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November 14, 2024

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ERCOT Board of Directors Briefs: Aug. 30-31, 2023

AUSTIN, Texas — ERCOT last week announced two leadership changes it said would “sharpen our focus on daily operations” as it battles near-daily tight grid conditions.

The grid operator said in a Friday press release that Woody Rickerson, previously vice president of system planning and weatherization, has been promoted to senior vice president and COO. He will be responsible for grid operations, weatherization, planning and commercial operations.

“This new position will leverage Rickerson’s deep operations experience and support ERCOT’s continued investments in grid innovations,” ERCOT CEO Pablo Vegas said in a statement.

Kristi Hobbs, newly named vice president of system planning and weatherization, will handle some of Rickerson’s previous responsibilities. She will oversee transmission planning, generator interconnection activities, training and weatherization, and will report directly to Rickerson.

The promotions, both effective immediately, come after ERCOT made six appeals in seven days for voluntary conservation Aug. 24-Aug. 30. The grid operator has recorded 10 all-time peak records this summer. However, it has encountered tight conditions during the early evening, when solar power ramps down and wind resources, which generally contribute less than solar during the summer, try to fill the gap. (See ERCOT Continues to Rely on Voluntary Conservation.)

“As our industry faces dynamic changes, ERCOT is continuously evolving and making the necessary improvements to the grid to support the needs of a growing population and robust economy,” Vegas said

The announcement came the day after ERCOT’s Board of Directors re-ratified Rickerson and Hobbs as officers during its bimonthly meeting.

In two other organizational changes, Chief Compliance Officer Betty Day was given oversight of business continuity and Rebecca Zerwas named director of state policy and Public Utility Commission relations and a board liaison.

ERCOT has been operating without a COO since Cheryl Mele left ERCOT and the position in 2019. She now is vice president of customer care and corporate communications at El Paso Electric.

NPRR1186 Remanded to TAC

The board remanded back to the Technical Advisory Committee a nodal protocol revision request that has drawn opposition from the storage community.

The directors asked that stakeholders and staff address only unusual scarcity situations raised by Eolian, a storage developer that appealed TAC’s approval of NPRR1186. Eolian asked that ERCOT be directed to resubmit new NPRRs to determine batteries’ state-of-charge (SOC) parameters and related compliance obligations. (See “SOC Transparency,” ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.)

Eolian COO Stephanie Smith called for scarcity events to be carefully defined, “ideally with reasonable amounts of study to ensure no further unintended consequences to the market.” She said NPRR1186’s requirement that batteries meet an SOC obligation at the top of the hour will negatively affect reliability and counter the benefit multi-hour batteries provide.

“We don’t yet know whether there will be cost implications to consumers or if it will create grid conditions that lead to reliability concerns or events,” Smith said. “Unfortunately, we don’t always start at the top of an hour and even though we have hourly products, we don’t want all batteries charging at the same time to meet a requirement … that could lead to unintended consequences, especially during tight conditions.”

NPRR1186 also adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market process should begin to respect the AS award limits for ESRs based on duration requirements.

Staff says the measure provides a necessary, cost-effective interim solution to improve the awareness, accounting and monitoring of SOC before the Real-time Co-optimization + Batteries project finishes its work in 2026. As of June 1, ERCOT says there were about 3.3 GW of batteries energized on the system. That total could grow to 9.5 GW by October 2024 should interconnection queue projects with signed agreements and posted security join the grid.

Rickerson and other ERCOT executives said NPRR1186 simply allows them to see how much energy batteries have stored and whether that’s enough to meet their commitments.

“We have a reliability issue today … we want to use batteries. Batteries are the future,” Rickerson said. “But we can’t keep buying a service that isn’t always capable of being delivered. [NPRR1186] will fix that and allow us to get to this power over time.”

Vegas: Environmental Regs a Threat

Vegas reviewed for the board five environmental regulations with overlapping timelines that, when taken together, he said could have serious unintended consequences for the grid during peak demand periods.

“Many of these rules do apply to [thermal] resources,” he said. “They have to understand whether they comply with one, two, three or combinations. It’s a very complex system that could lead to very, very detrimental decisions.”

ERCOT’s generation fleet is reckoning with five recent regulations from EPA:

    • The coal combustion residuals (CCR) rule that regulates CCR disposal at inactive generating units and establishes groundwater monitoring, corrective action, closure and post-closure care requirements.
    • The greenhouse gas rule that proposes significantly lower carbon dioxide emissions for coal and gas units.
    • The Clean Air Act’s Good Neighbor Rule that lowers state-level nitrogen oxides from thermal units to mitigate pollutants to downwind states.
    • The Mercury and Air Toxics Standard rule that proposes particulate matter emissions standards for coal-fired generators and mercury emissions standards for lignite-fired generators.
    • Texas’s regional haze federal implementation plan that recommends new limits on sulfur dioxide and particulate matter emissions to meet air-visibility requirements at national parks and wilderness areas.

“We all need to keep in mind the compound nature of stacking multiple rules on top of each other because it’s pretty deadly when you’re the owner and private investment decisions need to be made,” board Vice Chair Bill Flores, a former U.S. representative, said. “It’s important for the Texas consumer to know that we’ve got 72 GW, over half of our fleet today, are these plants. These rules take a substantial amount of that offline within the short-term period, and there’s no replacement that provides reliable, cost-effective power.”

Vegas said ERCOT has filed comments on all five rules and has scheduled a meeting this week with EPA and U.S. Department of Energy “to continue that dialogue.”

“We are actively engaging with the Department of Energy and the EPA to make sure that they understand our risks as operators on the system,” he said. “We’re obviously continuing that dialogue with them so that they clearly understand that it’s not just a Texas issue, it’s a U.S. issue as the entire grid is transforming.”

The Good Neighbor Rule is not effective in Texas, Louisiana and Mississippi after the U.S. 5th Circuit Court of Appeals issued a stay in May. The court is not expected to make a final ruling until next year.

San Antonio Tx Projected OK’d

The board approved a $329 million reliability project in the San Antonio area that previously had been endorsed by TAC. The CPS Energy project addresses thermal overloads in South San Antonio and has been designated as a Tier 1 project because of its estimated capital costs of $100 million or more.

In other actions, the board also:

    • Authorized the creation of the Technology and Security Committee to provide oversight of technology-related functions and physical and cyber security initiatives and committee assignments for the board’s members. Director John Swainson will chair the committee, the board’s fourth.
    • Approved a date change for ERCOT’s annual meeting of members to Dec. 18, when the board’s committees will meet. The change, from Dec. 19, resolves a conflict with the full board’s meeting.

Board Approves 30 Rule Changes

The directors endorsed 30 revisions requests covering the three TAC meetings since the board last met. With the exception of an other binding document revision (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC), they all passed unanimously.

Office of Public Utility Counsel CEO Courtney Hjaltman abstained from voting on OBDRR048, which was opposed by all six members of TAC’s consumer segment. The measure adds price adders to the operating reserve demand curve of $20/MWh and $10/MWh that will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively.

The PUC approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, in August. (See Texas PUC Approves ERCOT’s ORDC Modifications.)

The board unanimously approved two other OBDRRs, 13 NPRRs, seven changes to the nodal operating guide, two revisions to the planning guide (PGRRs) and the resource registration glossary (RRGRRs) and single modifications to the retail market guide (RMGRR) and verifiable cost manual (VCMRR). They include:

    • NPRR1150: requires qualified scheduling entities (QSEs) that represent resource entities, emergency response service resources or other QSEs, and that receive or transmit wide-area network (WAN) data to maintain connections to the ERCOT WAN and a secure private network.
    • NPRR1163, LPGRR070: discontinue the process of evaluating interval data recorder meters to determine whether any are weather-sensitive.
    • NPRR1164: requires resource entities to identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It also would require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
    • NPRR1165: strengthens market entry eligibility and continued participation requirements for QSEs, congestion revenue right (CRR) account holders and other counterparties by removing minimum capitalization requirements; requiring counterparties to post independent amounts’ remove references to guarantors; clarifying financial statement requirements; and referencing International Financial Reporting Standards rather than retired International Accounting Standards.
    • NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources and distribution energy storage resources seeking qualification to provide ancillary services and/or participate in security constrained economic dispatch (SCED).
    • NPRR1173: accounts for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
    • NPRR1174: establishes a process allowing QSEs or CRR account holders to return overpayment settlement funds to ERCOT.
    • NPRR1175: strengthens market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classifies information in the background check as protected information, modifies application forms for QSEs and CRR account holders, and add a new background check fee to the grid operator’s fee schedule.
    • NPRR1176, NOGRR252: revise the Energy Emergency Alert (EEA) procedures to require a declaration of EEA Level 3 when physical responsive capability (PRC) cannot be maintained above 1,500 MW and require ERCOT to shed firm load to recover 1,500 MW of reserves within 30 minutes. The NPRR also would modify the trigger levels for EEA Level 1 and EEA Level 2, change the trigger for ERCOT’s consideration of alternative transmission ratings or configurations from advisory to watch when PRC drops below 3,000 MW and restore a frequency trigger for the EEA Level 3 declaration if the steady-state frequency drops below 59.8 Hz for any period of time.
    • NPRR1182: incorporates controllable load resources and energy storage resources (ESRs) into the constraint competitiveness test’s (CCT) long-term and SCED versions. Controllable load resources will not be mitigated but will be used to identify whether a market participant has market power in resolving a transmission constraint; other resources’ registration data will be used in the long-term CCT process, and real-time telemetry will be used in the SCED CCT process.
    • NPRR1183: revises rules for and make publicly available on ERCOT’s website general information documents that don’t include ERCOT critical energy infrastructure information (ECEII), remove a reference to the Freedom of Information Act from the ECEII’s definition and remove antiquated or duplicative language related to reliability must run.
    • NPRR1185: adds a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
    • NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for ancillary services that resources can provide fast-response service only if awarded regulation service in the day-ahead market for that resource.
    • NOGRR215: allows new remedial action schemes to address only actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
    • NOGRR230: ensures the WAN data transmission’s integrity by requiring data be shared in a manner that prevents denial of service and distributed denial-of-service attacks.
    • NOGRR247: increases the under-frequency load shed (UFLS) program’s load-shed stages from three to five and changes the transmission operator load-relief amounts to uniformly increment by 5% for each stage, adds a UFLS minimum time delay of six cycles (0.1 seconds) and adds 59.1 Hz to the list of UFLS stages and revises the gray-box language from NOGRR226 to provide that the transmission owners’ load value used to determine load at each frequency threshold will be the TO’s load at the time frequency reaches 59.5 Hz.
    • NOGRR249: specifies methods for TOs to receive electronic communication of system operating limit exceedances.
    • NOGRR251: adds cold weather conditions to the template used for developing emergency operations plans to align with NERC Reliability Standard EOP-011-2 (Emergency Preparedness and Operations).
    • OBDRR045: edits the demand response data definitions and technical specifications, including modifications to the electric service identifiers list provided to retail electric providers.
    • OBDRR047: clarifies treatment of unused funds from previous emergency response service standard contract terms.
    • PGRR103: requires interconnecting entities to complete all conditions for commercial operation of a generation resource or ESR within 180 days of receiving ERCOT’s approval for initial synchronization.
    • PGRR108: updates language to reflect the current practice of posting regional transmission plan and geomagnetic disturbance assessment plans and update data sets.
    • RMGRR174: updates language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
    • RRGRR033: adds data to the resource registration glossary pursuant to NPRR1164.
    • RRGRR035: adds data fields consistent with NPRR1171.
    • VCMRR034: provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.
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FERC Approves Transmission Incentives for MVP Line

FERC last week approved transmission incentives for Missouri River Energy Services’ share of the Big Stone Project in Minnesota and South Dakota.

The wholesale power agency provides power to 61 member municipalities that own and operate their own distribution systems in Iowa, Minnesota, North Dakota and South Dakota. The MISO member is responsible for two segments of the Big Stone Project, which is a Multi-Value Project approved under the grid operator’s 2021 transmission expansion plan.

The first part of the line Missouri River is building is 345 kV and runs about 100 miles from South Dakota into Minnesota along a new right of way, while the second part also is 345 kV, but largely will be built on existing rights-of-way in Minnesota. Both segments involve related upgrades to substations, and the firm is working with Otter Tail Power.

Missouri River expects to spend $285.6 million on its half of the project, which will relieve reliability issues on the 230-kV system and improve connections between 345-kV systems.

The power agency asked for and got hypothetical capital structure, construction work in progress and abandoned plant incentives, plus a 50-50 equity and debt capital structure. To implement those incentives, the firm asked for and got some changes to MISO’s tariff.

The transmission investment is the largest ever made by Missouri River, representing 221% of the $129.5 million of its projected net transmission plan this year and 48% of its long-term debt. Coordinating the line’s permitting with multiple owners also will prove to be more complex.

“We find that Missouri River has demonstrated that the requested incentives are tailored to the risks and challenges faced by the Big Stone Project,” FERC said. “We also find that the approval of the hypothetical capital structure incentive and CWIP incentive will bolster Missouri River’s financial metrics, help ensure maintenance of its current credit rating and enable its participation in the Big Stone Project.”

Missouri River asked for the abandoned plant incentive because the project could fail due to no fault of its own, such as negotiations for construction and operations and maintenance agreements between partners with different business models. It also faces regulatory risks as it crosses two states and will require a federal environmental impact statement.

FERC granted the abandoned plant incentive, agreeing that it will help cut the risk of non-recovery of costs in the event the project is abandoned for reasons outside Missouri River’s control.

Commissioner Mark Christie filed a concurrence, saying that while the project met FERC’s existing requirements for transmission incentives, it was time to examine them generally. Christie has made the same point before on other orders involving transmission incentives.

“As this commission considers other potential reforms related to regional transmission planning and development, it is imperative that incentives like the CWIP incentive, abandoned plant incentive and RTO participation adder are all revisited to ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward,” Christie said.

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LPO Makes $398 Million Conditional Loan to Long-duration Storage Company

Eos Energy Enterprises, in Turtle Creek, Pa., has a solution to the California duck curve: zinc-based batteries with a duration of three to 12 hours, which can easily cover the curve’s trademark steep ramp in demand in the late afternoon when solar panels stop producing energy.

And the Department of Energy’s Loan Programs Office (LPO) is backing the company’s plan to expand production of its next-gen Z3 systems with a conditional loan guarantee of up to $398.6 million.

If finalized, the money will cover about 80% of the $500 million cost of Eos’ Project AMAZE (American Made Zinc Energy) expansion, which the company said will allow it to produce up to 8 GWh per year of the Z3 batteries by 2026. When charged and discharged daily, that capacity could be enough to meet the annual electricity needs of 130,000 average U.S. homes, according to the LPO.

Eos still must meet certain milestones and conditions before the loan is finalized, but the conditional commitment represents a stamp of approval, marking the Eos batteries as a potential first mover in the emerging long-duration storage market.

“Eos’ zinc … batteries provide alternative battery chemistry to lithium-ion, lead-acid, sodium-sulfur and vanadium redox chemistries for stationary battery storage applications,” the LPO announcement said. “Eos’ technology is also specifically designed for long-duration grid-scale stationary battery storage that can assist in meeting the energy grids’ growing demand with increasing amounts of renewable energy penetration.”

The batteries are manufactured using five low-cost and readily available raw materials: zinc-bromide, industrial-grade titanium, graphite felt, plastic and water, according to the company website.

The company prides itself on procuring most of those materials within a day’s drive of its plants in Turtle Creek, Pa., a small town east of Pittsburgh where George Westinghouse built his first factories in the 1890s. That local sourcing should qualify Eos to receive the investment tax credit for standalone storage under the Inflation Reduction Act, including a bonus credit for domestic content, the company said in its release on the award.

The Z3s are rated for 6,000 charge-discharge cycles — about 20 years — with minimal degradation, according to Eos. The basic technology also can be configured for a range of uses, from grid-scale standalone installations to small commercial and industrial applications.

The LPO also notes that the batteries are nonflammable and do not need extra cooling to operate, avoiding some of the hazards of lithium-ion batteries.

Eos’ technology “has been validated by GE and Siemens in the past,” LPO Director Jigar Shah wrote on LinkedIn. “The technology works well, and with automation, we can bring … down the cost curve.”

Targeting The ‘Intraday’ Market

Long-duration energy storage is one of the missing pieces of the U.S. and global energy transition, the answer to perennial concerns about the intermittency of renewables and what happens when the wind doesn’t blow and the sun doesn’t shine. While lithium-ion batteries can provide up to eight hours of duration, most projects today are designed with four hours of duration or less.

The critical mineral supply chain for the technology ― in particular, lithium, nickel and cobalt ― remains a long-term challenge for the industry as well.

Citing DOE’s recent Long Duration Energy Storage Liftoff Report, Shah said U.S. long-duration energy capacity will need to scale rapidly over the next two decades to reach President Joe Biden’s 2050 goal for a net-zero economy. The Liftoff Report estimates 225 GW to 460 GW of grid-scale long-duration storage will be needed.

While other companies, such as Form Energy, are developing multiday technologies, Eos is targeting what it calls the “intraday” sector with its three- to 12-hour batteries.

If finalized, the Eos loan would be the LPO’s first in the long-duration battery energy storage sector. The office’s battery storage investments to date have focused primarily on the electric vehicle (EV) sector, including an $850 million conditional commitment to Kore Power and a $9.2 billion conditional commitment to Blue Oval SK, a joint venture of Ford Motors and SK On, a Korean EV battery manufacturer.

The LPO also provided a $504.4 loan guarantee to Advanced Clean Energy Storage, a project in Utah that will produce green hydrogen to be stored in salt caverns to provide “long-term, seasonal storage.”

‘Time is of The Essence’

Eos started working on its zinc-based battery storage in 2008 and has 95 patents pending on the technology, according to the company website. Eos originally manufactured its units in China but came back to the U.S. in 2018, building a workforce of 300 in Turtle Creek. The company went public via a special purpose acquisition company, commonly called a SPAC, in 2020.

The conditional loan announcement comes at a pivotal moment for Eos, as starting up Z3 production has put a major dent in the company’s earnings, as reported in its second quarter financial results, released Aug. 14. Revenue shrank year over year from $5.9 million in the second quarter of 2022 to just $200,000 this year.

On the upside, Eos booked $86.9 million in new orders in the first six months of 2023 and now has a back-order pipeline of $533.6 million.

The company’s current semiautomated production lines are located in a former Westinghouse facility, renamed Ingenuity Plaza, where production of the Z3s began in August.

Eos also recently announced it is partnering with Wisconsin-based ACRO Automation Services on the design and construction of up to four high-output production lines by 2026. The company predicts the scale-up could create up to 650 permanent jobs.

To help build up that workforce, the company has committed to working with its regional chamber of commerce on expanding science, technology, engineering and math programs in local schools.

“We are putting in place all the elements that will allow us to build an efficient, optimized, state-of-the-art facility at scale,” said Nathan Kroeker, Eos’ chief financial officer. “We believe we can pair the conditional commitment from the DOE with private capital and state and local investment programs to meet our requirements.”

Eos CEO Joe Mastrangelo said the industry must “move with speed and urgency … to meet the demand for long duration energy storage. At such a crucial moment in our global energy transition, time is of the essence.”

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In the Fight Over Maine’s Utilities, the Future of the State’s Energy Transition Goes to Voters

PORTLAND, Maine — In a cramped downtown rental office space, a group of volunteers, environmental advocates and a few paid organizers make small talk, strategize and practice talking to voters about one of the most consequential climate elections of 2023.

Hand-painted signs, made the night before, are hung up on the wall and occasionally fall to the floor, only to be hung right back up. There is too little seating to accommodate all of the volunteers cramming into the office, so half of the people stand through the hour of training.

The campaign, which goes by the name “Our Power,” is trying to rally Maine voters to support a ballot question that would initiate a state takeover of Maine’s two investor-owned electric utilities, creating in their place a publicly run utility called Pine Tree Power, governed by board members who would be elected by Maine voters.

The strategy of the Our Power campaign has consisted largely of trying to convince Mainers on the referendum one voter at a time, either by phone or old-fashioned door knocking.

Our Power is attempting to overcome a multimillion-dollar disadvantage; the parent companies of the two investor-owned utility companies subject to the takeover so far have committed about $27 million opposing the ballot measure, flooding Maine residents with a barrage of advertisements warning of the dangers of a public takeover.

In contrast, the Our Power ballot question committee has taken in about $800,000 in contributions and has about $50,000 in cash on hand according to its most recent disclosures.

Our Power office sign (left) and fliers opposing Question 3. | © RTO Insider LLC

For some proponents of the ballot measure, the main issues of the referendum are cost and reliability. Central Maine Power (CMP) and Versant, the two investor-owned utilities in Maine, were the lowest ranked eastern region utilities in customer satisfaction in 2022 according to J.D. Power. A 2021 report by the nonprofit Citizens Utility Board ranked Maine 42nd among all states and the District of Columbia on overall utility performance, with the state scoring particularly poorly on reliability.

But for another portion of the movement — including some of the major environmental groups that have endorsed the initiative — the climate implications of the ballot question are equally important, and some see the campaign as a potential blueprint for other regions to follow. Both proponents and opponents of the referendum largely agree the outcome of November’s vote could have major implications on the state’s ability to decarbonize rapidly.

“The climate fight is a class war, and the utilities are a perfect example of what that looks like,” said Candice Fortin, U.S. Campaigns Manager for 350.org, a climate organization that has endorsed the campaign. “A handful of people are making billions and billions of dollars and everyone else has to suffer. It’s not OK.”

On the other side, the utility-funded opposition campaigns also put a focus on climate impacts while making their case against the ballot measure.

“We don’t know the ways that Pine Tree Power will try to achieve our renewable energy goals, and it’s a massive risk that shows that there’s a significant potential that Maine would be taken off from the great progress that we’ve made,” said BJ McCollister, president of the Resurgam Group, a public affairs firm hired by Maine Energy Progress, a ballot question committee funded by Versant Power’s parent company ENMAX.

Dueling Climate Claims

Both Maine Energy Progress and Maine Affordable Energy — the latter of which is backed by more than $18 million from CMP’s parent company Avangrid — have run ads arguing the switch to a publicly owned utility could inhibit clean energy.

“Big oil and gas companies spend millions influencing politics,” reads a Facebook ad by Maine Energy Progress. “Putting politicians in charge of our electric grid would put Maine’s progress on clean energy at risk.”

A range of climate-focused nonprofits have endorsed the public takeover, including the Sierra Club, Environment Maine, Maine Youth for Climate Justice, Maine Climate Action Now and several local Sunrise Movement hubs.

Meanwhile, McCollister and Versant have argued the absences from this list of supporters are just as important. While no major climate organizations have announced their opposition to the measure, groups including Maine Conservation Voters and the Natural Resources Council of Maine have remained neutral.

“Utility leadership absolutely matters when it comes to climate action and environmental impacts,” said Kathleen Meil, senior director of policy and partnerships at Maine Conservation Voters, which underwent a lengthy process around its stance on the referendum, ultimately deciding on a position of neutrality. “What wasn’t clear was whether utility ownership structure is the critical factor.”

However, Meil emphasized that Maine Conservation Voters’ position is neither an endorsement of the status quo nor a vote of confidence in the state’s utilities.

“When Paul LePage was governor, he was a climate denier, and he was strongly opposed to climate action, clean energy progress, and really thwarted the best efforts of the climate action and clean energy movements,” Meil said. “During that era, he had the support and the partnership of the utilities in thwarting that clean energy progress.”

Following LePage’s election, along with Republicans taking control of the Legislature in 2010, the state worked to roll back programs around solar rebates and net metering. During the Republican governor’s tenure, CMP lobbied against a bill to save the state’s net metering program, which LePage ultimately vetoed. Soon after the veto, a firm employed by CMP to lobby against the bill announced the hiring of LePage’s daughter.

Seth Berry, former Democratic majority leader of the Maine House of Representatives and three-term House chair of the Joint Standing Committee on Energy, Utilities and Technology, said that even prior to the LePage era, the investor-owned utility companies were “deeply opposed” to policy promoting distributed energy and energy efficiency at the state level.

“We were stymied at every turn not by the large fossil fuel lobby… but by the electricity delivery utilities,” Berry said. “I was just shocked and horrified, like how could we let this happen? How could the system evolve to be so incredibly dysfunctional?”

In 2021, Berry was the lead House sponsor of L.D. 1708, a bill that would have directed the public takeover of CMP and Versant, subject to the approval of Maine voters.

Although the bill passed through the Maine House and Senate with bipartisan support, it ultimately was vetoed by Democratic Gov. Janet Mills. While Mills called the performance of Maine’s investor-owned utilities “abysmal” and did not rule out her support for a public takeover in the future, she called the bill “a patchwork of political promises,” and expressed concern that a lengthy takeover process would delay necessary climate investments in the grid.

Mills has yet to take a public stance on the current ballot referendum facing voters.

Representatives for Avangrid and Versant said the companies support Maine’s transition to clean energy, and do not oppose climate policy generally in the state.

“As a company, CMP strongly supports Maine’s clean energy transition and Maine’s climate action goals,” said Jonathan Breed of Avangrid. “To meet this end, we look to seek a fair and balanced compromise on policies that continue to build on the environmental progress already made while not overburdening our customers.”

The utilities and their respective ballot question committees argue that establishing an elected board to run Pine Tree Power would increase the impact of corporate influence on utility policy.

“The question here is: do you want energy companies to be influencing policy — electric policy, utility policy and environmental policy? If the answer is no, then you probably don’t want this Pine Tree Power referendum to pass,” said Willy Ritch of Maine Affordable Energy. “If, for example, a bunch of oil and gas and fossil fuel interests successfully financed the campaigns of all the people that ran for that board, then maybe those people would not be as interested and willing to make the investments necessary to hook up more renewables.”

Although Avangrid has made significant investments in renewable power along the East Coast, the company also owns a considerable amount of natural gas infrastructure, including gas utilities in Maine, Connecticut, Massachusetts and New York. ENMAX owns a gas distribution network in Alberta, as well as more than 1,000 MW of gas generation.

“CMP and Versant are literally owned by multinational corporations that have their hands all in the oil and gas industry,” said Lucy Hochschartner, deputy campaign manager for Our Power. “They’re only controlled by executives who are accountable to no voters.”

Interconnection Woes

Another point of contention on the climate impacts of the referendum is whether a non-profit utility company would be able to significantly improve on the interconnection processes of the investor-owned utilities, which have come under fire from distributed energy developers in the state.

“CMP and Versant are doing an abysmal job interconnecting clean energy, so much so that the Legislature had to set up additional metrics and fines related to interconnections and require the utilities to do grid planning,” said state Sen. Nicole Grohoski, a member of the Energy, Utilities and Technology committee.

“I get regular complaints from residential rooftop solar customers who have been told by Versant that transformer upgrades needed for interconnection will take two years,” Grohoski added. “Mysteriously, when I point my constituents to the PUC’s dispute resolution process, Versant installs the equipment they need in two months.”

In early 2021, the Maine Public Utility Commission (PUC) opened a docket (2021-00035) looking at the interconnection practices of CMP following a request for an investigation by the Coalition for Community Solar Access and the Maine Renewable Energy Association.

The renewable energy groups allege that several of their members had received significant unanticipated notices of interconnection cost increases.

“These notices were provided to a number of Interconnecting Customers following the completion of the projects’ Impact Study, and immediately prior to execution of the Interconnection Agreement (IA) by CMP,” the renewable energy groups wrote in their request to the PUC. “It is highly unacceptable and unprecedented for a utility to identify entirely new interconnection scope items after the fact and to require a developer to pay for additional costs not contemplated in the System Impact Study.”

In March of 2022, the PUC accepted an agreement between CMP and the clean energy groups which included several provisions including the requirement that CMP must spend $700,000 to boost their interconnection processes. Following the agreement, the clean energy groups argued CMP failed to fulfill the requirements of the agreement, and the docket remains ongoing.

Judy Long of Versant Power defended the company’s record on interconnection to NetZero Insider, saying that while staffing difficulties and growing interest in clean energy subsidies have led to lengthy connection queues, the company is committed to reducing the amount of time it takes to connect projects to the grid.

“We’ve got the largest team in our company working on distributed generation, and we’re trying to work with developers to find ways so we can accommodate them,” Long said.

Breed said the contention CMP has delayed the interconnection of renewables demonstrates a “lack of understanding of the solar interconnection process in Maine given that interconnection cost responsibilities and timelines are governed by Maine PUC rules, not CMP or any other utility.”

“As a regulated utility company, the Maine PUC says it is our role in the interconnection process to systematically understand how new generation assets will affect the distribution of electricity to our customers, and to ensure power delivery remains safe and reliable,” Breed added. “We do not benefit or lose financially.”

A Blueprint for Future Campaigns

While only a handful of large national climate and environmental groups have taken a stance on the referendum, those that have endorsed the campaign see potential for expanding the public power movement well past Maine’s borders.

Proponents of the takeover point to the fact that the earliest communities to reach 100% clean energy in the U.S. are disproportionately served by municipal or co-op utilities, including Aspen, Colo.; Georgetown, Texas; Greensburg, Kan.; Kodiak, Alaska; Rock Port, Mo. and Burlington, Vt.

In his endorsement of the campaign, Bill McKibben, a high-profile climate author and one of the founders of 350.org, emphasized the nationwide potential of the movement.

“Maine’s proposal for a consumer-owned utility offers a model for transforming a nation and a world seeking solutions to the crisis of our era,” McKibben said.

In the Sierra Club’s endorsement, the nonprofit called the potential move to a publicly owned utility a “nation-leading step to protect consumers and the planet.”

Hochschartner stressed that the Our Power campaign remains focused on the specific issues facing Maine, but said the structural issues related to investor-owned utilities exist throughout the country.

“The model right now with investor-owned utilities is so fundamentally broken,” Hochschartner said. “This is really something that has the opportunity to be transformative nationwide.”

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Poll Shows Drop in Support for Offshore Wind in NJ

Support for New Jersey’s development of offshore wind projects has plummeted after 15 years of solid support, with just 54% of state residents now in favor of the strategy, according to a new poll by Monmouth University.

That’s down from 76% support in 2019, the year in which the state awarded its first offshore wind project, when just 15% opposed the move, according to the institute. Forty percent of those questioned now oppose the development of offshore wind, according to the poll.

Offshore wind projects drew 82% support in 2008 and peaked at 84% support in 2011, according to the institute. The poll, of 814 New Jersey adults, was “sponsored and conducted” by the Monmouth University Polling Institute, the institute said.

The poll presents another dose of bad news for the two offshore wind developers looking to complete projects in New Jersey’s waters. Danish developer Ørsted said Wednesday it will delay the expected commercial operations date for its Ocean Wind 1 project — the state’s first offshore project — from 2025 to 2026 because of rising costs. The developer said it will make a final investment decision on the project in late 2023 or early 2024. (See More Bad OSW News: SouthCoast Bails, Ørsted Tanks.)

A spokesperson for Ørsted, responding to a question from NetZero Insider about the poll, said the project will begin onshore construction in a few weeks and “has not slowed down or paused any planned activity.”

“A majority of New Jerseyans support offshore wind because they recognize the incredible need to reduce our reliance on fossil fuels, while more than two-thirds agree that significantly increasing the amount of offshore wind energy produced should be a priority over the next 10 years,” the spokesperson said. The poll shows that 37% think increasing the amount of wind energy produced should be a “major priority” and 30% think it should be a “minor priority.”

The state’s second OSW developer, Atlantic Shores Offshore Wind, released a statement blaming the adverse poll numbers on the “harmful effect of misinformation on sustainable energy development.”

Hurt Summer Tourism

Part of the decline in public opinion stems from concern about the effect on tourism, which is based on the New Jersey Shore. Forty percent of residents say “placing wind farms off the coast will hurt summer tourism,” according to the institute. In contrast, just 9% say it will help tourism, the institute said.

The recent spate of dead whales washing up on New Jersey beaches also influences the debate over offshore wind, the poll said. Twenty percent of those polled said they believe the development of offshore wind “definitely” contributed to whale deaths, and 25% thought it “probably” was connected. Ten percent said wind energy sector “definitely” had no connection to the deaths, and 35% said it probably didn’t.

| Monmouth University

State and federal investigators say they have found no connection between the whale deaths and any preparation work for the turbine projects, for which construction has yet to start.

“Opinion on the beached whale phenomenon has a high correlation with support for wind energy,” the institute said in an article outlining the poll results. “Among New Jerseyans who see a connection between the two, just 29% favor offshore wind energy development. Among those who feel these things are not related, 76% support wind energy.

Tony MacDonald, director of the Urban Coast Institute at Monmouth University, said in the article that it’s not surprising the offshore wind sector is facing headwinds, given that New Jersey is pursuing “very ambitious goals” to develop renewable energy, and “changing the status quo is very hard.”

“Clearly the state and wind industry have to do a much better job in reaching out to communities to demonstrate the economic and environmental benefits of these projects, as well as to counter misinformation about threats to tourism and threats to whales,” he said.

The statement from Atlantic Shores Offshore Wind, a joint venture between Shell New Energies US and EDF-RE Offshore Development, said, “the need to educate and engage in information sharing” is one of the challenges of developing a new energy source.

“We have a role to play in helping people understand offshore wind and ensuring that they have accurate information,” the developer said. “The spreading of misinformation and lies is dangerous and doesn’t serve the people of this state, who so urgently need the benefits that offshore wind will bring. It must stop.”

The project will bring power to more than 700,000 homes, generate $1.9 billion in economic activity and create 18,000 jobs, the statement said.

37% See OSW As Major Priority

The poll shows clearly that residents don’t necessarily see those benefits. Only 22% said they think the offshore wind sector will create a lot of jobs, compared to 55% who said they think it won’t create any jobs, the institute said.

Thirty-seven percent of residents said offshore wind should be a “major priority” for the state over the next decade, down from 48% in 2019, the institute said. The latest poll showed that 30% think offshore wind should be a minor priority, and 30% say it shouldn’t be a priority at all, the institute said.

The extent of the disaffection can be seen in the support for other forms of energy. Forty-one percent of residents favor building a new nuclear reactor, up from 26% in 2019, and 40% of residents favor drilling for oil or gas off the coast, according to the institute. Among those who think the wind turbines would hurt tourism, 23% support wind development, but twice as many favor drilling for fossil fuels off the coast.

The institute released the poll as the state Board of Public Utilities (BPU) evaluates applications submitted by four bidders in the state’s third offshore wind solicitation. The BPU expects to announce the winning bids by the end of the year. (See NJ’s 3rd OSW Solicitation Attracts 4 Bidders.)

The solicitation guidelines say the agency may award capacity of up to 4 GW, and perhaps more, as the state seeks to develop 11 GW of offshore wind capacity by 2040.

The state awarded its first OSW contracts to the 1,100-MW Ocean Wind 1, followed by the selection of the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores projects in 2021. All three projects are located about 10 to 15 miles from the shore, prompting opposition from residents and businesses who fear the visible turbines will ruin the ocean view and deter tourists.

The opposition, including citizens groups and municipal and county government, has instigated several lawsuits against the projects, especially against Ocean Wind 1. A new opposition group, Move ‘Em Out, announced itself this week with a website carrying the slogan “SOS: Your beach is next.”

In turn, Ørsted has filed suit to ensure it gains approvals needed to move the project ahead. (See Lawsuits Mount over NJ OSW Projects as Opposition Digs in.)

The company gained a small victory Aug. 15 when the two sides signed a consent order in New Jersey Superior Court in which the County of Cape May agreed to grant a road-opening permit that will allow the developer to start preliminary work and testing for the eventual installation of underground cables for Ocean Wind 1.

The developer is looking to build a 275-kV underground line through the Jersey Shore community of Ocean City, which is in Cape May County, to connect with the PJM grid at a substation sited on a closed coal-fired power plant in neighboring Upper Township.

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FERC: MISO Can Ban Intermittent Resources from Providing Ramp

MISO has FERC’s go-ahead to bar its renewable energy resources from supplying ramping reserves.

FERC’s Thursday order leaves MISO’s dispatchable intermittent resources (DIRs) ineligible to provide ramping service beginning Sept. 1 (ER23-1195).  (See MISO Plans to Bar Intermittent Resources from Ramp Capability; MISO Defends Renewable Ramping Stance to FERC.)

FERC said MISO’s plan doesn’t amount to undue discrimination because it “currently faces operational and price formation challenges associated with DIRs being unable to deliver ramp capability products services in the vast majority of intervals that DIRs are cleared.”

A group of MISO transmission customers argued FERC should have rejected the filing because the ban will treat similarly situated resources differently.

A coalition of MISO’s clean energy advocates also protested MISO’s plan on the same grounds and said the commission had a duty to reject it because it would create a rate that “unduly discriminate[s] among resources’ eligibility to provide grid services.” The group also said that MISO is “rapidly approaching an inflection point where it may be economic for renewable generation to maintain headroom in order to provide ramp capability products.” They said that prohibiting DIRs from providing ramp service conflicts with “MISO’s admitted need for greater flexibility” over the next two decades.

MISO has said its proposal is necessary — at least for now — because of the “significant differences” between renewable and non-renewable resources’ ability to deliver ramp product. It said most of DIRs’ cleared ramping capability is uneconomic and cannot be delivered because it’s trapped behind transmission constraints. The MISO ramp capability product’s current design doesn’t account for a resource’s deliverability.

“Given these conditions, we find that the proposed tariff revisions are just and reasonable and not unduly discriminatory or preferential as they will allow MISO to procure ramp capability products from only those resources that can reliably deliver them,” FERC decided.

FERC said that accepting MISO’s proposal will put a stop to DIRs being paid for ramp service “even though DIRs cannot reliably deliver the product 99.7% of the time.” It also said it will end some market distortion because MISO’s market clearing software will be able to clear resources other than DIRs that can provide deliverable ramping.

MISO’s Independent Market Monitor agreed that DIRs are “virtually always undeliverable” when scheduled to furnish ramping up capability.

The Monitor said, “ideally, MISO would automatically disqualify any resource from being scheduled to provide ramp capability products when it is not deliverable, but that is not technically feasible for MISO today or in the near future.”

In a joint concurrence, Chair Willie Phillips and Commissioner Allison Clements wrote to “emphasize the narrow, fact-bound nature of these decisions.”

Phillips and Clements said FERC’s decisions hinges on a “near perfect overlap between DIRs’ undeliverability and the circumstances when DIRs would clear ancillary services.”

“Today’s orders depend upon the particular factual circumstances before us, that unlike non-DIRs, DIRs are highly unlikely to be able to provide ancillary services when they are cleared,” the two wrote. They said ramping trends and circumstances could change in the future as MISO adds more renewable energy and advised MISO to improve its markets software so it can account for transmission constraints.

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Rhode Island Increases Heat Pump Incentives

Rhode Island is dedicating $25 million of American Rescue Plan Act funding to create a new heat pump incentive program, Gov. Dan McKee (D) announced last week.

Named Clean Heat Rhode Island, the program will expand heat pump incentives available from the state’s Office of Energy Resources (OER), which previously were focused only on households with oil or propane heating systems.

The new incentives “will make heat pump incentives available to a wider range of Rhode Islanders,” the OER wrote in a press release.

Rhode Island law mandates a 45% decrease in carbon emissions by 2030 compared to 1990 levels, and net-zero emissions by 2050.

“Residential and commercial heating is a major contributor to our state’s carbon emissions,” McKee said in his announcement. “My administration has been hard at work to develop a solution that makes energy-efficient electric heating accessible and affordable for everyone.”

Rhode Island’s residential and commercial heating sectors combined to make up about 28% of the state’s total emissions in 2019, with an additional 1.3% of emissions coming from the gas distribution network, according to the state’s emissions inventory. From 1990 to 2019, combined emissions from the residential and commercial heating sectors declined by about 14%, lagging the 19.6% decrease in total statewide emissions, according to the inventory.

The new incentive program will be broken up into three categories: a residential incentive for homes heated with fossil fuels, an additional residential incentive for low-income customers and a commercial incentive meant for small businesses, nonprofits and public buildings.

The standard residential incentive includes $1,000 per ton (12,000 BTU) of capacity to switch to efficient air source heat pumps and $1,250 per ton for ground source heat pumps. The state also is offering a $750-per-ton new building incentive for air and ground source heat pumps. Both incentives are capped at $10,000 per household.

For income-eligible customers, the incentive will cover the entire cost of the upgrade, but it extends only to customers with oil and propane heating systems.

According to the state, heat pumps for Rhode Island homes typically require two to three tons of capacity. A 2020 study commissioned by National Grid found that converting a single-family Rhode Island home to a ductless mini-split heat pump would have an average installed cost of $15,600.

The commercial incentive, which includes $2,500 per ton for air source heat pumps and $4,500 per ton for ground source heat pumps, is extended to nonprofits as well as small-to-medium businesses with less than $30 million in gross annual revenue.

Rhode Island Energy, the state’s investor-owned utility company, also offers up to $350 per ton to residential customers switching to electric heat pumps from propane, oil or natural gas heating systems.

The new incentive program comes as the state continues to grapple with how to cost-effectively decarbonize its heating sector and natural gas network.

Rhode Island’s Public Utilities Commission is in the middle of a multiyear investigation into the future of the state’s gas network and how to align the network with the state’s statutory climate goals (Docket No. 22-01-NG). (See Rhode Island PUC Grapples with Future of Gas.)

The PUC assembled a stakeholder committee in March of this year — with representation from a diverse range of companies and organizations, from Enbridge to the Sierra Club — to determine the scope of the investigation’s technical analysis.

The stakeholder committee is expected to finalize a list of decarbonization scenarios for the state’s gas network in September. In the coming weeks, the state likely will announce the members of a technical working group, who will work with consulting firm Energy + Environmental Economics (E3) to develop the granular assumptions for the technical analysis.

In August, E3 circulated a list of draft decarbonization scenarios that varied in levels of reliance on heating electrification, the existing gas system and alternative fuels like hydrogen and biomethane. The draft options ranged from a “High Electrification” scenario, which assumes the eventual decommissioning of the gas system, to a “Continued Use of Gas” scenario, which assumes a significant role for alternative fuels.

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ERCOT Continues to Rely on Voluntary Conservation

AUSTIN, Texas — ERCOT CEO Pablo Vegas thanked Texas consumers Thursday for helping the grid operator survive tight operating conditions this summer, saying their response to conservation appeals has been “nothing short of tremendous.”

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“Over the last 10, 11 days, we’ve asked Texans quite a bit to conserve energy during broad periods of the afternoon and early evenings,” Vegas told ERCOT’s Board of Directors Thursday. “We’ve seen each of the days that we have made those calls a material and meaningful impact on energy demand that has contributed … to get through a tight period of operations without having to go into emergency operations.”

The grid operator has made nine appeals for voluntary conservation this summer, including six times in seven days since Aug. 24. Residential customers are not compensated for their reduction, unlike businesses that participate in demand response programs.

The oppressive heat that has baked Texas since June has lessened this week, and demand with it. After recording more than 200 hourly average demand marks of 80 GW this summer, the average peaks have reached only 78.12 GW since Sunday.

However, ERCOT still has encountered tight conditions during the early evening, when solar power ramps down and wind resources, which generally contribute less than solar during the summer, try to fill the gap.

The problem this week is with thermal generation units, which have been running full bore this summer. On Wednesday during ERCOT’s latest conservation appeal, thermal outages neared 12 GW, almost a third above what the ISO terms an “extreme” level.

“We had more thermal outages coming off of a long stretch of very high demand and high utilization,” Vegas said. “It’s not surprising to see some mechanical breakages happening on some of the dispatchable generation.”

He told the board that ERCOT’s new normal is managing three primary variables that drive the grid’s reliability on any given day: demand on the system, the “traditional” thermal dispatchable fleet’s availability, and intermittent renewable generation’s performance.

“The combination of those three contributes meaningfully to whether or not we’re going to have enough supply to meet demand,” Vegas said. “When you have a challenge with one or even two of those, sometimes things can be tight and we get through it. And if you have issues with all three of them, you can have very tough conditions.”

Vegas said that on Aug. 17, operating reserves dwindled to about 600 MW during the evening ramp down. ERCOT resorted to deploying its ancillary services to find extra supplies to meet demand. That included its emergency reserve service, under which participants are paid to take their loads offline.

“What we’ve been experiencing throughout the summer has been some combinations of those three at different points in time,” he said. “That’s why it’s so critical that we have these tools available to us to manage these very quickly evolving situations and circumstances.”

ERCOT has set 10 new all-time peaks as of Aug. 23. The current mark of 85.44 GW, set Aug. 10, still stands. That is a 6.7% increase over last year’s peak, a stunning load growth when compared to the industry’s normal 1% gain year over year, Vegas said.

“The Texas economy continues to be booming and this is a great outcome for the state of Texas. It’s bringing opportunity, it’s bringing jobs … but it’s also bringing demand,” he said. “I don’t think anybody expects the growth to slow down meaningfully, so we need to be positioned to lean into that and to support that growth as we move forward.”

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Backers of Independent Western RTO Seek to Move Quickly

LAS VEGAS — The coalition of utility commissioners that this summer proposed the creation of an independent Western RTO is wasting no time getting the project up and running.

That spells good news for CAISO, one of the key beneficiaries of the effort as it seeks to stand up its Extended Day-Ahead Market (EDAM) in the face of increasing competition for participants from SPP’s Markets+ offering.

The group, which includes regulators from Arizona, California, New Mexico, Oregon and Washington, on Tuesday issued a notice inviting a broad range of stakeholders from across the Western U.S. and Canada to “help build” Phase 1 of the effort, which will include “deciding on the form, mission, and scope of an entity with independent, West-wide governance.”

“This effort, the ‘West-Wide Governance Pathway Initiative,’ seeks to build on the benefits of [CAISO’s] Western Energy Imbalance Market (EIM), realize the potential benefits of an extensive footprint for the Extended Day-Ahead Market (EDAM), and enable a path forward for a potential West-wide fully organized market (a Regional Transmission Organization or RTO), should participants in this effort so choose,” the notice said.

The regulators first floated the RTO plan in a July letter just as the growing competition between CAISO and SPP raised the prospect that the West could become divided into two day-ahead markets that eventually would evolve into separate RTOs.

The commissioners’ proposal cited studies showing the West would reap the greatest economic and environmental benefits from a single market — and one that pointedly includes CAISO. The plan seeks to create a workaround for an issue that for years has bogged down CAISO’s attempts to expand into an RTO: its state-run governance.  (See Regulators Propose New Independent Western RTO.)

‘With All Urgency’

In the notice issued Tuesday, the regulators made clear they plan to pursue an aggressive timeline for laying the groundwork for the effort. They seek to “finalize key elements of the independent entity’s governance” by December and to select and seat a founding board by January. The Regulatory Assistance Project will provide “staffing and facilitation” for the initial phase, which will be led by Carl Linvill and Jennifer Gardner, both former members of the WEIM Governing Body.

“Funding derived exclusively from 501(c)(3) sources will support the initial work of this initiative,” the notice said. “This arrangement will be evaluated over time and will likely require supplementation as the workload intensifies. We commit to ensuring that the initiative has access to consultants and advisors on the broad array of topics that may become relevant as the work proceeds.”

The commissioners acknowledged that Phase 1 of the effort “is being facilitated outside of any existing organization or decision-making process and asked stakeholders to provide feedback on a series of questions — outlined in the notice — about how to structure the stakeholder process. Comments are due by Sept. 11.

“I think there’s a lot of work in front of us to make sure that stakeholders are widely engaged, that public power has a seat at the table, [and] that the [investor-owned utilities], the public interest organizations, the consumer advocates are  all invited into that conversation and that it moves with all urgency,” Oregon Public Utility Commissioner Letha Tawney, a signatory of the July letter, said Wednesday in Las Vegas at a forum focused on CAISO’s EDAM.

“We propose a bit of a scope, decisions about a legal entity, a charter, a mission, a founding board. That’s ambitious,” Tawney said. “I’d love to hear, is that sufficient? Is it insufficient? Given how ambitious it is, is something else feasible?”

Speaking at the EDAM forum, California Public Utilities Commission President Alice Reynolds said the July letter was intended to take the problem of CAISO’s governance off the table. The process ahead, she said, will need to examine what an independent entity “needs to look like.”

“How we can build this so that there is an entity to provide the full range of options for regional cooperation, recognizing that we may not ultimately use all of them. Some of us might, some of us might not, but at least we’d have a path to the full range of benefits,” said Reynolds, who also signed the July letter.

“How can we get there as a region and really confront this 500-pound gorilla in the room of governance?” Arizona Corporation Commission member Kevin Thompson said at the forum. “If we could solve that issue, then let’s solve it and move on for the benefit of not only our utilities, but the benefit of our consumers as well.”

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NYISO Proposes $41.62M Project Budget for 2024

NYISO faced stakeholder scrutiny Wednesday after presenting its final project budget recommendations for next year to the Budget and Priorities Working Group, amounting to an estimated $41.62 million total.

The ISO is proposing 29 market and 37 enterprise project candidates. Although the total is fewer than was suggested when NYISO last shared the proposed budget, it is still about 30% higher than this year’s.

Labor costs are the primary driver behind the budget’s increase, rising from $13.74 million this year to an estimated $18.03 million.

Breakdown of NYISO’s proposed budget for next year compared to previous years | NYISO

Kevin Lang, partner at Couch White, expressed concerns about the hike, asking how the ISO planned to mitigate rising costs and whether it had the bandwidth to manage the projects or would require help from outside consultants.

“I recognize that some of these [projects] are relatively small and some will be a larger effort, but there are many more projects here than you had in the last few years,” Lang said.

Kevin Pytel, senior manager of product and project management at NYISO, conveyed confidence, saying, “We are comfortable with the workload; it is a lot, and we’re awfully stretching ourselves, but we do feel like it is achievable.”

Lang next asked how NYISO planned to reduce the cost of future budgets.

NYISO CFO Cheryl Hussey told Lang that “to address the increase in the cost of the product portfolio for next year, we’ll be proposing to increase our level of financing by $10 million in 2024,” a request that is under review by the New York Public Service Commission.

Pytel committed to a project prioritization process re-evaluation this fall, aiming for collaborative discussion on potential enhancements. Feedback on the proposed budget or the prioritization process can be sent to kpytel@nyiso.com.

The proposed budget will be revisited at the BPWG meeting Sept. 11, and NYISO aims to obtain budget approval at the Management Committee meeting Sept. 27.

July Operations Report

NYISO CEO Rich Dewey reported to the MC meeting, which also was held Wednesday, that it had been a “cool, long and wet summer” that saw much lower monthly energy prices compared to last year.

NYISO COO Rick Gonzales said the summer’s peak load of 28,735 MW came July 28, noting how August has been particularly mild so far. Additionally, 20 MW of nameplate front-of-meter solar resources were added since June. (See NYISO Operating Committee Briefs: July 22, 2023.)

Working Capital Fund Rebalance

The MC also voted to recommend that NYISO’s proposed revisions to how it rebalances customer contributions to its working capital fund be approved by the Board of Directors.

Every January, NYISO calculates each customer’s contribution to the fund based on the previous year and issues refunds that include interest in February. The ISO wants to rebalance the fund twice a year, in January and July, based on the prior six months. The rebalancing would better reflect recent conditions, and customers would receive refunds more quickly, it said.

The Business Issues Committee has already endorsed the proposal, and the ISO plans to present it to the board for Oct. 16. (See “Working Capital Fund Rebalance,” NYISO Business Issues Committee Briefs: Aug. 16, 2023.) If greenlit, the revisions will be implemented starting in July 2024.