be seeking innovative ways to improve the interconnection process to ensure new resources aren’t held up, consider how federal policy around electrification and generation development can be incorporated, and work with states to find solutions on the distribution side of the grid. He said the discussions in PJM’s Deactivation Enhancements Senior Task Force to streamline the process for transferring capacity interconnection rights (CIRs) from a retiring resource to a replacement is a promising pathway. 

“They have an opportunity to come up with creative and innovative ways of making the parts work together,” he said. 

Kentucky Public Service Commissioner Kent Chandler, who also serves as OPSI president, said he hopes the letter can open avenues for his commission to work closer with PJM to find new ways of maximizing reliability at lower costs. 

“My overarching concern is that the PJM region is engaging in too much reactive engineering, and are just calling it planning,” Chandler said in an email. “At the same time, the region is too siloed at addressing needs, such as the chasm between supplemental and baseline planning. Customers can’t afford siloed, reactionary investments in the [bulk electric system], and doing so likely results in a more expensive and less reliable system. I look forward to working with PJM on how we can address this.” 

‘A Real Frustration’

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said there’s widespread agreement among advocates on many of the issues raised in the letter. He said the advocates are concerned about the “extremely significant” costs ratepayers will face should the RTEP projects be approved and are frustrated with the short timeline between when PJM selects projects and seeks board approval. 

“There’s not many things that happen in such a short time period as this $5 billion project with this little input from stakeholders,” Poulos said. 

One of the chief reasons generator retirements such as Brandon Shores require extensive transmission development is the compressed Base Residual Auction schedule, which causes generators to receive the price signals to retire much closer to the start of the delivery year, Poulos said.  

PJM’s markets were designed to have generators seek deactivation three years in advance, but when that period is shortened, the amount of time to plan and construct solutions is likewise limited, increasing the odds of needing a costly RMR contract. Poulos anticipates the next major generation retirements also likely will provide little to no warning and come with even larger costs. 

“These decisions about when resources retire, you would think would be made three years and 90 days in advance of auctions. … You’ve cut that time down and put the pressure [on consumers] to address the situations and consumers to pay for situations,” he said. “One of the consequences is having these $5 billion retirement issues that are immediate needs, so we get less competition. It reduces the solutions when these things come on so fast. We need to really be thinking comprehensive long-term planning.” 

Poulos said consumer advocates also are frustrated about the lack of discussions around increasing the scope of PJM’s long-term planning. The Long-Term Regional Transmission Planning Workshop started this year addresses projects only of 345 kV or higher, which Poulos said limits its scope to a small fraction of the projects PJM might consider. 

“That long-term regional process is not aimed at the entire picture of how we go forward and that’s a real frustration,” he said. 

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FERC Approves Texas RE Standards Process Changes

FERC on Dec. 1 approved a set of updates to the Texas Reliability Entity’s Reliability Standards Development Process (RSDP) intended to give more flexibility to the regional entity’s Member Representatives Committee to develop standards and align the document more closely to NERC’s Standard Processes Manual (SPM) (RR23-1).

NERC filed the RSDP changes with FERC in May, after the RE’s Board of Directors approved them at its quarterly meeting in February. (See “Regional Standards Process Approved,” Texas RE Board/MRC Briefs: Feb. 8, 2023.) The RSDP defines the process for adopting, approving, revising and retiring Texas RE’s regional standards, as well as for creating a regional variance to a NERC standard.

The approved changes will affect all 10 sections in the current RSDP to varying degrees, with most of the revisions in the first four sections. These comprise the introduction (Section 1), elements of reliability standards (Section 2), roles in the standard development process (Section 3) and the development process itself (Section 4).

In Section 1, Texas RE will merge the background section of the current RSDP — which “requires regional reliability standards to support one or more of the NERC reliability principles and to be consistent with the NERC market principles” — with the introduction. Additional revisions to this section add principles for standards development and assign the task of determining who may participate in standards development to the RE’s Reliability Standards Manager.

Next, Texas RE will move language from one of the current RSDP’s appendices to Section 2, adding references to NERC’s 10 Benchmarks of an Excellent Reliability Standard and changing terminology to be consistent with the SPM.

New language in Section 3 will specify that the MRC “may undertake reviews of [FERC] orders and coordinate with NERC in the development of NERC’s annual reliability standards development plan.”

Revisions to Section 4 require Texas RE to follow NERC’s evaluation procedure when developing new regional standards, create “distinct process steps” for creating standard authorization requests (SARs) and add a requirement for the MRC to be notified when a SAR is submitted. Public comment periods for SARs have been lengthened from 15 days to 30; comment periods for draft standards were extended from 30 days to 45, with a ballot in the last 15 days; and the MRC will now be required to meet at least once per quarter.

Additional changes to Section 4 include organizational updates removing language requiring standard drafting teams to assess the impact of a SAR on neighboring regions and creating more options for obtaining feedback on draft standards. The revisions also add voting positions, consolidate language and provide flexibility regarding the termination of unsuccessful projects and procedures if a draft standard does not pass industry ballot.

Updates to Sections 5 to 10 provide for regional reliability standards to be “considered for review at least every five years,” instead of requiring a review as is currently the case; list information that SARs must provide to the MRC; give reasons the MRC can reject requests for interpretation of regional standards; update the appeals process; and outline a method for conducting field tests that is consistent with NERC’s SPM.

Public Citizen Opposes Language on Markets

FERC received only one filing opposing the changes, from Public Citizen.

The advocacy group objected to language in the revised RSDP requiring reliability standards to “accommodate competitive electricity markets” on the grounds that market considerations are outside the ERO’s purview. It requested that any references to competitive markets be removed from the document.

In response, NERC defended the language, citing the Federal Power Act’s requirement that FERC “not defer [to the ERO] with respect to the effect of a standard on competition” and the commission’s order that proposed standards should have “no undue negative effect on competition.” NERC also observed that nearly identical language was already in the previous version of the RSDP, albeit in a different section.

FERC said Public Citizen’s request was “outside the scope of the instant proceeding” while echoing NERC’s observation that the proposed revisions “do not substantially differ from” previous versions of the RSDP. As a result, the group’s objections were rejected, and the new RSDP was approved, effective immediately.

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ISO-NE Says Region Has Enough Resources for Upcoming Winter

ISO-NE projects it will have enough energy resources to maintain the grid throughout mild and moderate weather conditions this winter, the organization announced Dec. 4. Under more severe winter conditions, ISO-NE indicates some capacity deficiency actions may be required, but shortfall remains “unlikely.”  

While the RTO said it does not anticipate the need for controlled power outages, it cautioned that even in a mild winter, extended cold snaps still could stress the grid.   

The organization forecasts a peak demand of 20,269 MW under average weather conditions, and a 21,032-MW peak under below-average temperatures. This would be an increase compared to last winter’s 19,529-MW demand peak. ISO-NE anticipates winter peak demand increases will accelerate in the coming years due to electrification, surpassing 26,000 MW in 2032 and potentially reaching about 57,000 MW in 2050.  

For this winter, ISO-NE noted the National Oceanic and Atmospheric Administration projects above-average temperatures in New England, with more precipitation than usual in Southern New England and average precipitation in Northern New England.  

Temperature and weather patterns can impact both supply and demand on the grid, making weather “the largest driver of energy use and resource availability in New England,” according to the RTO. The organization touted its 21-day energy supply forecast, which it uses to anticipate and preempt supply constraints. 

“Seeing what’s coming is crucial to navigating any potential power system challenges, and our 21-day energy supply forecast is an operational tool that serves this very purpose,” ISO-NE CEO Gordon van Welie said in a statement. “It gives us situational awareness on energy adequacy over the operating horizon, allowing us to identify potential energy shortfalls while there’s still time to prevent them or lessen their impact.” 

The RTO has several out-of-market mechanisms in place intended to ensure grid reliability. This winter will feature the rollout of the Inventoried Energy Program (IEP), which will compensate generators for keeping up to three days of stored fuel on-site.  

The IEP is intended to be a short-term reliability solution, set to run for just two winters. It has been criticized by environmental groups as an unnecessary handout to fossil generators, while ISO-NE has argued it is an important reliability backstop for the region. (See FERC Upholds Ruling on ISO-NE’s IEP Payments.) 

This winter also will be the second and final year of the Mystic Cost-of-Service Agreement (COSA), which has delayed the retirement of the Mystic generation station. Mystic is the main customer of the Everett LNG import terminal, and Mystic’s retirement would necessitate a new source of funding to keep the import terminal open. The generator is set to retire when the COSA expires at the end of May 2024, after which the future of Everett is uncertain.  

Officials from FERC, NERC and ISO-NE have expressed concern about the indirect impacts the retirement of Everett would have on electric reliability. (See FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal.) 

However, there is little appetite in the region to extend the Mystic Agreement, which has been characterized by high costs and, according to some stakeholders, minimal grid reliability benefits. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.) 

According to an ISO-NE report released in September, the agreement has cost ratepayers in the region over $572 million from its start in June 2022 through August 2023. Over this period, Mystic’s operational conditions have been characterized by the RTO as “in-merit operation” for just one month, compared to nine months of “tank congestion management” and five months where the facility was characterized as “predominantly offline.” 

ISO-NE’s modeling for 2027 and 2032 has indicated the presence of Everett would not provide significant reliability benefits to the grid. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) 

In the coming years, the region could see several new clean energy resources come online that likely will boost winter reliability. The 806-MW Vineyard Wind 1 project aims to achieve commercial operation by the end of 2024, while the 1,200-MW New England Clean Energy Connect transmission project expects to be in service by 2025. 

In the longer-term, ISO-NE’s ongoing Resource Capacity Accreditation project is intended increase capacity revenues for resources that provide reliability attributes to the grid, particularly during periods of winter stress. Under the RTO’s current schedule, these updates will be implemented in time for the winter of 2028/29. 

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New York Issues Expedited Renewable Energy Solicitations

New York is moving quickly to keep its renewable energy development queue viable, launching solicitations for new onshore and offshore large-scale projects.

This new round is designed to move more quickly than previous New York solicitations, with hopes of restoring momentum to struggling projects and replacing any projects that are withdrawn.

Proposals under the state’s fourth competitive offshore wind solicitation (ORECRFP23-1) are due by Jan. 25, and award announcements are expected in February. Onshore developers have until Dec. 21 to establish eligibility for the seventh annual Renewable Energy Standard solicitation (RESRFP23-1). They must then submit proposals by Jan. 31, with award announcements also anticipated in February.

The Nov. 30 solicitation announcement followed a Public Service Commission decision in mid-October to not increase the reimbursement for several dozen contracted projects totaling more than 12 GW of nameplate capacity.

Developers had said they might not be able to start construction of the projects without more money, and there was speculation the PSC ruling would gut the clean energy portfolio the state is trying so hard to build.

But immediately after the PSC ruling, Gov. Kathy Hochul promised an expedited effort to help blunt its impact. The New York State Energy Research and Development Authority (NYSERDA) followed through with the solicitations for land-based and offshore projects.

The developers who had sought financial relief for projects awarded contracts under previous solicitations will be able to rebid those projects into this new solicitation.

This is key for offshore wind, given the lengthy timeline involved in planning and review of each project — a complete reset could set the state back years as it pursues statutory goals for emissions-free power.

The inflation-index option that was absent from early solicitations will be available to bidders in this latest request for proposals. Also, NYSERDA said it is streamlining the solicitation by removing certain bid requirements that were labor intensive to comply with but provided minimal value to officials evaluating the bids.

Offshore wind is a key component of the clean energy transition, promising gigawatts of emissions-free power.

A few projects are under construction or preparing to start construction in U.S. waters, having locked in their finances before spiraling costs clobbered the industry. But most are struggling with their financials.

New York’s neighbors are in the same position: New Jersey, Connecticut and Massachusetts have seen projects stalled or outright canceled, and a Rhode Island proposal was rejected as too expensive.

But all of the states have pressed forward — the southern New England states, New Jersey and now New York each have issued new solicitations in recent months.

Also, New York in late October announced conditional contract awards for three offshore wind projects totaling 4 GW of capacity.

The renewable energy industry had criticized the PSC for its decision and Hochul for an unrelated veto. But it welcomed the new solicitations.

Fred Zalcman, director of the New York Offshore Wind Alliance, said in a news release: “Actions speak louder than words, and we applaud the Hochul administration for providing, through this expedited RFP, a clear and unambiguous statement of support for offshore wind as an essential part of New York’s evolution towards a carbon-free grid.”

Anne Reynolds, executive director of the Alliance for Clean Energy New York, said: “I applaud New York’s fast action, because this sense of urgency is exactly what is needed to bring infrastructure projects to construction and achieve clean energy and climate goals.”

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COP28: 118 Countries Pledge to Triple Renewables to 11,000 GW by 2030

In the face of a yawning gap in efforts to reduce global greenhouse gas emissions, 118 nations at the 28th United Nations Climate Change Conference of the Parties (COP28) in the United Arab Emirates pledged on Dec. 2 to triple renewable energy capacity and double energy efficiency savings by 2030.

COP28 President Sultan Ahmed al-Jaber announced the Global Renewables and Energy Efficiency Pledge, which will target expansion of global renewable capacity to 11,000 GW by 2030, while also raising the global annual rate for energy efficiency improvements from 2% to 4% per year.

The pledge states that “renewable deployment must be accompanied this decade by … a phasedown of unabated coal power, in particular ending the continued investment in unabated new coal-fired power plants, which is incompatible with efforts to limit warning to 1.5 degrees C.”

The pledge specifically commits nations to “put the principle of energy efficiency as the ‘first fuel’ at the core of policymaking, planning and major investment decisions.”

Countries signing onto the pledge are encouraged to adopt “ambitious national policies on renewable energy,” including accelerating permitting of renewable projects and infrastructure, expanding grid connections and improving energy system integration, and providing clarity on market design and investment frameworks for renewables.

“The world does not work without energy,” al-Jaber said in the COP28 press release on the pledge. “Yet the world will break down if we do not fix [the] energies we use today, mitigate their emissions at a gigaton scale and rapidly transition to zero-carbon alternatives.”

But European Commission President Ursula von der Leyen framed the pledge as a first step toward a fossil fuel phaseout. “With this global pledge, we have built a broad and strong coalition of countries committed to the clean energy transition ― big and small, north and south, heavy emitters, developing nations and small island states,” she said. “We are united by our common belief that to respect the 1.5 degrees C goal in the Paris Agreement, we need to phase out fossil fuels. We do that by fast-tracking the clean energy transition, by tripling renewables and doubling energy efficiency.”

The EU will invest $2.5 billion in the energy transition over the next two years, she said.

Lisa Jacobson, president of the Business Council for Sustainable Energy, hailed the pledge as “a milestone to be celebrated. It signals that the global community is united in its goal to advance the clean energy transition ― and is aware of the enormous level of deployment needed to do so quickly. To reach this goal, the business community has an essential role to play in directing investment and deploying technologies ― in all sectors and all geographies.”

Climate activists were more critical. While welcoming the renewables pledge, Janet Milongo, senior officer at the International Climate Action Network, said it “still falls short of what is required to achieve global climate goals. Prolongation of fossil fuel lifelines is evident. Dangerous distractions like carbon capture and storage have no place in an energy transition plan,” referring to the pledge’s mentions of “unabated coal power.”

The pledge was part of a series of announcements Dec. 2, made under an umbrella initiative, led by al-Jaber and the U.A.E., dubbed the Global Decarbonization Accelerator.

    • The U.A.E.’s Hydrogen Statement of Intent drew support from 27 countries, pledging to “endorse a global certification scheme and to recognize existing certification schemes … to unlock global trade in low-carbon hydrogen.”
    • Fifty companies, representing 40% of global oil production, have signed an Oil and Gas Decarbonization Charter, committing to zero methane emissions and the end of “routine” flaring by 2030 and total net-zero operations by 2050.
    • A Global Cooling Pledge will target a 68% cut in GHG emissions from refrigeration and space cooling technologies by 2050. Space cooling and refrigeration now account for 7% of global emissions but are expected to increase as more nations expand their use of air conditioning. According to the announcement, 52 nations have signed the pledge thus far.

A $1 billion effort to cut methane and other non-carbon greenhouse gas emissions will be announced Dec. 5. A key question now is whether the renewables pledge will be included in the final official agreement from the conference.

‘Urgency of the Moment’

With President Joe Biden deciding not to travel to the U.A.E., the U.S. presence at the COP28 initially was more muted than in the past, starting out with a widely criticized $17.5 million pledge to the new loss and damage fund approved on the first day of the conference.

The U.A.E. pledged $100 million and the EU pledged $245 million for the fund, which is intended to compensate developing countries for damages they already have sustained from extreme weather events made worse by climate change.

Speaking at the conference Dec. 2, Vice President Kamala Harris announced a $3 billion U.S. pledge to the Green Climate Fund, which helps developing countries invest in clean energy and resilience. As part of the Paris climate accords, industrialized countries including the U.S. pledged to raise $100 billion per year for the fund by 2030. The fund hit $89.6 billion in 2021, according to the Organization for Economic Cooperation and Development.

The U.S. also is launching an international Clean Energy Supply Chain initiative to expand and diversify the supply chains critical to the U.S. and global energy transition. Harris said the U.S. is going to provide $568 million for low-cost loans to expand clean energy manufacturing.

“The urgency of this moment is clear,” Harris said, according to a White House release. “We cannot afford to be incremental. We need transformative change and exponential impact. As nations, we must have the ambition that is necessary to meet this moment.”

The U.S. also joined more than 20 other nations in signing the Declaration to Triple Nuclear Energy by 2050, according to an announcement from the Department of Energy. The declaration commits signers to ensuring they operate nuclear facilities responsibly, with “the highest standards of safety, sustainability, security and non-proliferation, and that fuel waste is responsibly managed for the long term,” while mobilizing financing for new plants.

“We are not making the argument to anybody that [nuclear] is absolutely going to be the sweeping alternative to every other energy source — no, that’s not what brings us here,” said Special Presidential Envoy John Kerry, as reported in The New York Times. But, he said, “You can’t get to net-zero 2050 without some nuclear.”

The other major initiative from the U.S. on Dec. 2 was the release of the EPA’s final rule aimed at slashing the nation’s methane emissions 80% between 2024 and 2038..

Announced by EPA Administrator Michael Regan and White House National Climate Advisor Ali Zaidi, the new rule gives oil and gas companies two years to end routine flaring of natural gas from new oil wells and one year to phase in zero emissions standards for key equipment such as pumps and storage tanks. It requires close monitoring for leaks, while also opening the way for oil and gas companies to use new technologies, such as satellite monitoring and aerial surveys, to detect leaks.

The final rules were developed with feedback from nearly 1 million public comments EPA received on proposed regulations issued in 2021 and 2022, according to the agency announcement. Regan said the standards were developed “to advance American innovation and account for the industry’s leadership in accelerating methane technology.”

EPA also plans to enlist “third-party expertise” to find the large leaks, known as “super emitters,” which account for close to half of methane emissions from oil and gas.

Statements in the EPA announcement signaled broad support for the rule from industry and environmental groups.

Orlando Alvarez, chairman and president of bp America, said the final rule was “well designed” and would “help drive material methane emission reductions this decade and beyond.”

Fred Krupp, president of the Environmental Defense Fund, called the rule “a vital win for the climate and public health, dramatically reducing warming pollution and providing vital clean air protections to millions of Americans.”

COP28’s Two Narratives

The wave of new pledges and commitments comes as the conference faces the first Global Stocktake of how well the nations that signed the Paris Agreement in 2015 have lived up to their commitments to reduce their GHG emissions to limit climate change to 1.5 C.

The outlook is not encouraging. The UN’s Emissions Gap report, released prior to the conference, said even if all countries were to meet their commitments, the world still would be headed for 2.5 to 2.9 C of warming by the end of the century.

Adding to the sense of urgency, the World Meteorological Organization rolled out its provisional State of the Climate report on the opening day of the conference, confirming that 2023 has been the hottest year on record, with ongoing increases in GHG emissions, record sea level rise and record low Antarctic sea ice.

Even before the opening of COP28, two narratives had emerged about how the world should respond to the challenges ahead and what official actions the conference might endorse.

The dominant narrative, advanced by al-Jaber, the oil and gas industry and other oil-producing countries, is that, along with more renewables and energy efficiency, new technologies — like carbon capture and storage — can mitigate the worst effects of the ongoing combustion of fossil fuels.

The alternative narrative, advanced by a range of environmental groups and some nations, envisions a global commitment to a full, fair, fast and well-funded phaseout of all fossil fuels. At yet another event Dec. 2, Colombian President Gustavo Petro announced his country would be the 10th to join the call for a fossil fuel nonproliferation treaty.

The first calls for such a treaty came from Pacific Island nations in 2015, according to the initiative’s website, and supporters now include a range of cities and environmental and other nonprofits. Colombia is the second oil-producing country to support the treaty; the first was the Pacific Island nation of Timor-Leste.

Petro acknowledged the paradox of a fossil fuel-dependent country supporting nonproliferation but argued that preventing the “omnicide” of the planet itself must be avoided, as reported in the Guardian. “There is no other formula, no other path. Everything else is an illusion,” he said.

The critical question now is whether any of the pledges and commitments being rolled out in Dubai will find their way into the final conference agreement. Wide support for a fossil fuel phaseout is unlikely, and even official sanction for a phasedown may be difficult or significantly watered down, as has occurred in the past.

Al-Jaber once again fueled controversy Dec. 3 when the Guardian reported that during a pre-COP interview, he said there is “no science out there, or no scenario out there, that says that the phaseout of fossil fuel is what’s going to achieve 1.5 C.”

Responding to those comments, Kerry pivoted the argument, saying the focus for limiting climate change to 1.5 C must be on “a phasing out of unmitigated fossil fuel emissions,” as reported by CNBC.

At a press conference on Dec. 4, al-Jaber said his comments were misrepresented and taken out of context, according to the Guardian.

“I respect science in everything I do,” he said. “I have said over and over the phasedown and the phaseout of fossil fuel is inevitable. In fact, it is essential.”

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Massachusetts Gives Itself Good Grades in Climate Report Card

Massachusetts on Friday issued its first-ever “Climate Report Card,” finding that all of the state’s sectors are “on track” for their 2025 decarbonization targets. 

The inaugural report from Gov. Maura Healey’s (D) administration measured decarbonization efforts in the transportation, buildings, electricity, and natural and working land sectors. The finding is based on some unexpected progress in the deployment of clean energy technologies and the assumption that will continue to accelerate in the coming years. 

But the report also highlighted the challenges to cutting emissions. According to the state’s greenhouse gas inventory, transportation and buildings are the two largest sources of carbon emissions in the state, responsible for 37% and 35%, respectively, of the state’s total emissions.  

The report card noted there were more than 70,000 light-duty electric vehicles in the state in 2022. Massachusetts’ Clean Energy and Climate Plan (CECP) models the state will need 200,000 total EVs by 2025 and 900,000 by 2030. 

The state also has a long way to go on public vehicle charging infrastructure: It has nearly 6,500 charging ports but will need to increase this number to 15,000 by 2025 and 75,000 by 2030, according to the CECP estimates. 

The report cited high interest rates, inflation and supply chain constraints, along with grid capacity limitations, as some of the challenges to rapidly electrifying transportation in the state. Other barriers include EV affordability, access to home chargers and public transportation accessibility. 

For the buildings sector, the report card found heat pump deployment has accelerated in recent years, noting nearly 30,000 heat pumps have been installed through the state’s Mass Save energy efficiency program from the start of 2020 through the first half of 2023. The CECP estimates the state needs to install 100,000 heat pumps between 2020 and 2025, increasing to an average of 100,000 annual installations between 2025 and 2030. 

But the report card noted installations through Mass Save have surpassed expectations, and the state is “at about 30% of [its] 2025 target even before accounting for installations outside of Mass Save such as those done within municipal light plant territories.” 

“Despite these early successes, sharp increases are needed to meet the state’s building sector targets,” the report added. It noted that energy efficiency and demand-control measures are essential to limiting the pressures electrification puts on the grid. 

The report card said Mass Save’s focus on cost savings may need to be reformed to increase the number of customers switching from natural gas heating to heat pumps. It also highlighted the difficulties of building decarbonization for old buildings and rental units, along with the need for a larger HVAC and weatherization workforce. 

While the power sector is responsible for increasingly less emissions in the state, the report called it “the linchpin of all other GHG-reduction strategies,” adding that “without substantial additions of clean energy, the transition to electric vehicles and building heating and cooling will not result in adequate GHG reductions.” 

Although natural gas remains the dominant source of power in the region, the report said clean energy sources accounted for 48.2% of the state’s electricity. It noted there was 113 MW of wind capacity and 3,325 MW of solar capacity in the state in 2020. The CECP estimates wind needs to increase to 180 MW by 2025 and 3,650 MW by 2030. The 2030 target likely will rely heavily on the successful deployment of offshore wind. 

The state cited the same challenges to transportation electrification as barriers to offshore wind deployment, along with the need for additional transmission to interconnect new renewables. Other issues highlighted include permitting and siting, infrastructure cost allocation and increasing peak demands. 

Additionally, the report noted “revenues that can be earned through existing energy market structures are not certain enough to facilitate long-term financing of new generation outside of state-run procurements for clean energy.” 

It added that utility incentives may need to be reconsidered to get the most out of the existing infrastructure. “Utilities are incentivized to build new infrastructure as opposed to optimizing use of the existing electric grid, managing demand or encouraging distributed resources.” 

“As Massachusetts makes progress and faces challenges in implementing our climate vision, it’s important that we follow the science and stay transparent about our progress,” Secretary of Energy and Environmental Affairs Rebecca Tepper said in a press release. 

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3rd Circuit Rejects Challenges to PJM MOPR, Affirms Authority over FERC Deadlocks

The 3rd U.S. Circuit Court of Appeals on Dec. 1 rejected three petitions seeking to overturn FERC’s approval of PJM’s tightened minimum offer price rule (MOPR) (21-3068, et al.).

The latest MOPR design eliminated a requirement that resources eligible for receiving any state subsidies be mitigated to their cost-based offers, a change the commission mandated in 2019. Later, PJM proposed limiting the application of the rule to resources with the “ability and incentive to exercise buyer-side market power” or when a resource receives state subsidies that are likely to be pre-empted by the Federal Power Act.

PJM submitted the tariff revisions in July 2021, and they went into effect automatically two months later after the commission deadlocked 2-2 (ER21-2582). (See P3 Seeks 3rd Circuit Review of PJM MOPR.)

In its ruling against the PJM Power Providers (P3) Group, the Electric Power Supply Association (EPSA), and the Ohio and Pennsylvania public utility commissions, the 3rd Circuit rejected arguments that FERC acted arbitrarily and capriciously by allowing the rule to go into effect, establishing for the first time since the enactment of the America’s Water Infrastructure Act of 2018 the courts’ authority to review the commission’s “action by inaction.”

The law was mostly focused on improving drinking water quality and financing improvements to flood-control infrastructure, but it also contained provisions pertaining to when FERC deadlocks. Previously, tariff changes that went into effect by operation of law were not reviewable by the courts because there was no action by the commission.

The law added Section 205g to the FPA to allow for such review. It also required that each FERC commissioner submit a written statement into the record explaining their vote.

The petitioners argued that in the absence of an order supported by the majority of the commission, there are “no institutional findings of fact or conclusions of law” that the courts can consider.

The court rejected that argument, saying the new section “unambiguously instructed that we construe FERC’s inaction as an affirmative order” for the purposes of review.

P3 and EPSA also argued that there was no evidence of FERC’s decision for the court to review, as required elsewhere in the FPA.

But the court said that in granting it jurisdiction over deadlocked orders, Congress intended for the commissioners’ statements to serve as evidence. Without such a record, the court wrote, it would be required to consider any orders by operation of law to be arbitrary and capricious, as it would have no way of evaluating how the commission arrived at its answer.

“The statements of the deadlocked commissioners do more than record each person’s individual rationale for affirming or rejecting the rate filing,” the court wrote. “Collectively, they illuminate the agency’s reasons for inaction, which Congress has instructed us to construe as an affirmative order.

“Because FERC must accept a Section 205 rate filing absent ‘a finding that the existing rate was unlawful,’ our thorough consideration of the entire record must ensure that the commissioners who did not find the 2021 MOPR unlawful engaged in ‘decision-making [that was] reasoned, principled and based upon the record.’”

In a joint statement after the deadlock in 2021, former FERC Chair Richard Glick and Commissioner Allison Clements argued that the previous MOPR resulted in the reliability contribution of resources receiving state subsidies potentially not being recognized, inflating the amount consumers paid by as much as $3.4 billion. Commissioners James Danly and Mark Christie opposed PJM’s proposal, arguing that it would ignore the impact of subsidies on wholesale markets and produce uncompetitive outcomes. (See ‘Good Riddance’ to Old PJM MOPR, Glick Says.)

Environmental groups applauded the court’s decision, saying the previous MOPR that FERC required in 2019 forced renewable resources to enter artificially inflated capacity offers and prevented them from being competitive with fossil-fired resources.

“The rule upheld today eliminates the anticompetitive treatment of resources supported by state and local policies in PJM,” said Caroline Reiser, senior staff attorney for the NRDC, in a statement. “With this rule in place, consumers will see the full benefits of state investments in clean power. Fossil fuel interests were trying to use the courts to do something they could not do in the market: slow the clean energy transition.”

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After One Year, SEEM Still Drawing Criticism

It’s been a year since the Southeast Energy Exchange Market (SEEM) began pairing offers and bids, with detractors certain as ever the market is dysfunctional and the utilities involved insisting they will push through the launch difficulties to long-term success. 

SEEM began operations in early November 2022, a year after its foundational agreement passed a deadlocked FERC. (See SEEM to Move Ahead, Minus FERC Approval.) The market’s founding members, including Duke Energy, Southern Co., the Tennessee Valley Authority and Dominion Energy, promised that the expansion of bilateral trading in 11 Southeastern states — now 12 after the addition of utilities in Florida — would reduce trading friction while promoting the integration of renewable resources. 

But Southern Environmental Law Center (SELC) Senior Attorney Nick Guidi thinks SEEM is a far cry from what Southern Co., TVA, Duke, Dominion and other utilities promised when designing the marketplace. 

“We have one year’s worth of operations to reflect on and assess, and based on that, I think we can say SEEM is failing. The information that we do have shows SEEM is not performing as the utilities expected,” Guidi said in an interview with RTO Insider. 

Before the market went live, SEEM participants hired consultants to prepare an analysis showing the market could deliver anywhere from $37 million to $46 million worth of benefits in its first year. But the SELC estimates SEEM has yielded just $3.3 million in savings over its first year, barely covering operating costs. The figure was derived from SELC analysts’ interpretation of the limited data that SEEM publishes on its website under the “Public Data” tab (which requires user registration to view). 

SEEM also estimated it would have an average hourly trade volume of 1,323 MWh; however, in the first year of operations, it averaged about 72 MWh in hourly activity. 

“We’re looking at about a tenth of what was promised one year in,” Guidi said. “The benefits are marginal, and we’re not seeing any uptick in renewable energy through this.” 

Erin Culbert, a spokesperson for Duke, acknowledged to RTO Insider that despite “a lot of activity of bids and offers … we have seen a lower number of successful trades than we would like.” However, she said the market has witnessed a growth in the number of successful matches month to month, particularly after four utilities based in Florida began participating in June. 

According to SEEM’s most recent monthly audit report, prepared by Potomac Economics, the market had 24 members in October. Participants traded 76,000 MWh of energy that month, up from 66,000 MWh in September and above the market-to-date monthly average of 52,000 MWh. 

Culbert said more than 100,000 transactions have been performed in the first year of operations, representing more than 2.5 TW of 15-minute power. 

SEEM’s sponsors are working to increase the number of successful trades, she continued, through means such as Duke’s development of automated tools to improve matches. Market participants, as well as SEEM’s independent auditor, also have suggested making additional training available next year to help participants craft bids and offers “that are a little bit closer to their actual cost.” 

“At this point in time, in some cases the bids and offers are too far apart to make a successful match,” Culbert said. “So we would love to be able to continue to share best practices, maybe look and explore to see if others on the platform want to consider having some more automation on their sides to make it very simple and easy to identify the right bids and offers that have the highest success rate for a match.” 

TVA and Southern deferred to Duke’s comments on the value of the exchange. 

Volumes of matched bids and offers on SEEM for October | Potomac Economics

Expected Benefits and Regulatory Limbo

Since before the market’s launch, SEEM’s critics, which include the SELC, the Carolinas Clean Energy Business Association (CCEBA), the Sierra Club and the Southern Alliance for Clean Energy, have argued it would entrench the power of monopoly utilities while providing limited benefits to customers compared to alternatives. (See SEEM Critics Repeat Call for Technical Conference.) The performance of SEEM over the past year hasn’t done much to change their minds.  

“I don’t know that we should call SEEM a failure yet, but it certainly needs dramatic reform if it’s going to be successful,” CCEBA Executive Director Chris Carmody said in an interview. 

Carmody said that even the $40 million in savings SEEM initially estimated was a low bar to accomplish. He pointed out that Vibrant Clean Energy’s research showed that establishing a competitive wholesale electricity market in the Southeast could save $384 billion by 2040. 

But Southeastern utilities avoid organized markets “like the plague,” he said. 

Guidi said SEEM has a structural problem and lacks the attributes necessary to improve meaningfully. The market should develop an open-access transmission tariff and extend participation to entities outside of its footprint. Currently, he said “only a small subset of entities in the region can participate,” with approximately 65 entities that participated in bilateral trading before SEEM’s establishment now ineligible to participate because of their location outside the footprint. 

The D.C. Circuit Court of Appeals this summer vacated FERC’s denial of requests to rehear its approval of SEEM, largely on procedural grounds. The court found the commission inappropriately denied requests for rehearing as filed late because it failed to take into account two federal holidays when determining the deadline. It remanded the rehearing requests back to the commission. (See DC Circuit Sends SEEM Back to FERC.) 

While it did not rule on the merits of SEEM’s tariff, the D.C. Circuit did agree partially with petitioners’ requests for rehearing of individual market members’ revisions to their tariffs implementing the non-firm energy exchange transmission service used for SEEM transactions, which the FERC majority had approved. These also were remanded back to the commission, with a directive to better explain its reasoning. 

“There’s not a broadly applicable SEEM tariff,” Guidi argued. “We need some transparency. There is very little to go on, and what’s out there, is a black box.”

Guidi said outside parties can’t access pricing data or know who is transacting with whom. “There’s not much for us to assess.” 

Carmody advised FERC and SEEM participants to closely examine the D.C. Circuit’s ruling. If FERC and the utilities take the concerns to heart, Carmody said he thinks SEEM’s design will resemble an energy imbalance market. 

From SEEM’s perspective, Duke’s Culbert said, FERC had already decided that it was “not unfair or discriminatory,” and the D.C. Circuit’s decision amounts to a request for the commission “to justify its decision-making.” She said trades are continuing on the platform under the current filed tariffs, and the focus for now is on continuing to “optimize the performance of the market.” 

Problematic Governance?

Carmody agreed that parties other than utilities should be involved in SEEM governance. He said SEEM appears to have been set up to prevent competition from independent, clean sources of energy, as well as grant Southern Co. the opportunity to sell its output more easily. 

“It was never really explained to us how it was going to promote renewable energy other than it would reduce solar curtailment,” Carmody said of SEEM. 

Guidi said SEEM’s governance design is problematic, where member utilities can choose who they transact with and exert complete control over governance, operations and market rules. 

“Independent entities have no role in SEEM governance, which raises concerns that they could be systematically excluded,” he said. 

To date, no independent power producers have engaged in SEEM trading. 

Guidi said the market needs a more ambitious design that emulates the Western Energy Imbalance Market with a real-time dispatch component. He blamed the slow pace of trading on the fact that SEEM completes transactions only if there’s enough of an overlap between bid and offers. 

“Competitively priced offers give generation owners no guarantee that they’ll be dispatched, unlike in standard organized wholesale markets. This uncertainty would likely dissuade IPPs from participating. It also means the market is not competitive,” he said. 

Culbert pushed back on these complaints about the market’s design, saying SEEM has “a very broad net of folks who can qualify to participate,” including utilities of all sizes. 

She emphasized IPPs that meet the minimum qualifications are welcome to join and “entities with generation or load that can participate in other kinds of wholesale bilateral markets also can participate in SEEM … and certainly any [entities] who would be interested that are in the same footprint would be welcome to reach out for more details.” 

Critics Recommend EIM Structure

Guidi said he believes that SEEM was formed in response to calls for broader market reform to bring lower energy prices and more customer choice to the South. He suggested bringing IPPs to the table would have a disciplining effect on prices and utility behavior and “better align electricity service with customer expectations and desire for cheaper prices and cleaner energy.” 

“You’re looking at cheaper prices; you’re looking at more solar energy, which is exactly what people are looking for,” he said.  

Carmody said SEEM lacks the transparency and the regulatory involvement of the WEIM. 

“Everyone who has a computer has a transparent view into how the Western EIM is functioning,” Carmody said. He said even though an energy imbalance market is voluntary, it still would produce significant savings, though not as much as having an RTO setup. 

“It seems to me that if SEEM were improved, it would be a happy medium between utilities maintaining control but also saving ratepayers a lot of money,” he said. “I really don’t think it’s rocket science to do that.” 

Carmody said ultimately, SEEM’s simplest fix would be to allow more parties to participate. He agreed that including IPPs and large customers would help the market take on some of the best characteristics of an EIM. 

Culbert suggested that SEEM “shares some of the same principles as an EIM, such as … assisting with imbalances and reducing energy costs.” However, she said the goal of SEEM is to be less complex, costly and time-intensive than an EIM. While the team always is looking for improvements, she said they would need to perform cost-benefit analyses to see whether adding “additional levels of complexity and cost” would bring enough value to customers. 

Reliability Concerns

Finally, Guidi said reliability under SEEM is a point of concern, exemplified by the market’s futility during last December’s widespread winter storm, during which TVA and Duke were forced to order rolling blackouts. 

“SEEM just went dark during Winter Storm Elliott. There were no trades for that three-day window. You want a centralized entity that has situational awareness at their disposal,” Guidi said. 

Culbert observed that “energy is a seasonal product,” and that SEEM has weathered only a single example of each season in its operations so far. She said the sponsors are optimistic additional experience will enable designers to improve performance. 

“We will continue to be able to gather new learnings as we go out through subsequent years — the operational team is really still considering this part of launch — to be able to craft the kind of training and the additional best practices that will keep adding value,” she said. 

Guidi said he does see value in SEEM because it brought together nearly every load-serving entity in the Southeast. 

“That’s a lot of different perspectives and different interests. So, that’s the hard part,” he said. 

With significant structural changes, he said SEEM could become integral to the Southeast’s electricity supply.  

“I think it’s worth salvaging. I think with some pretty substantial tweaks it can be a positive, but it’s not there yet,” he said. 

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Texas Public Utility Commission Briefs: Nov. 30, 2023

Texas regulators last week set aside further discussion and consideration of an ERCOT protocol change that one commissioner said was “totally discriminatory” to energy storage resources (ESRs).

The nodal protocol revision request (NPRR1186), approved by stakeholders and the ERCOT board, sets a one-hour state of charge (SOC) for energy storage resources participating in two ancillary services (ERCOT contingency reserve service and non-spinning reserve). It also includes penalties of up to $25,000 per violation.

Calling the rule change a “proposed solution in search of a problem,” Public Utility Commissioner Jimmy Glotfelty said in a memo that NPRR1186 “sets operational limits and potential compliance fines upon storage resources even as those resources are making outsized contributions to ERCOT reliability.”

“There have been no reliability problems from batteries, and there’s been no evidence provided by ERCOT that this has been a problem,” Glotfelty said during the PUC’s open meeting Nov. 30. “This the most flexible resource that we have on our system today, and one that will likely get us through the cold winter, which we’re fearful about.”

He said that because ERCOT hasn’t adopted similar protocols regarding the real-time state-of-fuel availability for coal or gas plants, “it would be discriminatory to adopt burdensome operational requirements on storage devices when no such requirements are placed upon thermal plants.”

“We should be able to understand the benefits of these flexible resources without having penalty structures that are disproportionately challenging to that resource,” Glotfelty said.

ESRs proved invaluable Sept. 6, when ERCOT entered emergency operations for the first time since the disastrous 2021 winter storm. Storage contributed a record 2.17 GW of energy during the event. (See ERCOT Voltage Drop Leads to EEA Level 2.)

“We’re also getting tremendous value from storage facilities at a time when we have really no other dispatchable generation resources coming onto the system,” Commissioner Lori Cobos said. She noted ERCOT is expecting about 1 GW of gas generation over the next few years, but about 8 GW of ESRs.

Texas PUC

Commissioner Lori Cobos | Admin Monitor

ERCOT’s vice president of system operations, Dan Woodfin, told the PUC the grid operator is trying to clarify rules to ensure it has enough reserves “to manage that system that’s much more uncertain than what it’s historically been.”

The change represents a compromise in that it reduced the original SOC requirement from two hours to one. That has done little to assuage storage developers who say the revision would chill the resource’s growth.

“ERCOT has not provided any evidence to show that the additional discriminatory restrictions and penalties on ESRs are founded upon a substantial and reasonable ground of distinction between ESRs and other resource types,” Eolian said in a pre-meeting filing (54445).

The PUC will resume discussion on NPRR1186 during its next regularly scheduled open meeting Dec. 14. It is expected to then approve, reject or remand back to ERCOT the change.

The commission did approve NPRR1184 and a system change request (SCR824). The NPRR clarifies ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and requires staff to credit counterparty collateral accounts for interest every month. The SCR increases the attachment file size and quantities allowed within the resource integration and ongoing operations system.

PUC Recognizes Jones, Bivens

The commissioners opened the meeting with words of praise for Brad Jones, the former ERCOT interim CEO who passed away Nov. 8.

Jones, who previously served as ERCOT’s COO, came out of retirement following the disastrous 2021 winter storm and helped the grid operator pick up the pieces after it nearly collapsed during the event. He is widely credited with restoring confidence in the ISO and its ability to manage the grid. (See Brad Jones, Former ERCOT, NYISO CEO, Dies at 60.)

“Brad did a great service to the state under extraordinary circumstances. He came back in from the sidelines, brought the organization together, helped us pick ourselves up and make things better,” Commissioner Will McAdams said. “Brad’s in a better place. He will be missed.”

“We’re forever grateful for his selflessness and tireless leadership at ERCOT,” interim PUC Chair Kathleen Jackson said. “Brad took on an incredibly difficult task with great enthusiasm and urgency. He immediately rolled up his sleeves working to strengthen the Texas grid, [reestablish] confidence in ERCOT and speak to Texans frankly and honestly about our state’s power needs.”

Glotfelty said there was “zero choice” other than Jones to step in at ERCOT following the storm. He also praised Jones’ work during the state’s deregulation efforts in the late 1990s.

“There were few that could bridge the divide between technical engineering and policy and legislative language. [Jones] could and he could do it fluently and he could do it with ease,” Glotfelty said. “Clearly, he’s done a great service, and he will be missed by, I know, everybody here in this commission and ERCOT.”

“He has been a tremendous contributor to our industry for many years. His charisma, his intellect and humor will always be missed,” Cobos said, recalling the time she compared Jones’ rugged good looks to Texas actor Matthew McConaughey.

The commissioners also recognized Carrie Bivens, who recently stepped down after 3½ years as ERCOT’s Independent Market Monitor, and her ability to raise issues few others would. (See Bivens Resigns as ERCOT’s Market Monitor.)

“This is a tough role that has tough responsibilities right now, but it’s very important. It’s crucial,” McAdams said. “[Bivens] embraced that, that mantra of independence, and did so by maintaining credibility and enhancing it with key policymakers, and that’s something that is invaluable right now. It was more than just a contract. It was service, as well.”

“Carrie was not afraid to give her points, although they weren’t always in line with everybody else’s in this dynamic system that we have. She was bold enough to step out there,” Glotfelty said.

“She exemplified a very strong will to stand behind her positions, and whether we agreed or not with all Carrie’s positions, she made her independent voice heard,” Cobos said. “It’s important that you all hear perspectives, even if you don’t agree with them, and that’s what the IMM is there for.”

Glotfelty Named to NARUC Team

Glotfelty was one of six state regulators named Nov. 22 to a National Association of Regulatory Utility Commissioners (NARUC) working group that will “zero in” on one of the grid’s biggest reliability risks: the “misalignment of the gas and electric power systems.”

The Gas-Electric Alignment for Reliability (GEAR), composed of regulators and industry officials, will conduct a 15-month effort to develop solutions that “better align the gas and electric industries to maintain and improve the reliability of both energy systems.” The lack of such coordination between the two industries has been singled out as one of the primary reasons for load shed events during the 2020-21 and 2022-23 winters.

Glotfelty is joined by Georgia’s Tricia Pridemore, New Hampshire’s Carleton Simpson, Michigan’s Daniel Scripps, Arizona’s Lea Márquez Peterson and Minnesota’s Katie Sieben. Pridemore and Simpson will serve as GEAR’s chair and vice chair, respectively.

Officials from gas and electric utilities and operators will be added to the group later.

Glotfelty also chairs the Texas Advanced Nuclear Reactor Working Group, which was created by Gov. Greg Abbott (R) in August to help position the state as the “national leader on advanced nuclear energy” (55421). (See Texas Seeking Lead Role in Nuclear SMRs.)

The group will next meet Dec. 5 in the PUC hearing room. David Wright, a Nuclear Regulatory Commission commissioner, will discuss regulatory and licensing procedures with the group.

University of Texas at Austin associate mechanical engineering professor Derek Haas, Zachry Sustainability Solutions’ Mike Kotara and Natura’s Doug Robison share the group’s leadership responsibilities.

Legislation Becomes Rules

The PUC approved a change to ERCOT’s emergency pricing program (EPP), reducing the amount of time the high system-wind offer cap (HCAP) remains at $5,000/MWh (54585).

Wholesale prices will be reduced to a $2,000/MWh emergency offer cap should they hit the $5,000/MWh HCAP threshold for 12 hours within a rolling 24-hour period. The $2,000 cap will remain in effect until 24 hours after the EPP is activated, or, if ERCOT is in emergency operations while the EPP is active, 24 hours after the grid operator exits emergency operations.

Generators are eligible to be reimbursed for any marginal costs they incur above the $2,000 offer cap while the EPP is active. To recover marginal costs above the HCAP, generators must submit to ERCOT additional attestations and information justifying any exceedances. Cobos added language to the rule that denies reimbursement to resource entities that fail to provide the necessary information to ERCOT.

ERCOT must notify market participants when the EPP is activated and when it ends.

“This puts iron in the glove of ERCOT to gather this information,” McAdams said. “It reassures the system that somebody is going to be checking to see what exactly is going on in the event of an emergency. It’s just one more measure that allows us to gauge the overall impact to the system and the root causes.”

The change is a result of 2021’s Senate Bill 3 and is designed to limit consumer exposure to high prices during emergency events.

The commission adopted a rule stemming from this year’s legislative session that creates a temporary solar-only renewable energy credit (REC) trading program. The program replaces the PUC’s renewable portfolio standard that is being phased out and will terminate on Sept. 1, 2025. ERCOT will continue to maintain an accreditation and banking system to award and track voluntary RECs generated by eligible facilities, as required by House Bill 1500 (55323).

The PUC also approved a proposal for publication that establishes an allowance for a transmission service provider’s (TSP) interconnection costs for connect resources at transmission voltage to ERCOT’s system (55566).

Renewable interests said the allowance, applied equally across all TSPs, would encourage continued interconnections that keep pace with load growth. Glotfelty agreed, calling the policy non-discriminatory while allowing that it might affect renewable resources more than others.

“This will force some financial discipline on siting for renewables and other facilities,” he said. “If it moves them closer to interconnecting facilities, then they’re going to be OK. These numbers will allow them to interconnect if they move far away, per their decision. They may have to pay more, but it’s all laid out in these rules.”

Foundation Set for $10B Loan Program

The commission approved several proposals for publication that will lay the foundation for the Texas Energy Fund Program, beginning with giving PUC Executive Director Thomas Gleeson permission to solicit and hire a contractor to manage the fund (55562).

The PUC issued a request for proposal for the fund’s manager in October. It hopes to have the contractor on board by the second quarter of 2024.

Texas voters in November approved the TEF program, a result of state legislation passed this year. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)

The TEF fund will provide $7.2 billion in low-interest loans and is intended to incent the development of up to 10 GW of natural gas plants. Some $5 billion will be set aside for 20-year, 3% interest loans to build new generation with at least 100 MW of fully dispatchable capacity. Power plants that come online before June 2029 are eligible for bonus payments.

Another $2.8 billion will be dedicated to grants for infrastructure improvements in non-ERCOT regions and to strengthen resiliency by setting up microgrids at hospitals, fire stations and other critical facilities.

Other proposed rules for publication include:

    • Procedures for loan applications in ERCOT, evaluation criteria, repayment terms and the performance standard a generator must meet to obtain the loan (55826).
    • Procedures to apply for completion bonus grant awards, terms for requesting the annual grant payment and performance standards necessary to obtain a completion bonus grant payment (55812).