The Virginia State Corporation Commission last week ruled that Dominion Energy overstepped its authority in requiring distributed solar for large customers to go through new processes that led to spikes in the cost of installation.
The Virginia Distributed Solar Alliance filed a complaint against the new procedures in June, alleging they overstepped the regulated utility’s authority, as the SCC has been looking into the issues around interconnection of distributed sources in other cases. The SCC last approved interconnection rules back in 2020 and it is now looking at additional changes.
The commission on Aug. 30 agreed to suspend the parameters and interconnection agreements until it wraps up its open proceedings looking into the issues, but it declined to “address the myriad of additional relief” sought by the solar group.
The group’s other requests can be taken up in other proceedings, the SCC said. It also noted that it was not taking lightly Dominion’s claims about safety and reliability, but that it lacked authority to implement the new processes without a prior order.
“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system; this may include, but need not be limited to, seeking specific authority from this commission in one or more formal proceedings,” the commission said.
The utility adopted new parameters for projects between 250 kW and 1 MW and projects that range from 1 to 3 MW in December 2022, but the solar group’s complaint focused on their impact on projects below 1 MW, which are midsized, nonresidential projects. The complaint alleged that the new rules have led to costs, delays and barriers to adding such distributed generation around Virginia.
The rules that were suspended by the SCC led to “unprecedented” costs and delays by potentially requiring distributed solar to pay for substation upgrades and dark fiber cable and relay panel equipment. Dark fiber costs between $150,000 and $200,000/mile; relay panels can cost $250,000 for equipment and potentially more than double that for engineering, mobilization and construction management.
The complaint listed a number of anecdotes, including one at the James River Juvenile Detention Center for Henrico County, where Dominion estimated $2.25 million in preliminary costs for a 686-kW system. Prince William County Schools faced similar costs on a 987-kW array it was planning. Both projects, and others owned by private firms, proved too expensive with the extra costs that Dominion assessed under the now-suspended rules.
Dominion had argued in a filing last month that it needs to update the rules as distributed generation has grown rapidly in Virginia since a law passed expanding its net energy metering program.
“As a result of these changes, more net metering generation, with higher capacity ratings, are now rapidly developing and penetrating the company’s electric power system,” the firm said. “The company has been tasked with integrating more net metering distributed energy resources, with higher capacity ratings, that are now permitted to produce up to 150% of the customer’s expected annual energy consumption.”
The parameters suspended by the SCC were meant to ensure Dominion’s ability to specify the equipment and technical specifications needed to establish safe and reliable interconnection, the company said.
MISO’s Independent Market Monitor took his concerns to stakeholders last week over what he deems unrealistic fleet assumptions in MISO’s long-range transmission planning.
MISO Independent Market Monitor David Patton delivered a presentation at an Aug. 31 long-range transmission plan (LRTP) teleconference to let stakeholders know he’s concerned MISO’s long-range transmission planning could upend market functions. He said the issue is serious enough for him to delve into MISO’s transmission planning matters when usually he’s confined to market matters.
“The performance of the market is greatly impacted by out-of-market investments … coordinated by MISO,” Patton said. He said overblown transmission investments can “fundamentally” affect locational marginal prices and ancillary services.
Patton said the capacity expansion prediction MISO is using to develop its second LRTP portfolio contains an overestimated amount of intermittent, renewable generation and an exaggerated amount of dispatchable generation retirements.
“Planning to that future, I think is highly problematic,” Patton said.
MISO would come up with a “very different set of future transmission needs” if it includes a more realistic fleet projection that includes battery storage, hybrid storage, and renewable resources and new natural gas generation, he said.
Patton’s criticisms are contained in this year’s State of the Market report. He also appeared in front of MISO board members to critique MISO’s transmission planning future. Board members have questioned Patton’s departure from markets into transmission planning. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)
Minnesota Public Utilities Commission staff member Hwikwon Ham said he had serious concerns with Patton’s critique of transmission planning. He asked what’s keeping the IMM from weighing in on states’ integrated resource planning, because that also affects MISO markets.
Ham said MISO’s second LTRP portfolio’s assumptions are based directly on states’ emissions reductions plans.
“You are directly defying that outcome,” he said.
American Transmission Co.’s Bob McKee agreed MISO’s futures use “actual” state plans and planned retirements.
Patton said he wasn’t trying to question state directives. But he said his analysis shows a 2040 fleet mix that contains 108 GW less solar and wind resources than MISO is planning for. He said MISO states still could achieve their official emissions reduction targets even with the absent, hypothetical intermittent resources. Patton said he didn’t account for “announcements made by governors that may or may not make their way into legislation.”
MISO expects it will add 369 GW of new, mostly renewable resources by 2042, bringing its total installed capacity to 466 GW. However, only 202 GW of that capacity is accredited; staff assumes a declining effective load-carrying capability for the renewable additions. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)
Patton also said he found MISO’s forecast that it will have 29 GW of flexible resources — including green hydrogen, long-duration battery storage, small modular nuclear reactors and reciprocating internal combustion engines — highly unrealistic. He questioned whether those technologies will be commercially available by the 2040s.
Patton also said half of MISO’s 13 states don’t have definitive decarbonization mandates. He said MISO shouldn’t assume members don’t build dispatchable gas resources between now and 2030.
But some stakeholders said they viewed Patton’s view as more environmentally harmful and more expensive to ratepayers, because of an expansion of gas infrastructure. Some also said it was disrespectful for Patton to show up to a planning meeting so late in the game to advocate for a rethink of MISO’s transmission planning future.
Patton said he will make a point to participate in MISO’s LRTP benefit analysis going forward.
Sustainable FERC Project attorney Lauren Azar said she worried Patton’s transmission analysis based on a concern for the market is shortsighted because the market only sends short-term signal and doesn’t indicate “the type of grid we’re going to need in 2042, or even 2035.”
“MISO is [a] leader in the nation in building 20 years out,” Azar said.
But Patton warned about the dangers of overbuilding transmission based on a flawed view of future capacity.
“If we adopt a future that’s not realistic, I don’t think we can be confident in that,” he responded.
Southern Renewable Energy Association’s Andy Kowalczyk asked Patton to consider MISO may be running the risk of underbuilding the transmission system, which also would raise costs for ratepayers. He said he didn’t think battery storage would “absorb” the need for new transmission because it still needs to charge from and dispatch to the system.
Sustainable FERC Project’s Natalie McIntire said she was skeptical of Patton’s analysis that MISO states could achieve a dramatic, more-than-90% carbon reduction by 2042 while removing 108 GW of renewable energy from the equation.
But North Dakota Public Service Commissioner Julie Fedorchak said she thought it was worthwhile for Patton to question MISO’s fleet assumptions when the second LRTP portfolio could cost as much as $30 billion.
“We absolutely need more analysis instead of less,” she said.
Mississippi Public Service Commission consultant Bill Booth called for MISO to take a fresh look at its battery storage addition assumptions.
“This is an expensive endeavor. We cannot afford to build wasteful transmission. …These are costs that are going to be borne by ratepayers, and we need to make sure they’re necessary and needed and the best thing for the footprint,” said Kavita Maini, an energy consultant representing MISO end-use customers.
MISO Responds
MISO Vice President of System Planning Aubrey Johnson said MISO in the past has been accused of not “being big or bold enough in transmission planning,” especially in its 2011 multivalue transmission portfolio. He said MISO is embarking on “least regrets” long-range transmission planning.
Johnson reminded stakeholders that the LRTP portfolios are being developed to resolve major regional system issues, not ensure the interconnection of an additional 369 GW, or ensure a certain generation mix. He said MISO’s planning future is meant to reflect members’ resource planning.
“It’s not the goal to maximize transmission building, but to maximize the value of the transmission we recommend,” Johnson said. He added he’s confident MISO will advance the most valuable second LRTP possible.
FERC has ruled it’s appropriate for MISO to continue to preclude renewable resources from providing ancillary services in its markets, countering a solar trade group’s complaint.
FERC said the Solar Energy Industries Association (SEIA) didn’t present evidence that MISO’s policy of barring renewable output from ancillary services was producing unfair rates (EL23-28).
In an Aug. 31 order, the commission said much like its recent order authorizing MISO’s ban on wind and solar generation from supplying ramping capability, it remains the case that renewables rarely are the most economic choice to supply operating reserves because their locations exacerbate already binding transmission constraints. (See related story, FERC: MISO Can Ban Intermittent Resources from Providing Ramp.)
SEIA lodged the complaint early this year in part because of MISO’s effort to bar renewables from furnishing ramping. (See Solar Trade Group Challenges MISO Ban on Renewable Ancillary Services.) The group argued that MISO’s dispatchable intermittent resources are operationally capable of providing regulation service, spinning reserves and supplemental reserves and that MISO’s market rules today discriminate against some resources because they’re tailored to the large, centralized power plants of the past. It also said instating renewables’ eligibility for such services would foster competition.
But FERC said SEIA didn’t demonstrate that renewables “can reliably deliver the ancillary services they are cleared to provide to the MISO market in a manner comparable” with other resources.
The commission acknowledged MISO’s current market clearing software isn’t sophisticated enough to consider locations of resources and nearby congestion rendering them non-deliverable. It said if MISO were to clear operating reserves from renewable sources, congestion would prevent them from making it to market in most cases. Thus, allowing procurement would create a reliability issue and payments to unhelpful resources, FERC decided.
The commission also agreed with MISO that it’s far more lucrative for renewable resources to provide energy over ancillary services.
Lastly, FERC said SEIA’s arguments differed from the commission’s previous regulations requiring open access transmission service and establishing separate performance and capacity payments for frequency regulation service, and its ruling against the undue discrimination of electric storage resources.
“Those orders did not require that every resource type must be allowed to provide such services,” FERC said.
FERC said though it’s “undisputed” MISO’s tariff treats renewable and nonrenewable resources differently with respect to ancillary services, SEIA didn’t prove that renewable and nonrenewable resources are “similarly situated” because when renewables are cleared to provide ancillary services, they’re trapped behind a transmission constraint.
As with their order blocking MISO renewables from providing ramp capability, Chairman Willie Phillips and Commissioner Allison Clements issued a joint statement to emphasize that the order was limited. The two said MISO’s market dynamics are set to change — and the snub likely will be temporary — as renewable energy becomes more prevalent.
“We strongly urge MISO to continue to improve and enhance the software on which its markets rely. Both MISO and the commission recognize the limitations of MISO’s current software, and the record suggests that these shortcomings are contributing to problems that go beyond [renewable] integration alone,” Phillips and Clements wrote. “We anticipate the continued development of these resources and encourage MISO to be ready for them as they come online.” They said MISO should devise ways to account for locational congestion in its software when selecting resources.
CAISO is planning ahead for a solar eclipse that will abruptly slash solar power across much of California the morning of Oct. 14.
CAISO successfully managed the drop in solar output during a total eclipse on Aug. 21, 2017. But since then, grid-scale solar within the CAISO footprint has increased from 10,000 MW to 16,500 MW. (See Grid Operators Manage Solar Eclipse.)
And behind-the-meter solar has grown from 5,700 MW to 14,350 MW.
“The October 2023 eclipse will be more impactful than the 2017 eclipse because of the growth in solar capacity since 2017,” CAISO said in a technical bulletin issued last week.
In response, CAISO has scheduled a series of meetings — including a workshop on Sept. 5.
Outreach to Western Energy Imbalance Market entities is planned, as CAISO said coordination across the WEIM is critical to ensure optimal market dispatch during the eclipse.
CAISO is planning additional reserve procurement, a step it also took to prepare for the 2017 eclipse. The ISO will consider restricting maintenance operations around the time of the eclipse, to reduce the risk of an “inadvertent issue” occurring during maintenance work.
Another option would be to implement a Flex Alert or activate demand response programs during the eclipse. CAISO said it probably won’t need to do that, “due to the eclipse occurring on a weekend when loads are typically lower.”
Blocking the Sun
During the so-called Great American Eclipse in August 2017, grid-connected solar generation in CAISO territory dropped by more than 3,500 MW in about an hour. CAISO replaced the lost solar power with electricity from imports, hydropower and natural gas power plants. Consumers conserved electricity during the eclipse to relieve stress on the grid.
The 2017 eclipse was on a Monday, from about 9 a.m. to noon in California.
In contrast to that eclipse, the event on Saturday, Oct. 14, will be an annular eclipse, in which the moon will block much of the sun but leave an outer ring.
Large parts of Oregon, Nevada, Utah and New Mexico, and small parts of California and Arizona, will see the maximum impact of next month’s eclipse, with about 90% of the sun obscured. Much of California will see lesser amounts of sun obscuration, in the 70% to 80% range.
The Oct. 14 eclipse will last from about 8:05 a.m. to 11 a.m. in CAISO territory. At the peak, around 9:30 a.m., grid-scale solar generation will drop to 12% to 23% of capacity, CAISO said. Solar production won’t be completely cut off, but will fall to a low of about 3,023 MW at 9:26 a.m.
Output will also be reduced for behind-the-meter rooftop solar, leading to increased load. The maximum impact to load will be a 4,843-MW increase at 9:15 a.m., compared with normal clear-sky conditions, according to CAISO’s forecast.
Because the eclipse will occur on a Saturday, loads will be lighter than they would be on a weekday.
Ramp-up Concerns
One of CAISO’s concerns is the steep ramp up in solar power after the eclipse peaks. The eclipse will end just as solar sites are reaching their midday production maximum, the ISO noted.
“The period after the eclipse maximum to the end of the eclipse … is the period of operational interest the CAISO will study to ensure adequate supplies of generation [reserves] are available to mitigate any adverse effects of the anticipated steep up-ramp in solar production,” CAISO said in its technical bulletin.
CAISO said it will coordinate with hydro and battery resources to help with potentially large ramps.
The bulletin models eclipse impacts on a clear-sky day, which CAISO said represents a “high impact” scenario. Impacts will be less if Oct. 14 is a cloudy day.
CAISO plans to send out messages through its market notification system before and during the event.
“This message is to serve as a reminder that the solar eclipse will take place on Oct. 14, 2023, from 8:05 to 11:05 PDT,” one sample message reads. “This is a unique event for the ISO BA, during which approximately 9,700 MW of solar generation will rapidly go away and then return within the span of less than three hours. Your cooperation and support throughout the event will help to ensure grid reliability.”
In light of stressed-out supply chains and a bogged-down study process, MISO has agreed to re-evaluate its rules around commercial operation dates in its interconnection queue.
Stakeholders and staff plan to discuss extending the grace periods around commercial operation dates at upcoming meetings of the Interconnection Process Working Group (IPWG).
MISO policy requires its interconnection customers’ generator interconnection agreements (GIAs) contain a commercial operation date that’s within three years of the date originally requested in their queue applications. MISO additionally allows an up to three-year extension of the commercial operation date in the initial GIA. When customers can’t meet either, MISO can terminate the GIA and generator developers lose their place in line unless they can secure a waiver of their commercial operation dates from FERC.
Last week, EDP Renewables’ David Mindham said supply chain troubles and delays in MISO’s studies of generation projects mean that projects regularly take longer than the allotted six years from originally planned commercial operations and often require FERC waivers, which create uncertainty.
Mindham raised the issue at the Aug. 30 meeting of the Planning Advisory Committee, which ultimately assigned the issue to the IPWG for consideration.
Mindham said MISO should consider extending its COD deadlines in its Tariff so they’re feasible. He said transmission owners often don’t have network upgrades ready until well into the second extension. Mindham said current wait times for equipment like breakers can last three and a half years and “eat away at the three-year grace period.”
“There are dozens of these projects that will require FERC waivers. This problem doesn’t seem to be going away. If anything, it seems to be getting worse on the transmission owners’ end, and it’s going to take several years for that to get caught up,” he said. “… The commercial operation date should have some meaning. It should be a date that developers can reasonably meet.”
Multiple MISO interconnection customers have sought commercial operation date waivers with FERC since the pandemic began and strained supply chains. Mindham said an extension could cut down on the need for developers to seek future waivers.
LAS VEGAS — The stars may not yet have aligned in favor of CAISO in the contest to bring an organized electricity market to the West, but key players in the industry appeared to be doing just that last week at an ISO event to celebrate the progress of its Extended Day-Ahead Market (EDAM).
Wednesday’s EDAM Forum at Resorts World on the Las Vegas Strip attracted 240 in-person attendees and about 300 participants online, a CAISO official said. The packed agenda included a CEO roundtable, a panel of Western utility commissioners, an in-depth presentation on potential EDAM benefits and a discussion about evolving markets in the West.
The ISO convened the forum just a week after CAISO submitted to FERC its EDAM tariff and associated day-ahead market changes designed to increase rewards for flexible resources and reduce load imbalances between the day-ahead and real-time markets. (See CAISO Files EDAM Proposal with FERC.)
And, accidentally or not, the event also coincided with two important developments.
The first was a notice issued by the coalition of utility regulators who this summer proposed the creation of a Western RTO that would be independent of CAISO’s governance while still building on the ISO’s Western Energy Imbalance Market (WEIM) and the EDAM. The document outlined an aggressive timeline for developing the governing framework and seating a board of directors for the new entity, signaling that the backers are moving urgently to build a market structure that ensures the participation of California and increases the likelihood of a single, seamless Western market. (See Backers of Independent Western RTO Seek to Move Quickly.)
The second was the Balancing Authority of Northern California’s (BANC) announcement that it will advise its publicly owned utility members to join the EDAM over SPP’s competing Markets+ day-ahead offering. Accompanying that was a parallel announcement that the board of BANC’s largest member, Sacramento Municipal Utility District, approved the utility’s request to join the EDAM. (See BANC Moving to Join CAISO’s EDAM.)
Scott Miller, executive director of the Western Power Trading Forum, expressed surprise at what he saw at the event.
“This really changes the calculus of my thinking around” Western markets development, Miller told RTO Insider immediately after the forum concluded.
“It was the general positivity — even from CEOs whose folks are involved in Markets+ — that struck me as interesting,” Miller said later in an email. “The fact that a ‘shared governance of EDAM with CAISO’ might be acceptable was a bit of a shift, although the shared governance might prove a problem in an RTO setting where transmission operations are turned over to the RTO.”
‘Tremendous Benefit’
During the CEO roundtable, Pacific Power CEO Stefan Bird explained why the utility’s parent, PacifiCorp, the first entity to join the WEIM in 2014, also decided to become the first participant in the EDAM.
“We want to use as much renewable power that’s free — has no fuel cost — as much as possible and avoid those emissions,” he said.
“I was part of that group running around the West, I don’t know, 10-plus years ago, and dreaming about … how cool it would be if we could just coordinate better and be more efficient in how we leverage the abundance that we have across the West, and so proud of how far we’ve come and excited about the next steps,” Bird said.
Idaho Power CEO Lisa Grow offered “profound thanks” to CAISO for developing the EDAM.
“I have been in this industry for 36 years, and I have participated in every single effort we’ve had to create an RTO, or some sort of organized market, and we just never quite got there,” she said. “I think that the demonstration that we can take incremental steps is the only thing that we’ve seen work.”
Grow said the industry’s transition to clean energy will require the region to “optimize the system we have.” She also questioned whether there’s a need for a full RTO — at least in the near term.
Idaho Power doesn’t “have legislative or PUC-mandated things that we have to do towards an RTO, so we can kind of watch how this goes,” she said.
NV Energy CEO Doug Cannon gave a “shoutout” to CAISO for its responsiveness in developing a WEIM rule change that allows a participant that fails the market’s resource sufficiency test during a trading interval to acquire energy within the market rather than just being shut out.
“That’s a tremendous benefit,” Cannon said. “What we were concerned about is, you’ve got somebody who’s already kind of down. Why are we pushing them further down by not letting them get access to this broader market? Instead, as a West, let’s come together and give that person an option to pick [energy] up. Now, they have to carry their weight, they’ve got to pay the price, but let’s help them through that challenging time. And the California ISO came to the table and helped deliver product that really helped there.”
Jacob Tetlow, executive vice president of operations at Arizona Public Service, said “this summer has been incredibly challenging for us.” The summer featured a 30-day stretch of temperatures exceeding 110 degrees Fahrenheit in Phoenix, leading the utility to smash its previous peak load record of 7,600 MW by nearly 600 MW.
“To me, the Energy Imbalance Market is a very helpful tool. It creates liquidity in the market. It puts resources in that might not have otherwise been available. That’s an efficiency gain,” Tetlow said.
But Tetlow also cautioned that the WEIM can’t be relied on as a resource adequacy tool, given that the market’s operations cut some of APS’ hour-ahead schedules and low-priority transmission in July.
“So, it absolutely helps, but it can’t be the tool to make sure you’re resource sufficient for your customers,” he said.
“No market is actually a substitute for a solid foundation of resource adequacy,” said CAISO CEO Elliot Mainzer. “RA — that’s the bottom foundation layer. And that’s why it’s so important for all of us to be taking those steps to get to solid resource adequacy to meet those planning standards. The market really is an optimization tool.”
Mainzer pointed to instances in July and August when it was “kind of hot everywhere” in the West, and the bilateral day-ahead market did not provide enough liquidity to cover all the short positions heading into real time in the WEIM.
While some low-priority exports had to be curtailed, he said, “we were then able to work together to foster maximum liquidity into the hourly markets, and then we were able to sit there and watch the Energy Imbalance Market cycling power across the West, particularly most of it heading certainly not California’s direction, [but] at that point in certain places that were really on the edge.”
Solving for The ‘Future Everything’
Of the CEOs participating in the roundtable, the Bonneville Power Administration’s John Hairston was the most reserved in his assessment of CAISO, the WEIM and the EDAM.
While Hairston acknowledged BPA has seen benefits since joining the WEIM in 2022, he also alluded to a running complaint among Northwest hydroelectric producers that the market undervalues the attributes of their resources. He said the agency’s portfolio of 31 hydroelectric dams is a “foundational piece to the clean energy transformation” in the West because of its flexibility and lack of greenhouse gas emissions.
“Hydro is highly responsive, so as you add renewables to the resource mix, you’re going to have to have that instantaneous response,” he said. “And so how we manage the system and reserve it is going to be critically important. And how we also allocate it to markets — participate in markets — will also allow us to figure out how to optimize this incredible resource for attacking climate change and dealing with meeting these renewable portfolio requirements in the most efficient manner.”
When BPA this summer embarked on a public process to determine whether to join the EDAM or Markets+, it signaled that its near-term decision on a day-ahead market could hinge on a longer-term evaluation of joining an entity that — unlike CAISO — promises a governance structure that meets the federal agency’s statutory requirement for independence. (See Regulators Propose New Independent Western RTO.)
“When we joined EIM, we were really clear,” Hairston said. “We came out of our public process and said the governance structure was sufficient but wasn’t preferred. The joint authority model [with the CAISO and WEIM boards sharing decisional authority] has worked, but at the end of the day is not independent, and that’s what we’re looking for in this next step.”
Hairston said he “applauded” Western regulators for putting out an independent RTO proposal “that has some legs,” but said the process will be “complex.”
“We need answers now around governance,” he said.
“I get that we have unanswered questions,” Grow said. “I think we have to be careful not trying to solve for the future everything, because it will collapse under its own weight.”
“The governance issue is a tricky one,” said Jim Shetler, general manager of BANC, which sits squarely inside CAISO as a separate BA. “I like to say we’ve lived in the belly of the beast for the last 25 years and we’ve learned to figure out how to manage that.”
“I also like to say I think the ISO today is a very different animal than the ISO 20 years ago. Clearly a much more collaborative organization,” Shetler said.
Mainzer attempted to drive that point home in his remarks wrapping up the forum.
“We’re just super-motivated to make sure that people feel that they can walk away from a CAISO stakeholder process and say, ‘Look, that is really fabulous, and we feel heard, and we feel acknowledged,’” he said.
He also gave a nod to the regulators’ RTO proposal, acknowledging that for many Western stakeholders, the “pathway to independent governance is a critical success variable.”
“And I’m just appreciative of the work of our regulatory community, to start taking this issue on with seriousness and obviously recognize the importance of getting the right people at the table, open and transparent,” he said.
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.
VCMRR034: provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.
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.
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.”
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.
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.”
