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November 4, 2024

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Texas PUC’s Proposed ERCOT Market Design to be Released Soon

AUSTIN, Texas — Keynoting the Energy Bar Association Texas Chapter’s Energy Symposium last week, Lori Cobos, the only lawyer sitting on the state’s Public Utility Commission, said ERCOT stakeholders will soon get a look at the market’s long-awaited redesign.

“Around Nov. 10,” a consulting firm will release its review of the PUC’s market redesign blueprint, Cobos said, which the commission agreed to almost a year ago. The PUC has since added an open meeting to its calendar for that date. A spokesman confirmed the commissioners plan to take up and discuss the consultant’s report and recommendation.

Expect the recommendations to be heavy on dispatchable generation, which includes the usual thermal resources and energy storage. Since the February 2021 winter storm crippled ERCOT’s system, the PUC, ERCOT and Texas legislators have prioritized baseload generation over renewable resources. (See PUC Forges Ahead with ERCOT Market Redesign.)

“If Texas is to continue to lead the country as an economic powerhouse, that will require a reliable, resilient and affordable supply of power to fuel our economy and serve our growing population base,” Cobos said during the symposium Nov. 1. “Texas must maintain year-round reliability under all weather conditions, and to do this, we will need to drive investment in new and existing dispatchable generation through market-based price signals and a reliability-driven framework.”

She said the market must incentivize “fast-responding dispatchable generation” that can respond to wind’s and solar’s variability and retain the existing baseload generation “that is available 24/7 to meet our continuously growing electricity demand and extreme weather conditions.”

A load-side reliability mechanism, proposed in a study funded by generation heavyweights NRG Energy (NYSE:NRG) and Exelon (NASDAQ:EXC), is expected to be the central recommendation. Referred to as the load-serving entity obligation (LSEO), the study’s authors have said it will directly address resource adequacy concerns by introducing a formal reliability standard and the mechanism to ensure an LRE has sufficient resources to meet this standard.

PUC Chair Peter Lake quickly latched onto the LSEO proposal late last year. The other commissioners at the time offered some pushback but agreed to include it on the new market blueprint.

Indirectly responding to criticism from some that the LSEO would be a “capacity-light” market, NRG’s Bill Barnes, senior director of regulatory affairs, said, “People think, ‘Oh, NRG, they just want a capacity market.’ No, we want a competitive market that can survive through reliability events, so that we can preserve our successful market structure. That’s the No. 1 priority for us.”

Barnes did not mention that the consultant reviewing the PUC’s blueprint, E3 Consulting, is the same firm that produced the NRG-Exelon report. The commission chose E3 over ERCOT’s Independent Market Monitor, the only other bidder on the contract.

Energy consultant Alison Silverstein, a former PUC and FERC staffer, has worked with the Texas Consumer Association (TCA) and ICF International, a global consulting services firm, to produce an analysis on the cost and reliability impacts of ERCOT’s recent and proposed market changes. She said deep concern over “a teeny bit of bias and conflict of interest” of E3’s ability to fairly review the PUC’s proposal led to their own analysis.

“The PUC hired E3, apparently untroubled by that same concern, and E3 went off and did the study, and nobody’s heard anything,” Silverstein said, speaking on the same panel with Barnes.

The commission’s blueprint also includes a backstop reliability service (BRS) and the use of dispatchable energy credits (DECs).

BRS would procure accredited new and existing dispatchable resources as an insurance policy to help prevent emergency conditions. Its principles include nonperformance penalties and clawbacks for noncompliance; deploying resources in a manner that doesn’t negatively affect real-time energy prices; and allocating costs to load based on a load-ratio share basis measured on a coincident net-peak interval basis.

The DEC proposal would establish a dispatchable portfolio standard for certain qualifying generators to create the DECs, which would be bought, sold or traded is the same manner as ERCOT’s existing renewable energy credit program.

“Does our market structure provide the right incentives for reliability?” Barnes asked, referring to the market design discussions. “It’s efficient. It’s cost efficient; brutally efficient. So, you’re getting the lowest-cost solution out of our current market design, but that doesn’t always mean reliability.”

Cobos assured her EBA audience that the commission will take public comment before making a final decision in January. She said the Texas Legislature, which begins its 2023 session on Jan. 10 and runs through Memorial Day, will also provide feedback on the blueprint, “in addition to looking at investments in dispatchable generation.”

PUC’s Market Design Costs

The PUC “had three primary options that have been sitting around, and to date, there has been minimal information released about what the specifics of those proposals were, or what the design and cost and reliability implications of those would be,” Silverstein said.

ICF analyzed the proposed designs using available public information and various models. Based on that, it said none of the current proposals would, by themselves, improve reliability enough to yield one outage every 10 years, the industry’s generally accepted standard of 0.1 loss-of-load expectation (LOLE).

“We thought it was a very reasonable set of assumptions and scenarios and methodology,” Silverstein said.

Texans should expect, on average, about five outages every 10 years (a 0.5 LOLE), ICF said. It noted reliability is expected to further deteriorate by 2030 if no further policy measures are taken.

Calling the LSEO proposal a “California-style redesign” of the ERCOT market, in that consumers would pay more for power plants that might not operate, ICF’s study found it would cost Texans an additional $22.8 billion from 2025 to 2030, including $8.5 billion more in 2025 alone, without significantly increasing the grid’s reliability. It forecast the LSEO would add another 2.5 GW of gas generation by 2030.

ICF said the BRS proposal, based on an energy storage entity’s recommendation, would yield less than two outages a decade (0.17 LOLE) at a total cost of $2.6 billion from 2025 to 2030. It projected the BRS would also retain about 8 GW of capacity that would otherwise retire under the current market construct.

The DEC proposal would cost consumers $1.3 billion during its first three years (2023-2025) but would then reduce the total costs to consumers by approximately $2 billion each year from 2027 to 2030, ICF said. It forecasts DEC, based on an energy storage provider’s recommendation, to bring online 3.4 GW of additional two-hour battery storage by 2030.

“Yes, there’s a wide range of uncertainty around LSEO cost,” Silverstein said during an Oct. 26 virtual press conference unveiling the study. “The one thing that is not uncertain, that is absolutely clear, is the LSEO costs are potentially huge. And as of now, the program is so significantly undefined that there is no way to narrow in the parameter for how expensive it could be or how effective it could be at improving reliability.

“Texans need a reliable grid, but not at any cost,” she said.

New Study on Energy Efficiency, DR

TCA plans to release a companion report later this month comparing the cost and reliability effects of using high levels of demand-side resources to improve reliability, with the results contrasted with its supply-side analysis.

Silverstein called it a follow-up, parallel piece to “the one scenario that the PUC chose not to study.”

“What happens if we actually do what customers do a lot more of with energy efficiency and demand-responsive distributed assets?” she said. “What does that do for reliability and affordability in ERCOT?”

Silverstein said Texas energy efficiency requirements are tied for last among the 28 states with such requirements. “We deliver such minimal energy efficiency to so few Texans, it’s criminal,” she said.

Liz Jones, Oncor’s vice president of regulatory affairs, said she expects energy efficiency to be one of the key issues debated within the legislature next year.

“There is a cottage industry about what kinds of programs are effective and efficiently implemented,” Jones said. “There is always a struggle because when we undertake energy-efficiency measures, we are collecting funds from all customers, and we are dispersing them to the customers who are qualified for the energy efficiency. It turns out it takes a lot of money to weatherize. Is it crucial for the person that lives in that home? Yes, and so we’re going to see a fight, I think, at the legislature about how we spend on energy efficiency.”

“The programs today are all over the map. They are not always focused, and they are tiny,” Silverstein said, agreeing with Jones. “The reason the winter storm caused so much damage is because Texas homes are under-insulated, because Texas heaters are ineffective and because the energy demand before the power started going out was 20% above anything that ERCOT had forecast. That was because of a lack of energy-efficient homes and lack of energy-efficient heaters. We deserve better, both for winter and for summer.”

Market Provides Expert Feedback

Jones and NRG’s Barnes both said market participants need to have a greater role in the rulemaking process. They and other ERCOT participants have seen their input sharply reduced with Senate Bill 2, which passed by last year’s 87th Legislature. The legislation created an independent board at ERCOT and gave more accountability to the PUC.

“One of the issues is how much should market participants — like Oncor; like NRG; like the city of Austin — have in making ERCOT rules. I would contend that you need us,” Jones said. “First of all, we’re free labor. We can provide feedback about how a particular rule would or would not be able to be effectuated in real-time operations or in planning. One of the things that I’m personally very interested in is making sure that the ERCOT rulemaking process, like the PUC rulemaking process, incorporates the feedback of interested parties in making those rules. It’s procedural due process, substantive due process. It’s a sensible way to try to do this.”

“I completely agree with Liz’s comments on Senate Bill 2,” Barnes said. “As a stakeholder in a marketplace, we have a stake in it. We have invested a lot of money [and] people time, and we should have a voice. Our folks are the experts. They’re the ones that turn the wrenches to start the power plants, and ERCOT needs to hear from us.”

Barnes added that he hopes the legislature avoids “tinkering” with market rules that have already passed. He pointed to the PUC’s weatherization requirements for power plants and transmission facilities as an example of changes that have already been instituted and that work.

“We like to have rules that are predictable and are certain to be done,” he said. “It would be great for the legislature to let that process play out, but they’re not going to. I would hope that there will be a lot of robust debate and discussion at the legislature, but let’s let the process play out at the PUC where the experts are. It will take time. It’s not like we’re going to be to snap our fingers and have an answer. These things are complicated, and we want to make sure we get them right.”

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Duke CEO: IRA Tax Credits Will Offset 15% Corporate Income Tax

Duke Energy (NYSE:DUK) sees the U.S. clean energy transition — and clean energy tax credits from the Inflation Reduction Act — as providing growth and profit drivers for its regulated utility business, even as the company moves ahead with the sale of the 3.5-GW portfolio of its commercial renewable energy business.

Speaking during the company’s third-quarter earnings call Friday, CEO Lynn Good reported that Duke’s board had authorized the sale of the utility’s commercial and distributed renewable business. The sale will allow the company to focus on its “core” regulated electric and gas utilities, she said.

“We have indications of interest — robust indications of interest — from credible counterparties and have a high degree of confidence we will transact on this business,” Good said. A “definitive” announcement could come in the first quarter of 2023, with the sale closing “as early as mid-year,” she said.

The commercial portfolio includes 1.53 GW of solar, 1.96 GW of onshore wind and 20 MW of battery story, according to company figures.

Lynn Good (Duke Energy) FI.jpgDuke Energy CEO Lynn Good | Duke Energy

As previously announced during Duke’s second-quarter earnings call, the proceeds from the sale will be used to pay down the utility’s debt “and allow us to fund our clean energy transition,” Good said. (See Duke Considering Sale of 3.5-GW Portfolio.)

The IRA’s production and investment tax credits will also act as a counterweight to the law’s 15% minimum corporate tax rate, which, Good said, is not expected “to have a material impact on our cash flows.” According to utility estimates, Duke could be eligible for “several hundred million dollars” per year from the IRA’s nuclear production tax credits, beginning in 2024.

Producing about half of the utility’s electricity in the Carolinas, Duke’s nuclear fleet includes 11 units totaling 10.7 GW of capacity, all located at six sites in the two states, according to the company’s website.

The utility is also estimating that the solar production tax credit will be worth about $60 million per year given the 13 to 17 GW that it could be putting on its system over the next decade. Potential investments in energy storage, estimated at $2.5 billion to $4.5 billion, would be eligible for the 30% investment tax credit for standalone storage, according to utility figures presented during the call.

Besides providing hefty tax write-offs, Good said the tax credits would be “returned to our customers, lowering our overall cost of service and providing for a more affordable energy transition.”

Duke is also capitalizing on the growth of electricity demand from new clean technology manufacturing across its service territory. Good pointed to recent announcements, such as the multibillion-dollar semiconductor plant Wolfspeed is building in North Carolina, and BMW’s expansion into electric vehicles and EV batteries in South Carolina.

Inflation, Supply Chains

With such positive business indicators, including ongoing population increases in its service territories, Good said the utility is projecting an earnings growth rate of 5 to 7% from 2023 to 2027.

The company reported net income of $1.356 billion ($1.78/share) for the quarter, compared to $1.435 billion ($1.88/share) for the same period last year.

Good acknowledged that Duke, like other businesses across the country, is facing headwinds in terms of both inflation and supply chain constraints. To counter inflation, the company has upped its cost-cutting efforts from $200 million to $300 million, Good said.

Responding to analysts’ questions, she said the cuts will come from digitalization initiatives that will “streamline our governance processes and reporting processes.” Duke is also “looking at supply chain and … other things that we could do to potentially move [costs] out of [20]23,” she said.

At the same time, the utility is countering supply chain constraints via multiyear contracts with key vendors. “We have confidence around supply into [2026] and beyond, with options to continue. We’re putting similar arrangements in place for battery storage,” Good said.

Duke’s long-term plan for the energy transition calls for $145 billion in capital investments over the next 10 years, with $75 billion earmarked for grid investments, $40 billion for “regulated zero-carbon generation” and $5 billion for “hydrogen capable” natural gas generation.

Carbon Plan Update

But Duke’s regulatory landscape, particularly in North Carolina, is still uncertain as the utility works through its compliance with H.B. 951, passed in 2021, which requires the Utilities Commission to approve a plan that will cut the state’s carbon emissions 70% by 2030. The commission asked Duke to draft the plan, which under the law must be approved by the end of the year.

Submitted in May, Duke’s draft plan includes the closure of 4.9 GW of coal and the addition of 5.4 GW of solar, but also calls for 3.5 GW of new natural gas generation. The plan also includes alternative pathways to the 70% reduction that would take two to four years longer. (See Duke Files Carbon-reduction Plan for North Carolina Utilities.)

Environmental and clean energy groups and state Attorney General Josh Stein have roundly criticized Duke’s plan and submitted alternatives of their own. But following recent series of public hearings, Duke filed a proposed order for the NCUC to approve its plan, and Good remains confident.

“This process is something that looks reasonable and somewhat predictable to us,” she said Friday. “The solar industry is interested in more solar; the industrials are interested in low prices. Low-income [organizations] are interested in the impact to low-income [customers]. The attorney general and the environmental community want us to go as fast as we can to reduce carbon [emissions].”

Good said that the comments and testimony from such stakeholders provide “fertile ground for the commission to make decisions” and defended the company’s approach.

“In the near term, it’s all about solar and battery [storage], and we have time on the long term to make decisions about some of the more difficult [technologies]: pumped storage; [small modular nuclear reactors]; offshore wind. So, we think there is strength to our recommendation to use the next couple of years to look at development on those key technologies so that we’re prepared by the middle of the decade to make the decisions about where to go.”

In particular, Good said, the company is in “evaluation mode” on offshore wind.

“It’s a renewable resource, but … we also recognize it’s expensive. It has transmission requirements, especially here in the Carolinas where you’ve got to get the power to the load centers that are further west than the coast,” she said. “The approach we’re taking is one of studying and learning more and also allowing the commission and stakeholders and the communities that could be impacted by both offshore and onshore transmission to be involved.

“We will not move first, and we will not move outside of the regulated business,” Good said. “The risk [versus] reward for investors and customers has to be appropriate for us to move forward.”

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Vistra’s Generation Produces During Texas Summer

Vistra (NYSE:VST) said its generation fleet provided 96% commercial availability during Texas’ record-breaking summer, helping smooth the volatility of fuel prices, weather and rising inflation.

CEO Jim Burke told financial analysts during the company’s third-quarter earnings call Friday that its thermal fleet reached maximum capacity on July 13, when wholesale prices reached the $5,000/MWh cap three times.

“A well maintained fleet is key to delivering reliable power for our customers and our communities and ensuring value is captured during these weather events,” Burke said.

Vistra reported quarterly earnings of $1.04 billion as measured by adjusted EBITDA from ongoing operations, as compared to $1.19 billion for 2021’s third quarter. The company uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.

Burke said management has been pleased with how its Vistra Zero assets performed this summer in Texas and California. It is attempting to extend by 20 years the operating licenses at generation subsidiary Luminant’s Comanche Peak Nuclear Power Plan. That would keep the 2.4-GW plant’s two units operating until 2050 and 2053.

“We continue to see how important a role our diverse set of assets are playing throughout the U.S. and ensuring reliable, affordable and sustainable power,” he said.

The Irving, Texas-based company said its full-year results are tracking at the midpoint of their $2.96 billion to $3.16 billion guidance. It is amid an upsized $3.25 billion share repurchase program, having bought back about $2.05 billion in outstanding shares (18%) as of Nov. 2.

Vistra’s share price lost 40 cents on Friday, closing at $22.85.

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NEPOOL Splits with ISO-NE over Pumped Storage Eligibility for IEP

ISO-NE will not incorporate an amendment approved by the NEPOOL Participants Committee to include pumped storage resources in its Inventoried Energy Program, yet another wrinkle into the implementation of the chronically uncertain winter fuel security program.

The D.C. Circuit Court of Appeals in June ordered FERC and ISO-NE to narrow the eligibility of the program, removing certain resources — including hydroelectric — that the court found would benefit from the IEP without any functional change to their behavior. (See Court Strikes a Blow to ISO-NE Winter Plan.)

ISO-NE has moved to comply with that order by preparing a filing to send to FERC for consideration.

But Brookfield Renewable Partners appealed to the PC during its Wednesday meeting to allow pumped storage to remain eligible for the program, arguing that the technology shouldn’t be ruled out.

Brookfield operates the 633-MW Bear Swamp pumped storage facility in Western Massachusetts.

“Brookfield’s view is that when the court ruled to remove hydroelectric resources, it contemplated conventional hydro with pondage but did not contemplate pumped storage hydro operating as storage (i.e., daily pump/charge to generate/discharge),” Aleks Mitreski, the company’s senior director of regulatory affairs, said in a presentation to the PC.

The economic rationale for when to operate pumped storage hydro and a chemical battery resource, for example, is identical, he argued; either all storage should be allowed to participate, or none.

The PC voted to approve Brookfield’s amendment to the ISO-NE compliance filing, which would simply specify that pumped storage is allowed to participate in the IEP. But ISO-NE will ultimately not include the amendment in its filing, the grid operator said.

“We believe the directive from FERC was clear that hydroelectric resources are not eligible under this program, and our filing will adhere to that directive,” ISO-NE spokesperson Matt Kakley said in an email to RTO Insider. “That being said, we welcome FERC’s resolution on this issue and will be prepared to implement the program in accordance with the commission’s ruling.”

The filing isn’t eligible for “jump ball” filings, which would formally pit ISO-NE’s stance against NEPOOL’s. Instead, NEPOOL will file comments to FERC explaining the votes shortly after ISO-NE submits its filing, according to NEPOOL counsel.

Brookfield has estimated that the additional cost to the IEP of inserting pumped storage back into eligibility is about $1.5 million.

Other PC Action

The committee briefly discussed a proposal to raise the age limit for members of the ISO-NE Board of Directors to 75, but it ultimately tabled it for further consideration at its next meeting in December.

It did approve the Hydro-Québec interconnection capability credit and installed capacity revenue values for the upcoming annual reconfiguration auctions.

It also approved by voice vote conforming changes to ISO-NE’s Financial Assurance and billing policies to reflect the implementation of the IEP.

Finally it rejected a request for a waiver of the NEPOOL Generation Information System Operating Rules by NuPower Cherry Street, which has been trying to get corrected renewable energy certificates for February and March of this year.

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MISO Membership Re-elects Incumbent Directors for 2023

MISO’s membership voted to retain three incumbent directors, ensuring the board of directors’ lineup will remain the same next year.

The grid operator said Thursday that current directors H.B. “Trip” Doggett, Barbara Krumsiek and Todd Raba will take their seats at MISO’s U-shaped board table for their final three-year terms.

The trio joined the board on Jan. 1, 2017. Board members are limited to serving three, three-year terms. Raba currently chairs the board.

“Chair Raba and Directors Doggett and Krumsiek have a thorough understanding of the challenges facing our industry, and I look forward to continuing our work together to meet those challenges,” MISO CEO John Bear said in a statement. “Their expertise and institutional knowledge will serve us well as we accelerate our reliability imperative efforts.”

MISO’s board consists of nine independent directors and the CEO.

Although the Nominating Committee interviewed other candidates this year, it ultimately decided to advance for consideration only the incumbent directors up for reelection. (See “Board Will Remain Same in 2023,” MISO Board Week Briefs: Sept. 12-15, 2022.)

MISO membership cast votes this year from Sept. 22 to Oct. 28. The board elections are conducted electronically and require a minimum 25% participation rate among its nearly 140 voting-eligible members to achieve quorum. Members can vote for, against or abstain from selecting any of the candidates. Candidates must earn a majority of supportive quorum votes to be installed.

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Mass. DPU Hears Opposing Views on OSW Finances

Avangrid’s (NYSE:AGR) declaration that the Commonwealth Wind project is no longer financially viable is potentially the latest delay in a long-running effort to site wind power off the coast of Massachusetts.

But advocates for offshore wind are optimistic it is likely only a temporary setback. The company itself signals its intention to continue with the project — but it wants to renegotiate its payments from the electric distribution companies (EDCs) that will buy the power.

Avangrid’s attorneys in an Oct. 20 filing asked the state Department of Public Utilities to suspend for one month its review of power purchase agreements for the 1.2-GW project in light of recent interest rate hikes, inflation and supply chain shortages.

“Commonwealth Wind’s purpose in pursuing this motion is to advance the project in an expeditious, transparent and ultimately successful manner, not to cause delay,” the company said. “Commonwealth Wind remains committed to working with the EDCs to keep the PPAs on track to obtain approval and to minimize the impact of any delays on that process.”

The move came after the three EDCs — Eversource Energy (NYSE:ES), National Grid (NYSE:NGG) and Unitil (NYSE:UTL) — and the state Attorney General’s Office asked the DPU to set remuneration for Commonwealth at 2.25% in accordance with a state law enacted in August. When the process began, remuneration was capped at 2.75%.

Avangrid CEO Pedro Azagra Blazquez told financial analysts during an Oct. 26 earnings call that despite all the challenges facing it, offshore wind remains the cheapest energy alternative in New England. Avangrid, he said, renegotiates many projects, and the changes it is seeking here are “modest and achievable.”

“We’re not suggesting we want to make more money. We’re just suggesting we need to find these projects back to the return we were expecting, and basically not to lose money,” he said.

Avangrid in September announced it was pushing the target completion date for Commonwealth to 2028 because inflation was running at 40-year highs. It said the extra year would allow it to take advantage of rapid advances in turbine technology and install units with 17 to 20 MW of capacity, rather than the 13-MW units that are today’s cutting-edge technology.

Meanwhile, Mayflower Wind Energy on Oct. 27 submitted a motion similar to Commonwealth’s, asking the DPU to suspend review of its PPAs with the same three EDCs for 30 days, or perhaps longer, to consider whether its own offshore wind project is economical and financeable under the current terms.

Possibilities to explore would include cost-savings measures, tax incentives under the Inflation Reduction Act and higher payments by the EDCs, Mayflower’s attorneys wrote.

In a separate motion, Mayflower also supported Commonwealth’s request for a one-month delay.

Offshore wind is an important part of the decarbonization strategy in Massachusetts.

Danielle Burney, deputy communications director of the Massachusetts Executive Office of Energy and Environmental Affairs, told RTO Insider on Tuesday that state leaders are monitoring developments.

“The Baker-Polito administration remains focused on increasing clean, affordable energy options and is prioritizing finalizing the latest offshore wind procurement to meet [Massachusetts’] climate goals and the statutory requirement to procure 5,600 MW of offshore wind by 2027,” she said via email.

“Avangrid’s Commonwealth Wind project, once completed, will serve as a critical component of these efforts and will greatly assist the state in achieving net zero in 2050. The administration is closely monitoring the recent efforts by Avangrid to explore altering the power purchase agreements that were previously executed with the electric distribution companies for the project.”

Amber Hewett, offshore wind energy program director for the National Wildlife Federation, said many factors are currently occuring at once, further complicating the already difficult process of creating a large and viable offshore wind industry in the U.S. and all the supporting infrastructure that it will need, which mostly does not exist.

“I’m staying hopeful that this is simply an unfortunate result of the global economy,” she said Wednesday.

Hewett, who has been advocating for offshore wind for nearly a decade, said proposals have been floating around Massachusetts for nearly two decades, so it is important to take a longer view and focus on the progress being made.

Avangrid is also 50% owner of the 800-MW Vineyard Wind I, which will be the first large-scale offshore wind project in the U.S. when it goes online next year, off Martha’s Vineyard. Hewett is cautiously optimistic that Avangrid wants to continue to move forward with the Commonwealth contract rather than scrapping and renegotiating it.

“So, this is hopefully a one-month setback, which is not much,” she said.

Tuesday was the deadline to submit comments on the matter to the DPU.

Avangrid Senior Vice President Saygin Oytan said in a filing that the estimated capital and debt costs of Commonwealth have increased by hundreds of millions of dollars and the project now has negative value. A modest increase in the PPAs, he wrote, would allow the project to obtain financing, still lower ratepayer bills and still have the second-lowest per-megawatt hour contract price among offshore wind projects that have been procured in the U.S.

If the project had to be put to competitive re-solicitation today, he said, the PPAs obtained would almost certainly be significantly higher than even the “modest increase” that Avangrid believes is needed. He added that he believes many other offshore wind projects nationwide are facing the same financial pressures.

The Attorney General’s Office submitted a two-sentence letter Tuesday restating its earlier brief, which called for the PPA remuneration cap to be cut from 2.75% to 2.25%.

The three EDCs filed a two-paragraph letter Tuesday saying there was no need for a one-month pause to renegotiate the PPAs because they have no intention of renegotiating.

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COP27: Will Countries Step up on Climate, Financial Commitments?

The 27th U.N. Climate Change Conference of the Parties (COP27) kicks off Sunday in Sharm el-Sheikh, Egypt, with an expected 30,000 attendees all focused on reinvigorating countries’ action on climate commitments in the face of worldwide inflation, the ongoing Russian invasion of Ukraine, and growing fears of food and energy insecurity.

Host country Egypt has laid out ambitious goals for the conference, calling for action on a range of pledges made at last year’s COP26 in Glasgow, Scotland, from reductions of greenhouse gas emissions, to solid progress on international financing for adaptation and “loss and damage.”

But Nisha Krishnan, lead for climate resilience at World Resources Institute Africa, sees significant headwinds going into the conference, such as escalating national debt in developing countries. “We have almost half of the [African] continent going into high debt and debt distress situations,” Krishnan said during a COP preview webinar on Wednesday, sponsored by the Environmental and Energy Studies Institute. “This is obviously influencing what is expected out of COP, as well as what can be delivered, particularly financially this year. …

“We just no longer have a climate conversation,” she said. “It has become an economics and finance conversation.”

Krishnan and other energy experts going to the conference agreed that expectations for Sharm el-Sheikh are muted compared to last year’s COP26 in Glasgow, where attendees reached an agreement aimed at keeping global warming to 1.5 degrees Celsius by 2050, the goal set in the Paris Agreement in 2015.

“One of the things about this COP is that it is almost a process COP,” Krishnan said. “There are plenty of things that need to be discussed this year; that we’ll need to announce them next year or the year after. … This is where the hard work gets done.”

But Ryan Finnegan, deputy manager for U.S. climate policy at the World Wildlife Fund, believes that events and action outside the official negotiating halls could “end up being more impactful, both for the delivery of strong COP outcomes [and] achieving implementation goals on the ground.”

“Since the Paris Agreement was adopted in 2015, we’ve seen a real robust increase in subnational and nonfederal participation and interest in tracking events that are happening at these international negotiations,” Finnegan said.

As countries move toward implementing their climate commitments amid calls for transparency and accountability, “there is interest not only at the national government level, but at the institutional and organizational level [for] using COP as a mechanism to force announcements or share progress points, to share expertise,” Finnegan said.

The U.S. delegation will include at least three state governors (still unnamed) and dozens of state officials and lawmakers, he said.

COP veteran Tracy Bach, co-focal point of the Research and Independent Non-Governmental Organizations (RINGOs) of the U.N. Framework Convention on Climate Change (UNFCCC), also pointed to the agenda of themed days that Egypt has organized.

“The Egyptian presidency is focusing on solutions,” Bach said. “The idea here is, in addition to what we know are the main agenda topics … they’re bringing in a wide array of experts, a fair number of them drawn from Africa as well as the global south … to keep fueling the negotiations and expanding the areas of convergence.”

The schedule includes a Youth and Future Generations Day on Nov. 10, Gender Day on Nov. 14 and Biodiversity Day on Nov. 16.

Biden, Midterms and the IRA

COP27 could also see a potential test of U.S. leadership on global climate action, with the credibility and momentum created by the passage of the Inflation Reduction Act and its $369 billion in clean energy funds at risk pending the outcome of the midterm elections on Tuesday.

While Republicans have acknowledged that even if they win control of the House of Representatives and Senate, they will not be able to repeal the law, they could try to pick off specific provisions, according to E&E News.

The midterm results will almost certainly be a factor in President Biden’s appearance at the conference, where he is scheduled to speak on Nov. 11. In the run-up, his administration has been rolling out programs and funding from the IRA, such as the recent $9 billion in rebates to help homeowners pay for energy-efficient home upgrades. (See related story, States to Receive $9B from IRA to Boost Home Efficiency Upgrades.)

But the IRA in and of itself me ay not be enough to build trust with some countries. Multiple analyses of the law, such as one from the Rapid Energy Policy Evaluation and Analysis Toolkit project based at Princeton University, have found that if fully implemented, the law would get the U.S. only four-fifths of the way to its 2030 goal of cutting its emissions 50 to 52% below 2005 levels.

It gives the U.S. a stronger hand going in, Bach said. But “the U.S. still has a long way to go in building trust in these negotiations.”

The IRA is “a domestic effort and has no bearing on the international climate finance piece where the U.S. might be worse in terms of its contributions,” Krishnan said.

Loss and Damage

A key test of U.S. credibility will be its position on “loss and damage,” which is one of COP27’s likely flash points between developed and developing nations. The issue turns on whether developed nations, like the U.S., which have been the world’s heaviest GHG emitters, should pay some form of restitution to developing nations that have sustained irreparable damages from the extreme weather caused by climate change.

The issue is on the conference’s provisional agenda, which has already raised concerns about the scope of any discussions, Krishnan said. The UNFCCC has appointed “two co-facilitators, which are Germany and Chile, to help lead a conversation and discussions around what this agenda item should be, such that there is no agenda fight on the first day and that the agenda is adopted,” she said.

The U.S. has dragged its feet on setting up an official structure or mechanism to finance a loss and damage fund, pushing for a watered-down statement in the final agreement at COP26, calling for “dialogue” on this issue. Special Climate Envoy John Kerry took some significant flack in September suggesting that with limited financing available from governments, funds for mitigation and adaptation should be the top priorities for international climate action.

Kerry has since backpedaled a bit. In a recent interview with Time, he said that the U.S. will take part in conversations on loss and damage at Sharm el-Sheikh and is open to talking about “potential financial arrangements” to help developing countries.

But some African stakeholders say loss and damage may not be the right approach. Speaking at an Atlantic Council webinar on Wednesday, Ayaan Adam, senior director and CEO of the Nigeria-based African Finance Corp., said the focus for international finance should be on resilience and addressing Africa’s massive “infrastructure deficit.”

“What we’re saying is, ‘Don’t build it in the old way.’ [If you] integrate resilience, you don’t have loss and damage,” Adam said. “So it’s not about loss and damage. It’s about understanding the science. … It’s a prevention, so you avoid loss and damage.”

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CAISO Reports on Summer Heat Wave Performance

CAISO got through September’s record-setting Western heatwave without blackouts by importing electricity, calling on the public to conserve energy and coordinating with utilities and government agencies, the ISO said in its 2022 Summer Market Performance Report published Wednesday.

During the 10-day stretch of triple-digit temperatures, from Aug. 31 to Sept. 9, CAISO experienced unprecedented demand, reaching a new high of more than 52 GW on Sept. 6. Demand in CAISO’s Reliability Coordinator footprint, which covers much of the Western Interconnection, set a record at more than 130 GW.

“The heat wave of September 2022 was one of the most challenging events in the history of the ISO grid,” CAISO CEO Elliot Mainzer said in a news release. “During events like these, it is important to carefully and transparently examine what went well and to identify issues to address and lessons learned that can be carried forward into future operations.”

In the report, CAISO said new resources procured since the rolling blackouts of August 2020, when demand reached 46 GW, have bolstered reliability. The ISO’s territory has added more than 3,500 MW of lithium-ion batteries in the past two years to store the ample solar power produced in the daytime in California.

Blackouts and near misses in the last three summers occurred during heat waves when solar power ramped down in the evening, but demand remained high from air conditioning use.

CAISO cited “enhanced coordination, awareness and communications internally and with neighboring balancing authority areas,” including participants in the ISO’s Western Energy Imbalance Market, as another reason it was able to keep the lights on. The increased coordination extended to investor- and publicly owned utilities, the California Public Utilities Commission, the state Energy Commission and the governor’s office, it said.

Market enhancements enacted the past two years helped, too, the report said. CAISO has reworked its scheduling priorities, beefed up its resource sufficiency evaluations and adopted “market pricing designed to incentivize generation during periods of high demand,” it said.

The major factor in avoiding blackouts on Sept. 6, the most strained day of the year, was an emergency text message sent out to 27 million cell phones by the Governor’s Office of Emergency Services urging consumers to conserve electricity in the face of imminent blackouts.

When the text message went out at 5:45 p.m., CAISO already had declared a stage 3 energy emergency and told utilities to arm for load shed, but it had not given the final order to start rotating outages.

Within 20 minutes of the alert, demand plummeted by 2,385 MW, to 48 GW, narrowly avoiding blackouts.

Imports from the Pacific Northwest and parts of the Desert Southwest, where the heat was less extreme, also played a large role in maintaining grid reliability, CAISO said.

“This included net imports of more than 6,500 MW during net peak on September 6 as well as an additional 1,000 MW from WEIM transfers,” the report said. “The ISO both received emergency assistance energy and provided it to other balancing authority areas experiencing stressed system conditions.”

Average daily electricity prices soared to $600/MWh with prices topping $2,000/MWh in some parts of the state. In comparison, the average locational marginal price for September was $106 MWh, it said.

Lessons Learned

The ISO said it learned lessons from the crisis that included the need to improve the use of batteries in the real-time and day-ahead time frames to optimize dispatch and ensure they are used most effectively in heat waves.

“The high prices experienced during the heat wave presented new scenarios for the ISO to learn about the complexities and challenges of managing battery state-of-charge,” the report said.

Batteries that bid above $150/MWh to charge during the day were insufficiently charged when they were needed at nightfall because of a software glitch, CAISO said.

“Despite this, ISO operators were able to position storage resources during the September 2022 heat event to meet net-peak requirements by leveraging minimum state-of-charge market functionality that was implemented as part of a package of 2021 summer readiness enhancements,” it said. “The ISO has now fixed the software issue.”

Another software problem “unintentionally curtailed higher-priority exports … while allowing lower-priority exports to flow,” CAISO said. “Although the ISO largely caught and reversed the error in high-priority curtailments, it deployed a software upgrade on Oct. 13 to ensure the appropriate export curtailment order is followed going forward.”

In addition, there was under- and over-counting of capacity in the WEIM’s resource sufficiency evaluation that resulted in CAISO failing the test two times on Sept. 6 instead of the six times it should have failed, the report said.

Because of the counting errors, “transfers into the ISO were limited, but not material,” it said. “This is because the transfer limits were well above the actual available transfers of 1,000 MW from the WEIM, so transfers into the ISO were not restricted.”

CAISO said it has corrected some of the counting problems and is exploring additional fixes.

The ISO has scheduled a stakeholder call for Nov. 17 to review the analysis and answer questions.

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Crane to Retire, Butler to be New CEO of Exelon

Exelon announced a leadership transition on Wednesday and reported “solid” third-quarter financials on Thursday.

Current President and COO Calvin Butler Jr. will succeed Chris Crane when he steps down Dec. 30 as CEO and director of the board of the Chicago-based utility.

Crane, who has been Exelon’s CEO since 2012, said he had to accelerate his retirement plans because of significant health issues.

Butler has held a series of leadership roles since joining the company in 2008. He was named executive vice president and chief operating officer in February 2022 and was promoted to his current roles just two weeks ago.

Crane presided over his final quarterly earnings call Thursday, updating industry analysts on the company’s outlook and performance, which he described as “solid.”

For the third quarter of 2022, the company reported GAAP net income of $0.68 per diluted share and adjusted (non-GAAP) operating earnings of $0.75, up from $0.47 and $0.53, respectively, in the same quarter in 2021. For the first nine months of this year, Exelon reported $1.65/share, up from $1.33 in the same period of last year.

The company narrowed its guidance for the full 12 months of 2022 to $2.21-$2.29 in adjusted (non-GAAP) operating earnings per share.

Like the rest of the Nasdaq Composite, Exelon’s stock (NASDAQ:EXC) is near a 52-week low. The share price was down 2.84% in heavier-than-average trading on Thursday as the Nasdaq Composite declined 1.73%.

During Thursday’s conference call, Crane addressed the monumental transition to clean energy underway in the electric utility industry.

Exelon, he said, is well-positioned to lead and benefit from the shift.

“Exelon offers an unparalleled exposure to that opportunity,” Crane said. “We serve more electric and gas customers than any other utility in the country in some of the largest cities of the country. We have earned the trust of our customers and our commissions by consistently reliably providing top-notch operation performance.

“And we live our values with steady commitments to our path-to-clean goal as well as through environmental advocacy and support for our communities in a strong governance model. As a result, there is a tremendous demand and support for investments we expect to make in our communities, which, as I said earlier, totals $29 billion of capital from 2022 to 2025.”

‘Privilege and Responsibility’

Crane has spent his entire career in the energy industry, joining ComEd in 1998, shortly before it became part of Exelon.

He was named Exelon’s chief nuclear officer in 2004 and took over leadership of its fossil, hydro and renewables facilities in 2007.

Crane was named president in 2008 and CEO in 2012. Under his leadership, Exelon merged with Constellation Energy and Pepco Holdings in 2012 and 2016 to become the largest U.S. energy company by customer count.

Also on his watch, ComEd became embroiled in a multiyear bribery scandal at the Illinois Capitol, allegedly forking over $61 million in return for legislation that boosted its profits and bailed out its money-losing nuclear plants. A federal investigation ultimately led to the indictment of several former Exelon executives and a $200 million fine for the company in 2020.

Crane’s successor has three decades of experience in the utilities industry and in regulatory, legislative and public affairs.

Early in his career, Butler worked in government affairs at Central Illinois Light Company. He later had senior leadership roles with R.R. Donnelley, a print, digital and supply chain company. He joined Exelon in 2008 and held various leadership roles at ComEd and Baltimore Gas and Electric before becoming BGE’s CEO in 2014.

He holds a bachelor’s degree from Bradley University, a juris doctor degree from Washington University School of Law and an honorary doctorate of humane letters from Morgan State University.

“Leading Exelon is a privilege and responsibility that I take very seriously,” Butler said in a news release. “Chris is a tremendous leader, mentor and friend. As our world has been undergoing significant change, so too has the energy industry, and Chris has been at the forefront of that evolution. At Exelon, we are uniquely positioned to lead the nation and our industry to a clean energy future that is safe, reliable, affordable and equitable for all. I appreciate the Board’s confidence in me and will do everything I can to serve our customers and communities, keep our employees safe and move the energy industry forward.”

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NERC’s DER Strategy Focuses on Industry Education, Collaboration

In a new report released this week, NERC warned that the bulk power system is in the middle of a major transformation because of the spread of distributed energy resources, creating a learning curve for which stakeholders are in danger of falling behind.

In the Distributed Energy Resource Strategy document published Tuesday, NERC said the ongoing “influx of DERs presents potential benefits as well as challenges for grid reliability, resilience and flexibility,” noting that the cumulative capacity of distributed solar facilities is set to rise from about 25,000 MW last year to more than 60,000 MW by 2031. The organization said its goal in presenting the report is to outline “current and future strategic actions” to ensure the grid can be operated reliably as these resources’ share of generation grows.

The new report is similar to a document NERC produced in September, detailing the organization’s risk mitigation strategy for inverter-based resources, a class of generators that includes large solar and wind farms. (See NERC Outlines IBR Risk Mitigation Strategy.)

NERC’s System Planning Impacts from DERs (SPIDER) Working Group has played a major role in the ERO Enterprise’s efforts to adapt the grid for the impact of DERs. The group defines DERs as “any source of electric power located on the distribution system,” which refers to electrical facilities located behind a transmission-distribution transformer that serve multiple end-use customers. In practice, this most often refers to rooftop solar panels and storage technology at businesses or homes.

DERs are attractive for end users because they offer the opportunity to reduce electric bills and provide some chance of operating independently in the event of a service outage; they can also lighten the burden on utilities during periods of high demand, decreasing the risk that interventions like load shedding will be needed. In a report issued in August, SPIDER noted that because they sit behind the meter, DERs have traditionally been viewed as a part of the distribution system only, with little or no impact on the broader bulk power system. (See NERC’s SPIDER Group Warns of Modeling Difficulties for DERs.)

However, the new report warned that the installation of these resources on the grid has proceeded much faster than BPS planners’ understanding of their potential impacts to reliability. NERC’s DER risk mitigation strategy is primarily designed to help stakeholders share their knowledge and push forward their collective expertise on the subject.

Core Tenets Underlying Strategy

The strategy comprises four core tenets. First is DER modeling; according to the report, SPIDER’s interactions with industry experts have “identified that a lack of DER modeling information, tools and established planning practices is limiting [utilities’] abilities to accurately incorporate DER models into planning assessments.” NERC said the group’s efforts in this category will primarily focus on industry guidance, but they will also require changes to reliability standards that relate to modeling in order to ensure planners have the appropriate DER data for modeling purposes.

Another tenet is to ensure that future studies of BPS reliability incorporate the effects of DERs in aspects including the pre-disturbance base case setup, selection of reliable contingencies and analysis of how aggregate DERs will respond to large-scale grid disturbances. SPIDER is currently working to develop a reliability guideline to encourage entities to account for DER growth in their studies; NERC is updating its standards to “ensure … requirements are adequate and clear on how to model, study and assess” the impact of DERs on planning assessments, with further standards updates likely to come in the future.

NERC is also studying the risks associated with the next core tenet, the operational impacts of DER — particularly as it relates to decentralization and the shift of significant amounts of generation to the distribution system. SPIDER is also developing a white paper focused on coordination between transmission and distribution entities to improve BPS reliability.

Finally, the last tenet of the strategy is the contribution of regulatory bodies, particularly FERC, to the conversation. NERC pointed to FERC’s Order 2222, which required RTOs and ISOs to open their markets to DER aggregations, as introducing “unique operational benefits and challenges for grid planners and operators” and showing that other stakeholders will not wait for the ERO Enterprise to take the lead on DERs. The report observed that further regulatory action may target other areas of the ERO’s purview, such as reliability standards, training and education, and cybersecurity.