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November 5, 2024

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Maine Voters Reject Public Takeover of Electric Utilities

Maine voters have decisively rejected a proposal for a public takeover of the state’s for-profit electric transmission and distribution infrastructure.

The unofficial tally in the Nov. 7 referendum was approximately 70% opposed and 30% in favor with 99% of the vote tallied, multiple media reports indicated. The state had not posted official results by the close of business Nov. 8.

The proposed Pine Tree Power Co. would have been a nonprofit, consumer-owned utility focused on reliable, affordable service rather than shareholder profit.

Other mission goals included assisting the state with its climate action plan, improving internet connectivity, advancing environmental and social justice, creating transparent governance and supporting economic growth.

Another question on the referendum ballot Nov. 7 would have affected Pine Tree: A proposed requirement that any consumer-owned electric utility gain statewide voter approval to exceed $1 billion in total outstanding debt.

Voters approved that measure by a margin nearly as wide as their rejection of Pine Tree — 65% to 30% — according to unofficial results.

Rural electrification cooperatives, municipal electric districts and certain quasi-independent state entities also are subject to voter approval of debt exceeding $1 billion, under terms of the referendum.

Long-running Debate

The concept of a Maine public utility has existed for years, rooted in part in the low customer service and reliability ratings of Central Maine Power and Versant, Maine’s two investor-owned electric utilities. (For NetZero Insider’s in-depth pre-election look at the issues, see “In the Fight Over Maine’s Utilities, the Future of the State’s Energy Transition Goes to Voters.”)

But following through and creating Pine Tree has proved difficult.

In 2021, Gov. Janet Mills (D) vetoed legislation that would have directed a public takeover. Seven weeks before the 2023 referendum, she urged state residents to vote “no,” saying a takeover would result in years of litigation and create paralysis amid the urgent need to prepare the grid for the clean energy transition.

Also, she said, Pine Tree would debut with up to $13.5 billion in debt amid potentially high interest rates.

The parent companies of CMP and Versant spent heavily to sway public opinion against Pine Tree.

Arguing in favor of Pine Tree was an array of grassroots organizations focusing not just on high rates and poor performance under the current ownership but on the chance to address environmental and social concerns through public ownership.

Late Nov. 7, the group Pine Tree Power conceded defeat on the ballot measure, but not on the underlying issues. It said:

“Central Maine Power and Versant’s parent companies poured almost $40 million … into misleading voters rather than fixing their worst-in-the-nation service. They made clear that their priority will always be enriching their shareholders, not serving their customers. Thousands of Mainers are ready for public power. While we couldn’t overcome being outspent 37:1, we started a critically important conversation that does not end today. Our grassroots movement educated thousands about the savings, reliability and climate benefits of consumer-owned utilities.”

Before the election, Pine Tree proponents said utility takeovers often take more than one attempt to achieve and said they would continue to press the issue in Maine if voters did not approve it this time.

Yet another of the eight questions on Tuesday’s ballot will have direct bearing on any future effort. By a huge ratio — 86% to 14% by unofficial tally — voters approved a ban on foreign governments and their entities spending money to influence elections or referendums in Maine.

Versant is owned by Enmax, a private corporation whose sole shareholder is the city of Calgary, Alberta. CMP is part of Avangrid, which is part of Spanish utility Iberdrola. “Maine not Spain” has been a recurring slogan in debate over Pine Tree, but the largest shareholder of Iberdrola is not Spain — it is Qatar, through its sovereign wealth fund.

Proposed Structure

Under the wording of the referendum, seven of Pine Tree’s 13 board members would have been elected and six would have been designated experts.

Starting Jan. 1, 2025, the state Public Utilities Commission would have directed takeover of any utility that met the criteria laid out by the referendum.

Upon takeover, Pine Tree Power would have had to retain the utility’s employees and would have been liable for property taxes on its infrastructure. It would have been exempt from state income tax, however, and its debt also would have been exempt from state taxes.

The new company would have had to cover all of its expenses with rates and charges — it would not have had access state funds and its debt would not have been a state liability.

In her Sept. 20 message urging residents to vote down the takeover proposal, Mills said she is committed to improving utilities’ quality of service and holding them accountable for it. But she challenged Pine Tree as a means of accomplishing this and pointed to its proposed structure.

“Question 3 creates a governing board of elected individuals — in other words, politicians — with no particular credentials,” Mills said. “Electing people only injects a level of politics and partisanship into the delivery of our electricity. That’s the last thing we need, and, hey, I’m talking as a politician.

“And what would this governing board of politicians be in charge of? Well, they would be required to contract with an operator to run the transmission and utility’s assets. An operator that has ‘familiarity with the systems to be administered.’ So, somebody who looks a lot like CMP and Versant. So, what we are really talking about here is adding a layer of bureaucracy and politics and partisanship over the existing structure of CMP and Versant and I just don’t see how this improves anything.”

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2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ

Voters Tuesday overwhelmingly approved a nearly $10 billion fund for gas generation in Texas, while handing Democrats victories in legislative elections in New Jersey and Virginia that have implications for energy policy there. 

Texas’ Proposition 7 passed by a vote of 1,641,453-886,991, gathering nearly 65% of the votes. (See $10B Fund for Gas Plants on Texas Ballot.) 

The proposition sets up the Texas Energy Fund (TEF), a $7.2 billion low-interest loan program intended for 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. 

The fund is a result of legislation sponsored by state Sen. Charles Schwertner (R). “Glad to see the voters supported Proposition 7 to ensure Texans have the electric generation they need to keep their lights on during extreme weather conditions,” he said in a statement. 

The Texas Public Utility Commission will oversee the TEF and provide the grants and loans to finance the construction, maintenance, modernization and operation of the state’s electric facilities. 

Stoic Energy’s Doug Lewin, who frequently comments on the ERCOT market, cast doubt on the PUC being able to function as a bank, saying the commission has “no expertise gauging default risk.” 

The PUC’s executive director, Thomas Gleeson, said staff have been working since early summer to prepare for the fund’s implementation. Application and award processes still are being developed, but the commission already has created a webpage with more information on project eligibility and the types of grants and loans available. 

“With voter approval of the fund, we will push forward developing the program and design transparent processes to ensure the administration of the TEF is timely, fiscally responsible and effective,” he said in a release. 

The PUC must begin accepting loan applications for projects within the ERCOT region by June 1, 2024, and must make initial disbursements for approved loans by Dec. 31, 2025. 

NJ Democrats Win Handily Amid Clean Energy GOP Attacks

Democrats strengthened their hold on the New Jersey legislature in Tuesday’s elections, retaining control of both legislative houses despite Republican efforts to paint Democratic Gov. Phil Murphy’s clean energy program — especially its offshore wind (OSW) projects — as excessive and expensive. 

With final results still to be confirmed, Democrats are expected to hold at least 24 seats in the 40-seat Senate and 51 of the 80 seats in the Assembly, adding at least five seats to their current 46. 

The string of victories followed a campaign in which Republican candidates sought to tap into opposition to the wind projects, especially focusing on whale deaths on the Jersey Shore. In one example, the Republican State Leadership Committee (RSLC), a national group that seeks to help the GOP win in state races, produced two advertisements on the issue, one of which concludes with the slogan “Save the Whales. Dump New Jersey Democrats.” 

The election came two years after voters re-elected Murphy by a much narrower margin than expected, prompting speculation that the result reflected voter disapproval of his aggressive clean energy strategy. Anjuli Ramos-Busot, director of the Sierra Club New Jersey Chapter, said Tuesday’s results showed the opposite. 

“The elections reflect that in reality New Jerseyans continue to vote for a clean energy agenda and environmental protections,” she said. “Clean energy transition won, clean air won and energy independence won.” 

Jeff Tittel, the former director of the state Sierra Club, said the long-term impact of the election on clean energy initiatives remains to be seen. Under pressure, some Democratic candidates backed away from supporting the initiatives during the campaign, and he questioned where those Democrats would stand in the future. 

“The question becomes how much willpower does the legislature have to now move forward on a lot of green energy proposals, given the fact that many of them were getting beaten up for the last couple of months,” he said. “Some of them, in order to kind of deflect, said we’re moving too fast on electrification, or they agree that offshore wind shouldn’t get any more subsidies, or that we slow down on EVs.” 

“Will they go back and be where they used to be on supporting green energy?” he asked. “Or because they made certain statements during the campaign, will they be more hesitant?” 

Virginia Voters Hand Democrats Slim Majorities in Both Houses of the General Assembly

Virginia Democrats won enough seats to flip control of the House of Delegates and maintain their majority in the Senate, two years after losing the lower chamber and the governor’s office to Republicans. Gov. Glenn Youngkin (R) will finish out the last two years of his term with slim majorities for the Democrats in both houses. Initial results have the Senate split 21-19 with the House split 51-48, with the Republican candidate leading in one close race that had yet to be called late Wednesday. 

A big motivator for voters this fall was abortion, with Youngkin backing a plan to limit abortions to the first 15 weeks of pregnancy, instead of the current law that allows abortion until the end of the second trimester. The majority of voters siding with Democrats on that issue showed they were rejecting extremism, said Advanced Energy United Policy Director Kim Jemaine. 

“I think you can essentially extrapolate from that, also, that voters are looking at some of the decisions made by Republicans in the General Assembly over the last couple of years and say that voters are also viewing climate denial and obstruction of clean energy policies in the bucket of extremism,” she added. 

She said she hoped Republicans will stop proposing bills curbing clean energy policies such as the Virginia Clean Economy Act (VCEA) of 2020, and the new Democratic majority can work with Youngkin on issues such as energy efficiency and expanding distributed generation. 

A Day 1 priority for the legislature should be filling the two empty seats on the three-person State Corporation Commission, which has operated with Chairman Jehmal Hudson as the only member for most of this year, Jemaine said. In Virginia, the General Assembly (both the Senate and the House) elects the regulators for six-year terms with the governor only able to make temporary appointments if the legislature is out of session. 

“I think folks were waiting for the outcomes of their elections to move forward there,” Jemaine said. “And so, this presents an opportunity for Democrats to appoint judges that will hold [Dominion Energy] accountable and ensure that those decisions are in alignment with the VCEA.” 

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FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’

FERC and NERC’s final report on the December 2022 winter storm laid out “an unacceptably familiar pattern” of extreme cold temperatures leading to widespread generation outages across the Eastern Interconnection.  

The report issued Nov. 7 noted that North America’s electric grid and natural gas infrastructure “continue to be severely challenged during extreme cold weather events” despite repeated warnings after multiple recent similar storms. 

The December 2022 event — known as Winter Storm Elliott — began with a bomb cyclone and extratropical cyclone, both indicating a storm associated with a rapid drop in pressure, that moved from the upper Plains states eastward and reached the Eastern U.S. by Dec. 23. An “unprecedented” amount of generation failed during the event, reaching more than 90 GW in coincident unplanned outages. 

Most of the entities that shed load were in the Southeast U.S., the report said, including the Tennessee Valley Authority, Louisville Gas and Electric/Kentucky Utilities, Duke Energy Progress and Duke Energy Carolinas, and Santee Cooper. Other entities did not shed load but had to issue energy emergency alerts, such as PJM, Southern Co., MISO, SPP and ISO-NE. All affected entities “experienced significant unplanned generating unit outages, derates or failures to start within their footprints.” 

The report noted that, similar to previous cold weather events, entities had warning of the coming frigid weather “well in advance” and many had “issued cold weather preparation notices to their generation and transmission owners and operators.” Temperatures were not as low as in the winter storms of February 2021. However, wind speeds were higher in many places, leading temperatures to drop faster than in 2021. For example, TVA “reported a drop of 46 degrees [Fahrenheit] in five hours.” 

Natural gas declined significantly during the event, due in part to freezing of gas wellheads and other equipment which could not be repaired quickly due to poor road conditions. The report called the gas production decline the greatest since the 2021 storm, with production at the Marcellus Shale and Utica Shale formations falling by up to 54%. Fuel supply issues at natural gas facilities accounted for 20% of the 3,565 generating unit outages and derates during the event (by MW); fuel issues for other resources came to just 4% of the total.  

Other leading causes of outages and derates included mechanical and electrical issues (41% by MW) and freezing issues (31%). The report noted that FERC and NERC “had provided multiple prior recommendations and follow-up activities regarding steps for winter preparedness,” and that most affected generator owners had plans of their own in place for extreme weather. Nevertheless, more than 75% of the generating units that failed due to freezing issues did so in temperatures above their documented minimum operating temperatures. 

Incremental unplanned generating unit megawatt outages, derates and failures to start by cause in the total event area. | FERC

Recommendations Include Gas Reliability Actions

The report provided 11 recommendations for preventing similar events in the future, which the authors acknowledged were “built on previous analyses and findings” from cold weather events over the past decade.  

The first recommendation is to finish implementing the revisions to NERC’s reliability standards suggested in the FERC-NERC joint report on the winter storms of February 2021. The report’s authors noted that “while some changes were implemented in response to previous … events, generators and natural gas supply and infrastructure remain vulnerable to extreme cold weather.” (See FERC Approves More Extreme Weather Rules.) 

Additional recommendations for generator reliability include implementing “robust monitoring” by NERC and the regional entities to ensure compliance with reliability standards and to determine if gaps exist. The report also called for NERC to initiate a technical review of the causes of unplanned generation outages related to mechanical and electrical issues during the event, along with a study by NERC, FERC and the REs to examine the “overall availability and readiness of blackstart units … during cold weather conditions” across the entire U.S. 

But perhaps the biggest recommendation of the report was the call for Congress and state legislatures to pass legislation establishing “reliability rules for natural gas infrastructure necessary to support the grid” and local gas distribution. Elaborating on this point, the authors outlined potential structures similar to the ERO, with regional natural gas communications coordinators fulfilling a role similar to the electric grid’s reliability coordinators. 

Natural gas supply and demand, with temperatures in the northern U.S., for the month of December 2022. | FERC

In a joint statement, NERC CEO Jim Robb and FERC Chair Willie Phillips endorsed this idea, repeating calls for a gas reliability organization that they made when the report was previewed at the commission’s September open meeting. Their support for such an organization echoes a similar call issued by the chairs of NAESB’s Gas-Electric Harmonization Forum earlier this year. (See NAESB Forum Chairs Push for Gas Reliability Organization.)  

“As the report lays out, we narrowly dodged a crisis last year. Had the weather not warmed up on Christmas Day, it is highly likely that natural gas service would have been disrupted to New York City,” Robb said. “The unplanned loss of generation due to freezing and fuel issues was unprecedented, reflecting the extraordinary interconnectedness of the gas and electric systems and their combined vulnerability to extreme weather.” 

In a statement, Todd Snitchler, CEO of the Electric Power Supply Association, said EPSA takes the report’s findings seriously and is “committed to improving power system performance in all weather and demand scenarios.” He added that “power generation outages involving all types of resources … must be addressed and corrected.”  

“The report reveals that no market model, region of the country or fuel type is immune to the challenges experienced during Elliott. A well-designed competitive power market, however, is the best foundation to serve power needs reliably and efficiently,” Snitchler said. “Areas of the country served by competitive power markets fared comparatively well during the storm when it came to resource adequacy … [while] regions served by public power and vertically integrated entities were subject to more than 5,400 MW of load shed at various times during the event.” 

NERC and FERC plan to hold a webinar for industry on the report’s recommendations “at the end of November,” the joint statement said. The date for the webinar has not been set. 

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FERC Accepts ISO-NE Order 2222 Compliance Filing

FERC last week accepted ISO-NE’s third compliance filing for Order 2222, ruling that the RTO’s proposal does not pose prohibitive barriers to market participation for distributed energy resource aggregations (DERAs) (ER22-983-004).

The commission directed ISO-NE to make an additional filing within 90 days to address outstanding issues related to its metering proposal.

At the beginning of March, the commission accepted and rejected parts of ISO-NE’s first 2222 filing, prompting a series of compliance filings from the RTO. (See FERC Gives ISO-NE Homework on Order 2222.) The second and fourth filings that followed went uncontested and were accepted by FERC in late October (ER22-983-003 and ER22-983-005).

The third filing focused on metering rules, market participation models, small utility opt-in requirements and coordination among the RTO, aggregators and utilities.

The filing was challenged in May by Advanced Energy United, PowerOptions and the Solar Energy Industries Association. The groups argued that the metering requirements in ISO-NE’s proposal are prohibitive to DERAs.

“ISO-NE has failed to make any adjustments to facilitate participation by DERs located behind a customer meter, leaving in place a barrier recognized by the commission in its compliance order, and has failed to justify the metering and telemetry provisions that underlie this barrier as directed by the commission,” the groups wrote. “The impacts of ISO-NE’s failure to incorporate behind-the-meter DERs into wholesale markets will only grow as penetration increases.”

For metering DERs, ISO-NE provided three options: retail delivery point metering, submetering with reconstitution and parallel metering.

The organizations said submetering with reconstitution and parallel metering are not viable options for most DERs, and metering resources at the point of interconnection would prevent those behind the meter from responding to price signals during times of peak demand. The organizations said this would “limit ISO-NE’s visibility into their availability, fail to optimize demand flexibility and undermine competition.”

ISO-NE wrote in its compliance that these configurations “minimize overall costs, are consistent with the metering requirements of all non-demand response resources and loads in New England, and ensure a just and reasonable allocation of wholesale power costs.”

FERC sided with ISO-NE, writing that its proposed options are necessary to prevent double counting.

“No party has identified less burdensome alternative metering configuration options that would also address the need to avoid double counting and inequitable cost shifting,” FERC wrote. “However, we encourage ISO-NE to continue to work with its stakeholders to consider additional metering options in the future, including for DERAs to utilize alternative submetering configurations.”

FERC gave ISO-NE 90 days to submit an additional filing that identifies the DERA as the entity responsible for submitting meter data and specifying a deadline for submitting data.

Also at issue was ISO-NE’s rule changes to incorporate DERAs into its participation models used in the RTO’s energy and ancillary services markets. ISO-NE’s initial filing modified aspects of the RTO’s five existing models, while adding two models specific to DERAs.

In March, FERC ruled that ISO-NE “failed to demonstrate that its proposed energy and ancillary services market participation models for [DERAs] accommodate the physical and operational characteristics of behind-the-meter [DERs], because behind-the-meter DERs participating under those participation models may be unable to provide all services that they are technically capable of providing through aggregation.”

The commission’s ruling in March, along with the protest comments, specifically took issue with ISO-NE’s existing Binary Storage Facility and Continuous Storage Facility participation models. In its ruling last week, FERC accepted ISO-NE’s clarifications and revisions, agreeing that the requirements of the models apply to all resources looking to participate.

In a statement to RTO Insider, an ISO-NE spokesperson said the RTO is pleased with the ruling, adding that the changes will “ensure distributed energy resource aggregations are metered accurately and the services they provide are not double counted.”

Sam Ressin of Advanced Energy United said the organization is disappointed with the ruling and “concerned that ISO-NE’s proposal, once implemented, will result in barriers to participation that will prevent most behind-the-meter DERs from contributing to the reliability and affordability of New England’s electric grid.”

In a concurring statement, Commissioner Allison Clements expressed her disappointment with ISO-NE for its decision not to use the filing to enable the full range of DR benefits from DERs.

“In essence, ISO New England chose to do the minimum required by law,” she wrote, noting that the RTO was clearly permitted by FERC to establish alternative DR metering options. “Rather than examining the full suite of options that may facilitate participation of DERs in its markets, ISO New England focused its further compliance filing solely on non-demand response resources.”

Clements added that all supply and demand resources should be considered as options to improve reliability in the region, saying it is “lamentable that ISO New England has failed to examine this path for facilitating more robust resource participation.”

Commissioner Mark Christie dissented with the order, citing the comments he issued in his previous dissent on FERC’s response to ISO-NE’s Order 2222 rehearing request. Christie had said Order 2222 created “nothing short of an incomprehensible quagmire bearing a substantial price tag.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.)

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Parties Preview FERC Review of EPA Power Plant Rule

FERC will host a discussion Thursday on the potential impacts of EPA’s proposed rule for power plant emissions as part of its annual technical conference on grid reliability, and parties have laid out the arguments they want addressed at the forum. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.) 

The think tank Energy Innovation Policy & Technology released a report and hosted a webinar arguing that EPA’s proposal can be met while maintaining reliability. 

The rule would require fossil fuel-fired power plants to install emissions-mitigation technologies depending on when they plan to retire and how often they run. Coal plants that want to keep operating beyond 2040 need to install carbon capture and storage (CCS) technology that eliminates 90% of their emissions, Harvard University Environmental & Energy Law Program Executive Director Carrie Jenks said on the webinar. 

Baseload natural gas plants would either need CCS or blended hydrogen, though the rule would require less investment for plants that run on an intermediate basis or as peakers, Jenks said. 

The rule would effectively retire uncontrolled coal plants and largely leave a system with natural gas and storage balancing higher levels of renewables, which is already largely the case in California, New England and the U.K., said GridLab Executive Director Ric O’Connell. 

“Adding clean resources and using the gas fleet as a balancing resource is a pretty well-known playbook,” O’Connell said. 

Sens. John Barrasso (R-Wyo.) and Shelley Moore Capito (R-W.Va.) — the ranking members of the Energy & Natural Resources and Environment & Public Works committees, respectively — wrote FERC a letter urging it do more than the tech conference. The senators, whose committees oversee FERC and EPA, had urged the commission to hold the tech conference this summer. (See GOP Senators Call for FERC Conferences on EPA Power Plant Rule.) 

“Unless the EPA withdraws or significantly revises its proposed Clean Power Plan 2.0, the EPA will unnecessarily and significantly increase risks to electric reliability,” the senators said. “It will also increase dramatically the costs of generating electric power and make electricity less affordable for American families.” 

If FERC does not bring to bear its expertise and fact-based analysis “to dissuade the EPA” from continuing with the rule, it would be partially responsible for the resulting blackouts, they added. The senators urged FERC to gather comments and submit that record to EPA before the rule is finalized. 

While the rule does have requirements on how long uncontrolled natural gas plants can run if they operate more than 50% of the time, as long as EPA allows averaging, that should not be an issue, Jenks said during the webinar. 

Power plants can run at their full capacity during emergencies, such as Winter Storm Uri in February 2021 or the 2014 polar vortex, and then make up the difference in the rest of the year, she said. 

Another worry that opponents have brought up is the lack of “essential reliability services” such as frequency response, regulation reserves, operating reserves and voltage regulation that are provided for free because of the way traditional power plants work, said O’Connell. Grids do not need all their power plants to provide such services, with O’Connell saying a grid like MISO with about 200 GW of supply needs an “order of magnitude less” than that. 

“It turns out that clean resources, especially batteries with grid-forming inverters, can absolutely provide essential reliability services,” O’Connell said. “In fact, batteries have been providing regulation services in PJM for a long time now, closing in on a decade.” 

California is already rapidly decarbonizing its generation fleet, and CAISO is looking ahead to meet the state’s goals of eliminating emissions from electricity by 2045, said Cristy Sanada, regulatory affairs senior manager for the ISO. 

“The state policies have driven kind of where California is right now,” Sanada said. “California was very early to move on RPS standards and battery mandates. And, you know, we’ve already surpassed a lot of those early kind of RPS targets that were set out.” 

California’s own policies are driving the grid there to change more than a pending EPA proposal, but O’Connell noted that more is at play than just policy when it comes to the energy transition. 

“Let’s look at a state like Texas that doesn’t have any kind of clean energy goals at all, right?” O’Connell said. “Last year, wind energy exceeded both nuclear and coal and provided 25% of Texas’ electricity. Solar came on really strong this year. We saw a huge amount of solar being installed – it’s likely going to be 10% of the state’s electricity next year, if not more. And so, this is happening in states and locations that aren’t necessarily policy-driven like California. It’s really economically driven.” 

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MISO Stakeholders Split on Sloped Demand Curve Proposal

Stakeholders appear divided over MISO’s proposal to use a downward sloping demand curve in its capacity auction, with criticism aimed mostly at a provision to allow utilities to opt out of the auction for three years at a time.  

MISO at the end of September filed for FERC permission to replace its vertical demand curve used in its capacity auction with a sloped demand curve that assigns value to excess capacity (ER23-2977). (See MISO South Support for Sloped Demand Curve Wanes on Opt-out Provision.) Stakeholders’ comments on MISO’s filing rolled in last week.  

Consumers Energy filed in support of the sloped demand curve and said it should take care of the auction clearing capacity prices at either very close to $0/MW-day or near the cost of new entry, and drive “proper” grid investments.  

The Michigan-based utility said MISO’s “current model struggles to provide adequate price signals and investment incentives and fails to promote efficient resource planning or accurately reflect the reliability value of incremental capacity.”  

The Kentucky Public Service Commission also supported the sloping demand curve, saying it would allow excess capacity “to be assigned value commensurate with its reliability contribution along the downward slope of the curve.” 

The Electric Power Supply Association called the new curve “a key element in the ISO’s efforts to address the region’s resource adequacy challenges and support reliable operations.” Calpine also chimed in, saying the curve will yield more accurate capacity prices.  

However, the Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project said while they agreed with most aspects of MISO’s plan to implement the sloped demand curve, they took issue with MISO’s plan to impose an “X% adder” on load-serving entities that opt out of the auction altogether. The adder will require those LSEs to secure more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The adder will be based on how much excess capacity is procured through the auction using the sloped demand curve in previous years. 

The trio said the adder introduces “an artificial financial disincentive against LSEs utilizing the opt-out mechanism, undermining the suite of choices available to LSEs, and it will impose significant artificial costs on ratepayers.”  

In a joint protest, the Public Utility Commission of Texas and the Arkansas Public Service Commission likewise said MISO’s opt-out provision will penalize LSEs. Entergy and Cleco joined in criticism of the opt-out provision and advocated for allowing LSEs to partially opt out of the capacity auction with a portion of their load.  

The Louisiana Public Service Commission said MISO’s requirement that LSEs procure beyond the 1-in-10 standard if they wish to opt out of the auction “all but guarantees” LSEs will choose to participate in MISO’s auctions. The commission said the demand curve won’t incent new capacity, just “shift dollars around among existing capacity, while requiring LSEs” to acquire more capacity than necessary to meet loss-of-load expectation standards.  

Other stakeholders struck a harsher tone against the whole of MISO’s proposal.  

The Mississippi Public Service Commission said MISO’s narrative that a downward sloping demand curve is necessary for reliability is untrue. It said the price signal that the sloped demand curve is designed to evoke is unnecessary because most MISO utilities are vertically integrated and can roll the costs of generation needed to meet resource adequacy targets into their rate bases.  

“The premise — that ‘incremental capacity’ above that needed to satisfy the one day in 10 years loss-of-load expectation standard — is pure ex cathedra hokum,” the commission told FERC. “Energy from installed capacity, not capacity that clears an auction, is what serves load and provides reliability. Efforts in MISO that establish appropriate energy pricing, including scarcity pricing, market monitoring that prevents physical and economic withholding, and the desire to profit from existing generation investment will motivate generators to produce electricity, irrespective of whether those generators cleared in the Planning Reserve Auction.”  

American Municipal Power, Missouri Joint Municipal Electric Utility Commission, Southern Minnesota Municipal Power Agency and WPPI Energy asked FERC to completely reject MISO’s proposal, saying they doubted the changes are necessary.  

“MISO has not justified that these dramatic changes to its resource adequacy construct are warranted. Nor has MISO acknowledged or justified largely eliminating critical auction clearing price mitigation that protects against excessive prices, or explained how its various revisions can be implemented in a coherent, just and reasonable manner,” the utilities said. 

They said they didn’t see how FERC could allow MISO to clear its auction beyond the current limit of 1.75 times the cost of new entry for generation. They also said MISO’s opt-out provision is murky and its proposed opt-out deficiency charge for LSEs that fail to come up with the adder amount of capacity is “unduly punitive.”  

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Eversource Closer to Exiting OSW Venture with Ørsted

Eversource Energy reported Monday that it is moving closer to the sale of its share of an offshore wind joint venture and has substantially completed negotiations with a potential buyer. 

New England’s largest utility has been looking to exit offshore wind development for more than a year, but the process has moved slowly as financial and supply chain challenges altered the economics of its partnership with Ørsted, the world’s largest offshore wind developer. 

Earlier this year, Eversource reported a $401 million impairment on its offshore wind business, which came to $331 million after taxes. (See Eversource Takes Hit on Sale of Offshore Wind Assets.) 

In September, Ørsted bought out Eversource’s interest in the uncommitted wind lease area the two jointly held. Eversource is now trying to finalize the sale of its interest in the Revolution, South Fork and Sunrise projects to an as-yet undisclosed buyer. 

In a Nov. 6 conference call with financial analysts, Eversource CEO Joe Nolan said the main remaining hurdle is for the potential buyer and Ørsted to finalize their joint venture agreement and other documents. 

Nolan could not estimate how long that would take but said Ørsted and the buyer are familiar with one another, having engaged in other transactions. 

“We expect this process to wrap up shortly,” he said. 

Eversource’s stock, which has been trading near 52-week lows, closed 3.16% higher Monday. 

Eversource’s 10-Q filing for the third quarter indicates the company’s total equity investment balance in its offshore wind business had reached $2.58 billion as of Sept. 30. 

South Fork is under construction and is expected to start generating power later this year. The partners have decided to begin construction of Revolution next year. 

Ørsted has said it would like to continue with Sunrise, but the best path to do so would be through rebidding the project with more lucrative terms. 

Nolan shared the same message Monday: “Together, [Eversource and Ørsted] will work towards developing a bid that will reflect the attractive nature of this project. We feel confident that Sunrise Wind will deliver clean and reliable energy to New York and support economic development in the region, much earlier than many other projects. We will continue to evaluate ways to maximize project economics and to ensure project schedules remain on track. We have begun limited onshore construction for Sunrise Wind.” 

Given the fluid nature of that project, CFO John Moreira said Eversource could see a scenario under which it sells its share of South Fork and Revolution first, then follows up with sale of its interest in Sunrise. 

In its financial report, Eversource said it earned $339.7 million for the third quarter, down from $349.4 million in the same period of 2022. For the first nine months of 2023, earnings totaled $846.2 million, down from $1.08 billion in 2022. 

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Energy Bar Assoc. Panelists Urge Midwest to Get a Jump on DER Aggregations

Midwestern parties need to act with more urgency to open wholesale markets to DER aggregation, panelists said during the annual meeting of the Midwest chapter of the Energy Bar Association.

Joann Stevenson Worthington, senior manager of regulatory affairs at Voltus, said DER contributions aren’t as new as some may think. She said FERC Order 2222 was “acknowledging that it was happening and really trying to put some structure around it.”

“The regulations are behind and continue to be behind what’s happening on the ground,” Stevenson Worthington said during the Nov. 6 meeting.

She also said FERC “seems inclined not to give people a lot of time to get their ducks in a row” on compliance.

FERC last month rejected MISO’s proposed 2030 go-live date to bring DER aggregations into its markets. The commission told the grid operator to pick a closer date and explore the possibility of aggregations spanning multiple pricing nodes. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

So far, Stevenson Worthington said she’s observed “piecemeal” responses from states on aggregator participation, driven largely by their regulated utilities approaching them about cost recovery and tariffs. She said she’s concerned that state commissions and RTOs won’t reach the level of cooperation required to successfully implement Order 2222.

Stevenson Worthington said Order 2222 issues need to be “grappled with in the shorter term instead of the longer term” and that it behooves states to work out rule sets now. She said she felt “horrible” telling states that because she knows they’re working with limited funds and resources and often focused on “putting out other fires.” However, she said states and grid operators continuing to work in their own “siloed” processes isn’t practical.

“I think this will require a greater deal of coordination than at current,” she said. She added that full DER aggregator implementation in the wholesale markets will pay off through lower prices for customers.

Ameren Illinois Senior Manager of Regulatory Compliance Peter Millburg said states, utilities, aggregators and grid operators need to arrive at a process that works for everyone — and quickly.

“It’s here. Aggregation is already here, and it’s at scale. … We already purchase capacity from it,” Millburg said. “Right now, it’s a really manual process, and that needs to change.”

Millburg called for a “dynamic, real-time” solution. He said utilities and grid operators need to move from simply making sure load is served to understanding how to maximize dispatch of the system. He also said asking utilities to hand over data and let a third-party aggregator handle every aspect of the process is a “nonstarter” due to cybersecurity concerns.

Millburg said despite vendors’ claims, fully functioning distributed energy resource management systems don’t exist yet, though they should.

Millburg advised everyone to “remove fear.” He said he understands aggregation participation is a new concept, and reliable service is paramount, but that the two aren’t mutually exclusive.

“These are known products; these are existing products. … Keep in mind that it’s not just generation; it’s also demand,” he said.

Steve Davies, IURC’s senior assistant general counsel, said IURC has been holding public meetings on Order 2222 and gathering opinions for nearly a year.

Davies said Indiana might start a docket on the rule or institute its own state rulemaking on allowing DER aggregator participation.

He urged other states to get started as early as possible collecting suggestions and thinking about what rule changes they will need.

“We’ve been doing this for almost a year now … and I feel like I’m just starting to get my head around this,” Davies said.

MISO said it will seek an extension with FERC to hold up to six months’ worth of additional discussions with stakeholders before proposing a new Order 2222 implementation date and deciding whether it can handle multinodal aggregations.

MISO said it will handle FERC’s other, less intensive asks in a filing within 60 days.

MISO’s plan to devote more time to Order 2222 coincides with it extending its DER Task Force through 2024. The RTO originally considered sunsetting the task force this year.

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Vistra Teases ‘Re-segmenting’ Businesses in 2024

Vistra said Nov, 7 that its acquisition of Energy Harbor will accelerate the company’s transformation and lead to a “re-segmentation” of its businesses when the deal closes.

CEO Jim Burke told financial analysts during the company’s quarterly earnings call that Vistra’s “transformative acquisition” of Energy Harbor will support the Irving, Texas-based company’s clean-energy transition, one of its four strategic objectives. He said management expects to disclose the specifics of the combined company’s long-range plan in the first half of next year.

“In the meantime, we continue to opportunistically invest in renewables and energy storage growth,” Burke said.

Ohio-based Energy Harbor and its three nuclear plants — Davis-Besse, Beaver Valley and Perry — will add more than 4 GW of nuclear generation to Vistra’s existing Comanche Peak plant and its 2.4 GW of capacity.

The $6.3 billion transaction, announced in March, has run into a delay at FERC over market power concerns. The commission has said it will rule on Vistra’s application by April 11. The Nuclear Regulatory Commission in September approved the transfer of the plants’ operating licenses to Vistra. (See FERC Delays Ruling on Vistra Purchase of Energy Harbor.)

Vistra has committed to selling more than 1,000 MW of gas-powered generating plants to alleviate the market power concerns and says it made substantial concessions to comply with a Justice Department request in August.

“We have responded to requests from FERC, and that process is progressing,” Burke said. “We believe that will eliminate any potential remaining concerns around market competition. We continue to target a closing before the end of the year.”

The company will also begin construction on its three largest combined solar-and-storage projects next spring as part of the Illinois Coal-to-Solar and Energy Storage Initiative.

Vistra reported $1.61 billion in ongoing operations adjusted EBITDA, compared to $1.04 billion during the same period a year ago. The record-breaking Texas summer boosted its ERCOT fleet’s output to 2.5 TWh during the third quarter, its highest quarterly performance by 10%.

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.

Vistra’s share price closed at $34.77 Thursday, down 56 cents on the day.

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Obstacles to Decarbonizing Key New York Housing Sector Flagged

Decarbonizing New York state’s million-plus midsize apartments will be difficult under current regulatory and financial structures, a report by the Federal Reserve Bank of New York found last month.

Decarbonization is critical for the state’s emissions-reduction goals, but it is expensive and cumbersome for those businesspeople who are generally short of the money and expertise to carry it out. Moreover, the return on investment — slowing damage to the planet — is societal rather than individual. When the benefits of taking action do not accrue to the decision-maker, the report’s authors point out, there is no impetus to decide to take action.

“Window of Opportunity: New York’s Small Multifamily Buildings, Expiring Equipment and Clean Energy Goals” was published in late October as part of the New York Fed’s Community Development initiative. It looked at a specific segment of the state’s 8.6 million housing units: those in five- to 50-unit buildings.

More than 1.45 million housing units are in this category. Those units are aging; almost 70% of their occupants are low- or middle-income; 1.3 million are heated with fossil fuel equipment that is nearing the end of its service life; and many are owned by small-scale landlords.

The conflict is readily apparent: A perfect target for decarbonization is owned by people who lack the resources and knowledge to carry out the work and inhabited by people who cannot afford to pay for it.

The Problems

New York already has one of the lowest per-capita levels of greenhouse gas emissions of any state, among the fewest vehicles per capita and a dominant industry — finance — that does not spew emissions.

So as state leaders pursue the goals and mandates of the Climate Leadership and Community Protection Act, and New York City leaders implement Local Law 97, a primary goal is decarbonizing buildings, the largest single source of emissions in the state.

But actually decarbonizing all those buildings is a tall order. New York’s population growth has been stagnant or negative in recent years, so the effort must focus heavily on retrofitting its existing, aging housing stock: 80% of the buildings that will exist in 2050 have already been built, the authors predict.

The report is based on a series of interviews and a roundtable discussion with 28 stakeholders in the housing and finance sectors. They flagged numerous problems facing decarbonization of the five- to 50-unit sector of New York’s housing stock:

    • Absent any legal mandates, the decision to electrify ultimately is up to the building owner. Owners of smaller properties often run the operation themselves, without benefit of support teams. They are less likely than large-property owners to know about electrification or have the means to pursue financing for it.
    • Owners have far more pressing concerns, such as basic maintenance, and lack bandwidth to undertake a sweeping new initiative.
    • Owners often cannot self-fund a deep retrofit, which can cost more than $100,000 per unit. Financing is dicey, because electrification may actually increase operating costs. The owner cannot raise the rent on a regulated unit, and if the local market is struggling, the owner may not be able to raise rent on an unregulated unit either.
    • Many five- to 50-unit properties already are financed to maximum leverage, making it hard to secure new debt; also, senior lenders worry about lien priority when new mid-process debt is issued.
    • Government incentives and financing for electrification are not optimized for five- to 50-unit properties; the process to apply for such funding is arduous; and the administrative costs are prohibitive.
    • Owners of nonregulated units fear their property will become regulated if they accept funding.
    • Owners of regulated units fear their property will go through a lengthy and potentially costly rent restructuring when utility bills rise post-electrification.
    • Contractors qualified to do the work are in short supply. Small contractors often consider the five- to 50-unit projects too large to undertake, and large contractors consider the projects too small.
    • Risk allocation is lopsided: Owners have no recourse if, as first-movers, they invest in equipment that becomes technologically obsolete or becomes noncompliant with superseding state regulations soon after installation.
    • Predevelopment processes can be lengthy, expensive and cumbersome, potentially including gathering and analyzing historical data, conducting an energy audit and modeling energy savings projections.
    • There is no standardized solution — every project is essentially done from scratch.
    • There is no one-stop shop where small property owners operating on a thin margin with minimal resources can go for assistance with the many aspects of decarbonizing their buildings.

Suggested Remedies

Many of the problems cited in the report boil down to high cost and complex regulations, stubborn issues common to many endeavors in New York.

The report offers no ready list of solutions, but it does flag potential improvements, including increased funding, streamlined incentive programs, more proofs of concept, easily accessible technical assistance and a better-structured retrofit market.

Stakeholders offered some other suggestions:

    • Combining incentives offered through different agencies would help facilitate a project, but that is often impossible because the agencies do not coordinate with each other, or because the funding streams cannot be combined.
    • A new tax credit, abatement and/or exemption would be impactful, helping ease the financial weight of the work.
    • Utility cost breaks or monetized emission reductions would provide something that lenders could underwrite to.
    • Pairing public health care dollars with energy efficiency funding would monetize the health co-benefits of electrification.
    • Creating a form of secondary debt for electrification would sidestep the difficult prospect of financing such projects through the primary debt on the property.
    • On-bill financing for electrification or efficiency upgrades would be helpful, extending the repayment period and eliminating the need for upfront capital without competing with other debt.
    • A single entity or consortium could seek a single bid for multiple properties and ease the deficit of expertise that many of the owners of those properties have.
    • Larger financial institutions could meet their net-zero commitments by reducing the cost of capital.

The report was emphatic on this last point: “Stakeholders strongly emphasized that no matter how many incentives are offered, subsidies are provided or other funding levers are pulled, until the largest financial institutions begin putting their weight behind electrification, mass scale cannot be achieved.”

Along with their concerns and criticism, the stakeholders provided some positive reviews. They unanimously praised the state’s Climate Friendly Homes Fund, for example. The $250 million state initiative is intended to retrofit at least 10,000 units of multifamily housing in economically disadvantaged communities, and in so doing create a template for wider-scale work, establish best practices, demonstrate the feasibility of electrification and spread awareness of the need to electrify.

Another effort is the Clean Heat for All Challenge, designed to install low-cost, low-power heat-pump technology in New York City Housing Authority buildings. The cost of rewiring the authority’s 2,000-plus buildings for higher-voltage solutions would be staggering.