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November 14, 2024

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Texas PUC Closes 1st Phase of Market Overhaul

Texas regulators last week celebrated the closure of the first phase of their blueprint for reliability reforms to the ERCOT grid, cautioning that it’s only a first step.

The Public Utility Commission closed two dockets during its Feb. 1 open meeting, 52373 and 53298. The former encompassed initial revisions to the market design, and the latter covered the development of a firm-fuel supply service.

“The ERCOT grid is more reliable than it’s ever been, and getting to this point has been a total team effort,” PUC Chair Thomas Gleeson said in a statement, thanking ERCOT staff, industry stakeholders and lawmakers. “This doesn’t mean we’re done improving the grid. We’re just closing the book on this first chapter.”

A result of legislation passed after the devastating 2021 winter storm, the first phase reforms included two expansions of the PUC’s weatherization rules, requirements for generators to secure backup fuel supplies’ new consumer protection measures and market changes that focused on price stability and reliability.

In a memo, commission staff said modifications to the operating reserve demand curve, emergency response service reforms, and development of fast frequency response service and ERCOT contingency reserve service have been completed.

They recommended new projects be opened for a firm-fuel product and voltage support compensation. Two other projects are in progress: demand response and setting higher performance standards for energy efficiency programs. The PUC already has received approval for three positions to manage the latter project.

Commissioner Jimmy Glotfelty said he supported the voltage-support docket.

“This is becoming more and more an issue as we have more inverter-based resources. This might be an issue that we need to address in the future, and it’d be good to get positions on it.”

Meanwhile, several Phase 2 projects already are running full bore.

The commission reacted positively to staff’s suggestion that the interim value of lost load (VoLL) that will be used in ERCOT’s reliability standard be set at $25,000/MWh and that any study using the metric as an input conduct sensitivity analysis, varying VoLL between $20,000/MWh and $70,000/MWh (55837).

VoLL was reduced to $5,000/MWh from $9,000/MWh and decoupled from the system-wide offer cap after high prices during the winter storm. According to the grid operator’s market monitor, the $9,000 cap resulted in $16 billion of incorrectly priced market transactions during the storm. Staff noted that Potomac Economics said in its 2022 state-of-the-market report that the $5,000 value “likely underestimates VoLL by a substantial amount.”

Staff carefully reiterated the interim VoLL value is for study purposes only and will not affect consumers’ cost of electricity. The Brattle Group is beginning a survey of ERCOT retail customers in March to determine their value of lost load. (See “VoLL Study to Begin,” Texas PUC Sends ESR Change back to ERCOT.)

Staff also presented a draft scoping document for a review of ancillary services, as required under the Public Utility Regulatory Act. The review’s report, a collaborative effort with ERCOT and Potomac Economics, is due to the PUC in September (55845).

Protocol Changes Approved

The commission also approved nine protocol changes approved by ERCOT’s Board of Directors, but not before probing one revision (NPRR1181) that requires qualified scheduling entities to notify the grid operator when inventories drop to critical levels (55445).

“These are things that ERCOT wants to know, but these are not critical for market operations,” Glotfelty said. “It’s the individual generator’s responsibility to know how much coal they have, how much energy they have. … I think this is kind of an overreach, quite frankly.”

Dan Woodfin, ERCOT’s vice president of system operations, agreed the NPRR isn’t needed for market operations. He reminded commissioners that as the region’s reliability coordinator, the grid operator needs situational awareness of future reliability risks.

“If we’ve got a plant that has coal, they’re running out of coal or maybe some rail issue or something, we shouldn’t be approving transmission outages that depend on one or more of those units at that plant being available,” he said. “That’s something where that information is critical to us to be able to make good decisions and avoid reliability problems.”

Gleeson Chairs 1st Meeting

The meeting marked Gleeson’s first as PUC chair. He was appointed to the position by Gov. Greg Abbott (R) last month. (See Abbott Names PUC Executive Director as Chair.)

“I’ve spent almost my entire professional career at this agency. I’ll be honest, when I started here 15 years ago, this was definitely not something I saw in my career plan,” he said.

Gleeson had been the PUC’s executive director since December 2020. He replaces Kathleen Jackson, who was named interim chair when Peter Lake resigned last June.

“We’re proud to have you up here with us,” Glotfelty said. “We’re excited to see you move from representing the entirety of the staff to representing the entirety of all of the people in the state, and we know you’ll do a great job each and every way.”

“It’s quite the transition to having about four people in my office to 240 people,” Gleeson said.

Following a brief executive session, the commissioners approved the appointment of Connie Corona, the PUC’s deputy executive director, as interim executive director. Corona first joined the commission in 1997, returning in 2017 after a 14-year stint in NRG Energy’s regulatory affairs group.

The commissioners also agreed to request the state legislative board set their salaries at $225,000 for the remainder of the 2024 fiscal year and at $230,000 for 2025. The request will include setting the executive director’s salary at $245,559 for the remainder of 2024 and $257,858 for the 2025 fiscal year.

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NM Utilities to Pursue More Analysis Before Day-ahead Decision

Two New Mexico utilities said they need to conduct more analysis before they make a choice between competing day-ahead markets in the West, despite the results from a key study on the financial impacts.

The comments from representatives of Public Service Company of New Mexico (PNM) and El Paso Electric (EPE) came during a Jan. 25 workshop hosted by the New Mexico Public Regulation Commission. 

The focus of the workshop was a cost-benefit study conducted for the Western Markets Exploratory Group (WMEG) by Energy+Environmental Economics (E3). 

E3 analyzed two different footprints across the West for participation in either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+. The study examined production costs under two different market participation footprints as compared to a business-as-usual scenario. 

EDAM and Markets+ are both expected to launch in 2026, and potential participants are scrambling to understand what choice would be best. 

Emmanuel Villalobos, director of market development and resource strategy at EPE, said the utility is planning “very involved, robust studies” as a follow-up to the WMEG analysis. 

The next step will be to layer onto the WMEG study real-world operational constraints and resource adequacy considerations, he said. That work, expected to take place this year, will be followed by a gap analysis. EPE expects to choose a day-ahead market in 2025. 

Kelsey Martinez, PNM’s director of regional markets and transmission strategy, said in a previous PRC workshop that the footprint of each day-ahead market would be a major deciding factor — a point she reiterated during the latest workshop. (See New Mexico Contemplates Organized Market Choice.) 

“The market footprint is a key factor in determining the realization of a lot of the benefits that come with day-ahead market participation,’ Martinez said. “So [are] the production and trade benefits, the resource diversity and increased reliability as well.” 

Martinez called the WMEG study “one tool in our toolbox.” She said PNM is gathering information on each market’s rules for third-party transmission usage and the rules’ impact on PNM benefits. 

Another issue, she said, is the likelihood that either market will evolve into an RTO, which PNM strongly supports. 

Martinez said PNM is following closely the West-Wide Governance Pathways Initiative for changes that might allow “wider adoption of the CAISO markets and evolution of those markets.” (See Western RTO Initiative Outlines Governance Options.) 

Footprint Analysis

The workshop was part of the PRC’s effort to develop guiding principles for utilities when deciding whether to join a day-ahead market or RTO. (See NM Commission to Set Standards for RTO, Day-ahead Participation.) More workshops on the topic are possible. 

During the workshop, Jack Moore of E3 gave an overview of the WMEG cost-benefit study. E3 presented the findings previously. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.) 

One of the two footprints evaluated was the EDAM Bookend, a single combined day-ahead and real-time market covering the entire Western Interconnection except for British Columbia and Alberta.  

Under the EDAM Bookend, the West as a whole would save $60 million a year compared with a business-as-usual case, although results varied among individual balancing area authorities.  

The second scenario is called a Main Split footprint, in which most of the West would participate in Markets+, but CAISO, PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District would join EDAM. 

In the Main Split, West-wide costs would rise by $221 million relative to business as usual. Results again varied by agency. 

‘EDAM Island’

PNM and EPE asked E3 to analyze an additional scenario similar to the main split footprint, but in which New Mexico goes with EDAM rather than Markets+. This would create a “New Mexico EDAM island,” with neighboring Arizona in Markets+. The scenario is just a “what if,” E3 said, and not an indication of which market the states will ultimately join. 

In the EDAM Island scenario, a New Mexico-California transaction might face wheeling charges between New Mexico and Arizona, and again from Arizona to California. The impacts potentially could be reduced if transmission arrangements or market-to-market coordination agreements were in place, E3 said, but such agreements weren’t included in the modeling.

E3’s analysis found PNM would see a $41 million cost increase in the EDAM Island scenario compared with business as usual, excluding wheeling revenue. PNM was modeled as being a “heavy exporter” of low-cost wind and solar resources. 

For EPE, costs would decrease by $23 million in the EDAM Island scenario, as the utility would be able to buy energy from the PNM zone at lower prices. 

WEIM Impacts

PNM and EPE both are participants in CAISO’s Western Energy Imbalance Market (WEIM), a regional real-time energy market. 

Martinez of PNM noted that selection of a day-ahead market would be “bundled” with participation in a real-time market. So if PNM decided to join Markets+, the utility would leave WEIM and instead enter SPP’s real-time market. 

From the time it was launched in 2014 through the end of 2023, WEIM participants achieved $5 billion in benefits, including $392 million in benefits in the fourth quarter of 2023 among its 22 participants, CAISO reported Jan. 31. 

Fourth-quarter benefits were $6.1 million for PNM and $4.0 million for EPE. 

During the workshop, Vijay Satyal, deputy director of regional markets for Western Resource Advocates, asked whether the analysis of the Main Split scenario considered the impact of PNM and EPE leaving WEIM if they joined Markets+. 

“Was that potential loss of benefits factored into the net total cost impact?” he said. 

Moore said the study accounted for those factors. 

Michael Barrio, a senior principal with Advanced Energy United, pointed to what the group considers to be limitations of the WMEG study. 

“The study focuses narrowly on operational costs, failing to account for broader benefits, like reliability, capacity savings and resource diversity, which could be much larger,” Barrio said during the workshop. 

Despite all the effort going into choosing a day-ahead market offering, Martinez of PNM noted that the barrier for leaving either market will not be high. 

“If there are major topological changes or generation changes or market footprint changes, that could very easily trigger another benefit analysis from us, and we could shift to a different market operator,” she said. 

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Washington Renewable Developer Rankled by Siting Board Alterations

The developer of a large and controversial wind and solar farm in southeastern Washington contends the state’s siting body has ordered unscientific changes that make the project unviable.

Scout Clean Energy, the Colorado-based developer of the proposed Horse Heaven Hills Energy Center, submitted a letter to the Washington Energy Facility Site Evaluation Council (EFSEC) on Jan. 19 that showed the company correctly anticipated how the state board would seek to alter the design of the project during a public meeting Jan. 31.

In the letter, Scout Clean Energy President Michael Rucker said the “ad hoc” changes proposed by EFSEC “are an arbitrary, drastic departure from established council precedent. Further, they are unsupported by scientific or any other evidence in the record and would render the project both technically and economically non-viable without substantial amendment to the application.”

During the Jan. 31 meeting, EFSEC issued a requirement that Scout create a two-mile buffer around each known ferruginous hawk nest within the project’s 112-square-mile site. In 2021, the Washington Fish and Wildlife Commission unanimously heightened the status of ferruginous hawks from “threatened” to “endangered.”

EFSEC also ordered that Scout not locate turbines in areas considered culturally significant to local tribes. The council agreed to the strictest environmental options presented to it by its staff.

Scout’s plans call for either 222 wind turbines up to 500 feet tall or 141, 657-foot turbines along a 24-mile east-west stretch of the Horse Heaven Hills just south of Kennewick. EFSEC’s Jan. 31 decision potentially would cut from the project up to 116 of the shorter turbines or 73 of the taller ones. The exact numbers are imprecise because the developer could shift the locations of some of the removed turbines.

Scout’s proposal also includes two 500-MW solar farms on the east and west sides of the 24-mile stretch. EFSEC ordered that the eastern solar farm be removed because of its proximity to sensitive tribal cultural sites.

EFSEC environmental planner Sean Greene said there are roughly 60 to 70 hawk nests and significant cultural sites within two miles of the turbines to be eliminated.

“It won’t eliminate all the impacts, but there will be a significant reduction in impacts,” EFSEC Chair Kathleen Drew said.

‘Guessing Game’

The project has drawn strong opposition from many Tri-Citians because the turbines would show up in a currently pristine view of the hills from the urban area and because of the proximity to the ferruginous hawk nests. EFSEC staff noted the altered plan would remove turbines from along the north slopes of the hills, eliminating many residents’ concern about their views.

If built, the wind project would be the second in Benton County. Richland-based Energy Northwest, which owns and operates the 1,216-MW Columbia Generating Station nuclear plant north of the area, operates 63 wind turbines several miles southeast of the northern face of the Horse Heaven Hills. Completed in 2007, that site covers about 8 square miles and produces almost 96 MW. It is not visible from the Tri-Cities and has sparked no controversies.

In its Jan. 19 letter, Scout said the changes would trim the nameplate capacity of the wind portion of its project from 1,150 MW to 236 MW.

The letter contested the buffer zones around the hawk nests, arguing most are remnants that no longer are used by the birds.

“The decline of ferruginous hawk in Washington has been primarily the result of foraging habitat loss due to agricultural conversion,” Rucker wrote. “This factor is apparent in the Horse Heaven Hills, where nearly all previously documented nests have less than 30% available foraging habitat within 2 miles. Even before the project was proposed, ferruginous hawks have been essentially eliminated from the Horse Heaven Hills through this landscape-level conversion of habitat and encroachment of residential uses.”

The letter argues that it has been nearly five years since active nests were recorded within two miles of the project.

“No active nests have been documented since then, despite ongoing annual surveys by qualified biologists,” Rucker wrote.

Regarding the buffers around cultural sites, Rucker said, “the implications of this decision for future energy facility siting in Washington State are dire. It suggests that the council could redesign the project and prohibit any portion of a project based on [tribal cultural sites] that are undisclosed to an applicant. … Energy siting in Washington would become a guessing game, one few developers will be willing to play given the substantial at-risk costs involved.”

Wildfire Concerns

Addressing another matter related to the project, EFSEC staff told council members Jan. 31 that airplanes dropping water or flame retardants on range fires must fly within 500 feet above the ground. Consequently, those planes cannot fly over range fires among the wind turbines. EFSEC directed Scout to come up with a plan for fighting fires on its property to compensate for firefighters not being able to use planes.

Southeastern Washington is mostly shrub-steppe and grasslands that are susceptible to fast-moving range fires. Rural fire departments routinely fight those fires with state help, including planes, on the larger fires.

During the meeting, EFSEC also granted Scout’s request that the agency delay its final decision on the project until April 30 to give the company time to regroup and consider its options. EFSEC’s role is to make recommendations to Gov. Jay Inslee, who will issue the final decision on the project.

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FERC Again Questions MISO Reliability Payments to Wisconsin Coal Plant

FERC once again has determined that the continuing payments MISO is making to a Wisconsin coal plant to stay online to sustain system reliability might be too steep.  

The commission in a Jan. 31 order said Manitowoc Public Utilities’ proposed $1.16 million monthly compensation to continue operating its Lakefront 9 coal unit as a MISO System Support Resource (SSR) may be unreasonable (ER24-525). It set the matter for hearing, settlement and refund procedures. The new payments took effect Feb. 1.  

It’s the second time FERC has indicated that Manitowoc Public Utilities is charging too much to maintain grid reliability. FERC in mid-January approved a settlement lowering Lakefront 9’s monthly payment to $880,000 instead of the utility’s originally requested $1.03 million for the past year. (See FERC Approves Settlement in MISO Reliability Payments to Wisconsin Coal Plant.) MISO’s SSR agreements must be re-evaluated and extended annually if necessary. 

The Wisconsin Public Service Corp. and WPPI Energy protested the amount, voicing concerns over Manitowoc’s estimates for labor and maintenance costs, taxes and insurance, legal and consulting expenses, depreciation costs, carrying charges and capital project expenses.  

Lakefront 9 began operating as an SSR in February 2023 after MISO discovered that thermal overloading and voltage issues could occur on several nearby constraints if the plant was permitted to suspend operations as scheduled. The utility intended to idle Lakefront 9 until 2026, when it could be converted to a renewable fuel source. 

MISO has said its members’ planned transmission upgrades for the area that will improve system performance and allow it to lift the SSR agreement won’t be ready until mid-2028. 

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FERC Gets Dueling Competition Studies in Transmission NOPR Docket

With FERC potentially issuing a final rule on transmission planning this year, the issue of whether it should curtail competition is the subject of dueling reports filed in the Notice of Proposed Rulemaking’s docket (RM21-17).

The Electricity Transmission Competition Coalition (ETCC) filed supplemental comments Feb. 1 with a report extolling transmission competition’s benefits in response to a report filed in December from a group called Developers Advocating Transmission Advancement (DATA) arguing the opposite.

DATA is made up of transmission owners Ameren Services, Eversource Energy, Exelon, ITC Holdings, National Grid USA, Public Service Electric and Gas, and Xcel Energy.

“Contrary to their plea to revisit the commission’s prior determinations supporting competitive solicitations under Order No. 1000, the incumbent TOs fail to demonstrate that cost-of-service regulation is as effective as competition in establishing just and reasonable transmission rates,” ETCC said.

Competition disciplines cost, but regulated utilities with monopolistic rights and guarantees projects will have an incentive to press for the highest returns possible, it said.

“In a regulated cost-of-service model, the utility has an inherent incentive to spend more because the utility can then earn more through a return of and on its investment,” ETCC said. “Through competition, a developer has an inherent incentive to find an innovative and efficient solution, while an incumbent with monopolistic, exclusive rights has no such incentive.”

DATA’s report argued that those promised cost savings have not appeared in the decade plus since Order 1000, highlighting the costs of projects that were subject to competition. While the docket had 774 filings as of press time Feb. 1, DATA argued that its report includes information FERC had not seen yet.

ETCC called the DATA report “an unverified, authorless and self-serving white paper/pamphlet,” which, it continued, lacks credibility and was filed in the docket at the last minute — 15 months after the reply comment deadline.

“The resulting analysis shows that, rather than Order No. 1000-mandated competition leading to cost savings, final costs for projects selected through competitive solicitations tend to exceed cost baselines by at least 6%,” DATA said. “Furthermore, with certain reasoned adjustments, average baseline exceedances are calculated in the 12 to 19% range.”

Winning bids for projects from competitive processes do not represent final project costs because what is actually recovered tends to exceed those considerably, DATA argued. And competitive proposals often include cost caps, but DATA said those do not appear to offer meaningful cost-containment protections for customers, with final project costs exceeding them.

DATA’s report was in response to a report the Brattle Group prepared for LS Power in 2019 that found that competitive forces saved 20 to 30% compared to monopoly projects, which has been widely quoted by supporters of competition. That report suffered from a lack of finalized projects, DATA argued, so Brattle had to use cost estimates.

Brattle’s report includes 22 competitively bid projects, but just nine of those were completed in a way that allows for apples-to-apples comparison, DATA said. Some of the projects did lead to cost savings, but they were outweighed by ones that came in above cost, and DATA found they led to 6% higher costs compared to their baselines.

ETCC noted that the Brattle report already drew a response the year it was released from Concentric Energy Advisors, to which Brattle then responded. The California Public Utilities Commission and competitive transmission developers had discussed those two 2019 reports in the NOPR docket.

“The incumbent TOs cherry-pick data from select competitive projects, misleadingly describe those projects and advance anecdotes that do not represent the spectrum of the competitive transmission experience,” ETCC said.

Some of the missing projects are successful competitive projects that led to cost savings and thus go against the TOs’ narrative, it added.

“Critically, the incumbent TO white paper rests on the flawed premise that costs exceeding a competitive developer’s initial winning bid will be recovered from consumers,” ETCC said. “Unlike the incumbent utilities, which can generally flow their project cost overruns into rates, most competitive developers cannot pass through cost overruns to consumers because binding cost caps and cost-containment commitments are necessary for a competitive developer to win a solicitation and be awarded a project.”

Projects that go over a hard cap need to get approval from FERC to actually recover those costs, but even those that allow for adjustments because of inflation, or recovery of some cost overruns, are better than monopolistic projects without any cost containment, ETCC said. Only one of the nine projects DATA covered sought cost recovery above its cap.

ETCC also argued that DATA’s paper cut out most of the 22 projects Brattle studied to get the results it wanted. DATA also ignored the issue of inflation, which has affected projects built by incumbent utilities as well, it said.

Xcel’s Minnesota Energy Connection has more than doubled from the company’s initial estimate to $1.14 billion, and Ameren’s 345-kV Pana-Mt. Zion-Kansas-Sugar Creek line saw its costs grow by 44% from its initial development, ETCC said.

“Critically, because these projects were not competitively awarded and were instead developed without any cost containment, customers absorb these project cost overruns through formula transmission rates,” ETCC said. “Cost overruns are common among incumbent utility projects.”

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CEC-Stanford Energy Summit Calls for Equity in Energy Transition

PALO ALTO, Calif. — Communities historically excluded from decisions around energy use must be given a much greater role in the transition to a cleaner energy system, according to academics, researchers and power industry officials at the California Energy Commission-Stanford Energy Innovation Summit held Jan. 29-30.  

Summit panels centered on the kickoff of a CEC-led initiative, in collaboration with Stanford University and other research partners, called the Equitable, Affordable and Resilient Nationwide Energy System Transition — or EARNEST. The new university consortium is funded by the U.S. Department of Energy and designed to link university researchers with local and federal efforts to decarbonize the grid over the next five years.  

While panels covered a variety of topics, including state regulatory challenges, university and government partnerships, and solutions for remote grids, there was consensus among participating researchers and industry officials on the need for a more equitable transition drawing on the knowledge and perspectives of traditionally underrepresented communities in the U.S., such as tribes and other communities of color.  

“The people who will define what happens in the next half-decade are the communities that are the bellwethers and the guides for their partner institutions, funded through the Department of Energy’s consortium, to try to look for the pathways to an equitable and affordable, resilient, nationwide energy system transition,” said Holmes Hummel, managing director of Energy Equity and Just Transitions at Stanford’s Precourt Institute for Energy.  

Wind Power in Rural Alaska

One such community was represented by Chad Nordlum, energy project manager for the Native Village of Kotzebue, a remote city in Alaska’s Northwest Arctic Borough, who spoke during a panel titled “Co-creation of Knowledge of Traditionally Underrepresented Communities.”  

Kotzebue has spearheaded renewable energy development for the last 25 years, installing some of the first utility-scale wind turbines in 1997. Tribal communities in Alaska and throughout the nation often rely on diesel generation for power, and wind energy in Kotzebue displaces between 250,000 and 300,000 gallons of diesel fuel each year — around 20% of the city’s annual power needs.  

In 2020, the Kotzebue Electric Association (KEA) installed 532 kW of solar power, adding to its goal of producing 50% of the community’s energy from renewable sources over the following five years. KEA is planning for another 500-650 kW of solar and is seeking $2 million to fund the project. To meet its goal, KEA needs to upgrade and expand its system, but tribal nations and other underrepresented communities often lack access to the resources needed to do so, according to Nordlum.  

“I don’t think the rollout of renewable energy has been done in an equitable way so far. It’s all based on competitive grants [and] organizations like my tribe … have few capacities to hire grant writers, to hire engineers,” he said. “I think it could be done in a much more equitable way than it’s been done so far.”  

Holmes added that the difference in resource capacity between research institutions like Stanford and the communities they seek to partner with represents a stark inequity.  

Michael Wara, director of the Climate and Energy Policy Program at Stanford’s Woods Institute for the Environment, agreed, saying it’s important for research institutions to “show up” with resources that allow desired partners to participate.  

“Our philosophy has been to try to bring resources to the organizations that we really want to partner with, and that’s a value I would really recommend,” Wara said. “Think creatively about how to bring more to the table than you ask for.”  

Inequity in Energy Access

A 2022 report by the Building Energy, Equity and Power Coalition, a group of California-based nonprofits and environmental justice organizations, highlighted that low-income communities of color are often excluded from policy and decision-making around decarbonization. They typically lack information on major projects and developments, have low representation in the workforce and face major cost barriers.  

EARNEST is in many ways a listening project designed to engage the communities facing those barriers by seeking to meet people where they are.  

“In the electric utility industry, the culture of innovation and inclusion could use more help,” said Gene Rodrigues, assistant secretary for electricity at DOE’s Office of Electricity. “It’s not really all about policies, programs, technology and operations; it’s about people.”  

Even as the energy sector attempts to reduce reliance on fossil fuels, some renewable resources still depend on a culture of extraction that most often impacts the low-income communities of color that have made disproportionately lower contributions to the climate crisis, said Mari Rose Taruc, energy justice director with the California Environmental Justice Alliance.  

“An extractive economy or approach comes in many ways,” she said. “Are you trying to extract our time and energy to be partners with you? Are you extracting our labor to install these energy systems? Are you extracting from the earth? And what are you giving back?”  

As an example, Taruc pointed to a lawsuit recently filed by the nonprofit Comite Civico del Valle to overturn approval of the Salton Sea lithium mining project, claiming it lacked proper environmental review and consideration of potential harm to nearby residents who suffer elevated rates of asthma and heart disease.  

If impacted communities aren’t properly engaged, she said, projects will likely run into these types of delays.  

Alice Reynolds, president of the California Public Utilities Commission, also noted the cost barrier to accessing renewable energy — and energy at all, for that matter.  

“We’re at a point where rates are unsustainable for people. We have about 30% of our customers within the territories of the utilities that we regulate who are on low-income programs,” she said. “We need to think about providing services to everyone.”  

Moving Forward

Despite the ever-growing need to rapidly decarbonize and electrify the grid, local communities can’t be “run over” in the process, Wara said.  

“If we’re going to actually solve the climate crisis, we need to build a bunch of stuff, and we can’t build it in the way we built it in the 1960s on the back of structural racism,” he said. “The questions that the communities have is the essential start for good work to be done.”

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Algonquin, Residents Make Final Arguments in Weymouth Hearing

The attorneys representing the Massachusetts Department of Environmental Protection, Enbridge subsidiary Algonquin Gas Transmission and a group of 10 residents presented their final arguments in a department adjudicatory proceeding Jan. 31 over the waterways license of the company’s embattled natural gas compressor station in the city of Weymouth.

The hearing is the latest in the ongoing saga over the Weymouth compressor station. Algonquin submitted its application for the at-issue waterways license in 2015. It was approved in 2019 but was later sent back to MassDEP following a court appeal.

The compressor station was constructed as part of Enbridge’s Atlantic Bridge Project, aimed at increasing the south-to-north capacity of the Algonquin and Maritimes & Northeast pipeline systems. FERC gave the facility final approval in 2020 (CP16-9), and it began operations in 2021.

While state officials and lawmakers frequently speak of the importance of environmental justice, the residents opposing the compressor station have cast the ongoing proceedings as a key litmus test for Gov. Maura Healey’s administration. It was sited close to industrial facilities, including fuel storage tanks, two gas plants, a chemical manufacturing facility and the largest hazardous waste disposal site in New England; residents of the surrounding area have long argued that their community already hosts more than its fair share of polluting infrastructure.

The focus of the Jan. 31 hearing was whether the station meets the definition of an “ancillary facility” to a section of the Algonquin system known as the “HubLine” and therefore requires an adjacent location. The HubLine runs beneath the Fore River, Boston Harbor and Massachusetts Bay to connect with the Maritimes & Northeast system, which heads north to Nova Scotia.

Attorneys for Algonquin and MassDEP argued that the station requires an adjacent location and was therefore correctly sited at its existing location, while the attorney representing residents argued against the need for an adjacent location.

Nicholas Cramb, the attorney representing Algonquin, said siting the station at its existing location limited the waterways impacts compared to all alternative locations, which would have required suction and discharge pipes with additional waterways impacts.

Cramb’s position was supported by David Bragg, senior counsel for MassDEP, who said the department “determined that the location at the site — already in industrial use, already part of the infrastructure crossing facility, without the need to disturb a square foot of jurisdictional tidelands in another area — … was the appropriate location, and that it was required to be there.”

Michael Hayden, the attorney representing the residents, made the case that the compressor station did not require an adjacent location to the HubLine because the line simply does not need it to operate. He emphasized that the HubLine operated without the station for more than a decade.

“The gas is not being pushed through the compressor station for local distribution. This is going to Canada; it’s going to Maine,” Hayden said, adding that the station provides “no discernible benefit to our Massachusetts residents.”

Final oral arguments for the waterways remand proceeding | MassDEP

Cramb responded that the petitioner’s argument that the line can send gas north to south without the station is “irrelevant.”

Without the compressor, the relevant portion of the gas system cannot move enough gas “to satisfy the purposes of the Atlantic Bridge Project and Algonquin’s contracts,” Cramb said. He called the assertion that the station provides no benefits to Massachusetts residents “absolutely a false statement,” noting that one of Algonquin’s customers is a power plant in Salem.

Hayden also made the case that, because the station remains under review by MassDEP, it should be subject to the environmental justice provisions of the state’s 2021 “Next Generation Roadmap” law on climate policy.

The law requires an environmental impact report (EIR) for projects likely to cause environmental damage located in or near state-designated environmental justice communities. Hayden argued that the law dictates that the EIR could be triggered “at any stage of the review process.”

Hayden also noted that the station is located within 1 mile of multiple environmental justice communities. A 2019 state health assessment found that nearby residents face higher risks of health conditions linked to air pollution, including lung cancer, heart attacks, heart disease and pediatric asthma. Hayden has argued that gas released from the compressor poses an added threat to the community.

Hayden requested that the MassDEP Office of Appeals and Dispute Resolution (OADR) “remand this entire application and project back to the department to complete the environmental justice review that’s required under the 2021 climate act.”

Cramb and Bragg both argued that the EIR requirement does not apply to the station because the 2021 law was intended to apply only to new projects, whereas the waterways application was filed in 2015.

In its pre-filed closing brief, Algonquin added that “it is clear that [the law] does not require that Algonquin file an EIR for the compressor station because the compressor station is not subject to [Massachusetts Environmental Policy Act] review.”

Following the conclusion of the final arguments on Jan. 31, Chief Presiding Officer Salvatore Giorlandino of the MassDEP OADR will make a recommended final decision to DEP Commissioner Bonnie Heiple.

Heiple, who was appointed by Healey in March, will then be tasked with making the final decision on the proceeding.

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Western Market Seams Issues to Differ from East, Study Finds

A new study finds that the seams dividing CAISO’s Extended Day-Ahead Market (EDAM) from SPP’s Markets+ in the West would pose a different set of problems than challenges seen at the boundaries of full RTOs in other parts of the U.S. 

The Seams Evaluation study was commissioned by the Western Power Trading Forum (WPTF) and Public Generating Pool (PGP) and prepared by Energy Strategies and Gridwell Consulting.  

The study seeks “to provide a framework for understanding the key seams areas and seams issues that may exist between the two proposed day-ahead markets in the West,” while not taking a position on whether the region should have one or two day-ahead markets. 

The authors also said they did not intend “to propose specific solutions to seams issues” or provide a comprehensive assessment of all potential issues. 

The study lays out how the two day-ahead markets proposed for the West are “fundamentally different” from RTOs in the East.  

Those differences include the fact that, unlike the day-ahead markets, the RTOs feature the consolidation of balancing authorities and full participation of entities within the BAs; fully coordinated resource adequacy; and consolidation of transmission planning and generator interconnection to the grid. 

The day-ahead markets also would lack full co-optimization of energy deliveries and ancillary services and would require consolidation of open-access transmission tariffs to completely optimize use of transmission.  

Seams Within Seams

A key challenge Western day-ahead markets likely would share with Eastern RTOs is the issue of “economic” seams, which arise when boundaries between markets hinder the most cost-effective dispatch of energy across the grid and prevent operators from managing transmission congestion to the greatest extent possible. 

To mitigate the impact of economic seams, neighboring RTOs use interface pricing to help facilitate energy flows between them in both the day-ahead and real-time market. The study points out that RTOs also address their boundaries with additional tools, such as interchange scheduling, day-ahead firm flow entitlement exchange, coordinated transaction scheduling and market-to-market coordination. 

“While the West should be able to build on these concepts, these tools are currently untested under the non-RTO day-ahead market frameworks and may not translate directly given the seams within the day-ahead markets,” the study says. 

The authors note that the mechanisms RTOs use to manage economic seams are the result of negotiations, agreements and joint design efforts among stakeholders from both markets. 

“Additionally, given the nature of day-ahead markets, we expect that there will be more parties and/or more seams agreements required (including between BAs and Market Operators) than is seen in the context of Eastern RTOs,” the study says. 

The study also delves into the challenges likely presented by seams within Western day-ahead markets as well as between them. Key among them is that both EDAM and Markets+ lack mechanisms for co-optimizing awards for ancillary services with day-ahead energy, although the study acknowledges that could change in the future.  

Another internal seam stems from the fact that both day-ahead markets as proposed will allow their BAs to continue to use existing constraints to ensure that market participation doesn’t compromise their reliability obligations, effectively allowing for voluntary participation in the markets. 

“This may affect the extent to which BAs rely on the market for imports and commit units within their own footprint, which can reduce overall benefits through lack of full optimization of the fleet,” the study finds. 

Another key internal barrier will be the lack of a common resource adequacy framework. Participants in both EDAM and Markets+ will have the option of either joining the Western Power Pool’s Western Resource Adequacy Program or not committing to any RA program at all, while California utilities will continue to be subject to that state’s RA requirements. 

“Given the lack of a consistent RA and full [must-offer obligation], other mechanisms must be designed to address sufficiency of resources by individual market participants or BAs in a day-ahead market,” the study says. 

Western Challenges

The study also explores potential seams issues specific to day-ahead markets in the West, including increased barriers to contracting for resources, with the boundary between the markets possibly introducing new complexities to contracts, raising costs and increasing risks around deliveries. 

Greenhouse gas accounting and dispatch inefficiencies would represent another key barrier between the two markets, according to the study. These would “result from the absence of a single day-ahead market to produce coordinated GHG pricing signals and establishment of similar treatment to all imports into GHG-regulated areas, even under linked carbon pricing programs,” the study says. California and Washington currently operate under separate GHG cap-and-trade programs, but efforts are underway to link them within the next couple of years. 

Different approaches to market power mitigation could create yet another type of seam between Western markets, the study finds. The authors point to the increased potential for “higher instances of uncompetitive conditions due to optimizing over two smaller footprints as opposed to one larger footprint.”  

They also caution that Markets+ is in the process of developing a balancing authority area-level mitigation system that could differ from what CAISO already has in place for the Western Energy Imbalance Market. 

“Creation of two ways to address system/BAA-level market power mitigation will naturally result in areas being exposed to differing levels of over- and/or undermitigation,” the study said, noting that the differences could result in differing levels of contracting for resource among the markets. 

The WPTF/PGP study should contribute to discussions about day-ahead market seams already taking shape in the West. At a recent meeting of the Markets+ Participants Executive Committee, supporters of both markets spoke about the need to begin addressing the reality of a divided region. (See SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)  

WPTF and PGP will host a webinar to discuss the seams study Feb. 6.  

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ERCOT Technical Advisory Committee Briefs: Jan. 24, 2024

ERCOT stakeholders last month moved closer to taking action on a tabled rule change that would address the reliability concerns with inverter-based resources (IBRs).

Staff told the Technical Advisory Committee during its Jan. 24 meeting that the prevalence of IBRs on the system has increased the likelihood of potential instability issues, such as the recent Odessa disturbances. They said the issues are only going to increase along with the continued growth of solar and wind resources. (See NERC Repeats IBR Warnings After Second Odessa Event.)

ERCOT says the Nodal Operating Guide revision request (NOGRR245) would improve the clarity and specificity of IBRs’ voltage ride-through requirements. The NOGRR would align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid.

FERC also recently issued Order 901, directing NERC to address same risks NOGRR245 takes on.

ERCOT has recommended that TAC approve the change with recent comments it filed. It said a recommended proposal by the committee’s Reliability and Operations Subcommittee is not acceptable, as it does not address the current “significant reliability risk.”

Staff have made several changes to the proposed NOGRR to allow for additional exceptions for documented technical limits. IBRs must:

    • meet existing requirements and “substantially” meet new requirements, with each plant’s documented technical limit level becoming the requirement for that plant;
    • maximize capability through software upgrades and minor hardware upgrade kits;
    • accurately represent technical limits in all provided models; and
    • meet the latest requirements upon repowering, retrofitting or reinvestment.

They also cannot create any instability, uncontrolled separation or cascading outages for the ERCOT grid.

TAC agreed to resume discussion of the NOGRR at its next meeting, which it rescheduled from Feb. 27 to Feb. 14. The virtual meeting is designed to give stakeholders an opportunity to endorse a recommendation for the Board of Directors’ Feb. 26-27 meetings.

RUC Use Down Sharply

ERCOT saw a “significant” decrease in reliability unit commitments (RUCs) last year compared to the previous two years, staff told stakeholders.

The grid operator had 2,726 instructed resource-hours resulting in 2,500.6 effective hours. In 2022, ERCOT saw 8,244.8 instructed resource-hours and 7,910.5 effective hours; in 2021, effective resource-hours came in at 3,853.1. (See “RUCs Continue to Increase,” ERCOT Technical Advisory Committee Briefs: Jan. 24, 2023.)

ERCOT bought back 509.5 effective resource-hours, a 20.4% rate that matched 2022’s buy-back.

Ryan King, manager of market design, said changes in resource owners’ real-time price expectations and higher demand were among the factors contributing to RUCs’ reduction. While reluctant to identify specific causes for the decrease, he admitted the deployment of ERCOT contingency reserve service in June and higher ancillary service requirements since the 2021 winter storm may have played a role.

“Some of these factors might have been present all the time, and all of these might have been present some of the time, but I’m not sure that we have a really definitive cause and effect,” King told TAC.

He said ERCOT will continue to monitor and report on factors contributing to commitment changes.

The grid operator incurred $3.67 million in RUC make-whole payments, almost exclusively covered through capacity-short charges, last year, along with $3.45 million in claw-back charges.

ADERs now up to 9

Dave Maggio, ERCOT’s market design and analytics principal, said seven aggregated distributed energy resources (ADERs) have been approved to go through the qualification and validation process of commercial operations.

They will join two ADERs that have already qualified to participate in the wholesale electric market; they are providing 9.4 MW of energy and 3.1 MW of non-spinning reserve service since their participation following the first phase of a virtual power plant (VPP) pilot project. (See “2 VPPs Qualified for Market Participation After Pilot Project’s 1st Year,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

The ADERs will participate in the second phase of the VPP pilot. They will be limited to an 80-MW cap for energy and 40 MW for non-spin.

Data related to the ADERs’ market participation have been “somewhat limited,” Maggio said, but it has still been enough to propose incremental changes for the second phase. Staff plan to present a Phase 1 report and a draft of the Phase 2 governing document to the board and its Reliability and Markets Committee this month.

Jupiter’s Smith Elected TAC Chair

TAC members elected Jupiter Power’s Caitlin Smith as its chair for the next two years, elevating her from vice chair, the position she’s held the past two years. They also elected Oncor’s Collin Martin as vice chair. There were no other candidates.

Caitlin Smith, Jupiter Power | ERCOT

Members also confirmed the leadership of its subcommittees and sub-groups after elections were held within the stakeholder groups last year:

    • Protocol Revision Subcommittee: Diana Coleman, CPS Energy, chair; Andy Nguyen, Constellation Energy Generation, vice chair.
    • Retail Market Subcommittee: John Schatz, Luminant, chair; Debbie McKeever, Oncor, vice chair.
    • Reliability and Operations Subcommittee (ROS): Alexandra Miller, EDF Renewables North America, vice chair.
    • Wholesale Market Subcommittee: Eric Blakey, Pedernales Electric Cooperative, chair; Jim Lee, CenterPoint Energy, vice chair.
    • Credit Finance Sub-group: Brenden Sager, Austin Energy, chair; Loretto Martin, Reliant Energy Retail Services, vice chair.

Katie Rich was elected as the ROS chair when she was with Golden Spread Electric Cooperative, but she has since changed jobs. A new election will be held at the subcommittee’s next meeting.

Tier 1 Project Endorsed

TAC’s unanimously approved combination ballot included a Tier 1 transmission project that will go to the board for approval. ERCOT labels projects costing more than $100 million and requiring the directors’ approval as Tier 1.

Texas-New Mexico Power submitted the Pecos County Improvement Project last year to ERCOT’s Regional Planning Group for its review. The RPG studied nine options before settling on its recommendation to address the reliability need under maintenance outage conditions near Fort Stockton in the Far West weather zone.

The project consists of about 55 miles of new and rebuilt 138-kV transmission lines and a new substation. It has a capital cost of $114.8 million, with the upgrades expected to be completed by August 2026.

The combo ballot included seven nodal protocol revision requests (NPRRs), single changes to the Planning (PGRR) and Retail Market (RMGRR) guides, and a system change request (SCR) that, if approved by the board and the PUC, would:

    • NPRR1170: define when a qualified scheduling entity (QSE) representing a resource that relies on natural gas as its primary fuel source should notify ERCOT about gas supply disruptions.
    • NPRR1179: ensure that QSEs representing resources with an executed and enforceable transportation contract procure fuel economically and file a settlement dispute to recover their actual fuel costs incurred when instructed to operate because of an RUC. This change would also adjust the RUC guarantee to reflect the cost difference between the actual fuel consumed during the RUC-committed intervals and the fuel burn calculated based on verifiable cost parameters and would clarify that fuel costs may also include penalties for fuel delivery outside of RUC-committed intervals.
    • NPRR1195: assign ERCOT-polled settlement metering facilities’ maintenance and repair responsibilities to the facilities’ owner if it is not a transmission and/or distribution service provider (TDSP).
    • NPRR1206: clarify the QSEs required to have a hotline and a 24/7 control or operations center, and reconcile the deadline by which QSEs representing resource entities that own or control resources must provide notice that they are terminating their representation and the deadline that resource entities owning or controlling resources to change QSEs with a 45-day timeline.
    • NPRR1207: permit the incidental disclosure of protected information and ERCOT critical energy infrastructure information (ECEII) during a tour or overlook viewing of the ERCOT control room provided to eligible persons who have signed nondisclosure agreements and complied with screening and other requirements before accessing the control room.
    • NPRR1208: create a new daily ERCOT invoice report listing invoices issued for the current day and day prior at a counter-party level.
    • NPRR1211: incorporate the other binding document “Methodology for Setting Maximum Shadow Prices for Network and Power Balance Constraints” into the protocols.
    • PGRR109: require interconnecting entities associated with IBRs to undergo a dynamic model review process before the commissioning date and mandate that resource entities owning or controlling operational IBRs undergo a review process before changing settings or equipment that could affect electrical performance and necessitate dynamic model updates.
    • RMGRR179: add a communication method so TDSPs can use Texas standard electronic transactions to inform retail electric providers of record which electric service identifiers are affected by a TDSP’s mobile generation or temporary emergency electric energy facility deployment.
    • SCR825: modify ERCOT’s current control room voice communication configuration(s) to give QSEs and their subordinate QSEs greater flexibility when assigning agent(s), including allowing sub QSEs to assign agents different from those used by the parent QSE.
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Deflated New York OSW Portfolio Positioned to Start Regrowth

The few details released on New York’s potential next wave of offshore wind projects indicate continued efforts to expand the human and industrial infrastructure critical to offshore development. 

They also indicate a 28% shrinkage: Contracts for all four projects that previously were contracted by the state have been or will be cancelled. They had a combined 4,230 MW of capacity, but the three proposals submitted by the Jan. 25 deadline would be a maximum of 3,034 MW. 

Three gigawatts is a respectable figure, given the struggles the offshore wind industry experiences as it establishes itself in the United States. (Four other Northeast states have seen contract cancellations in the past year.) 

And New York is in advanced negotiations for three other projects it awarded provisional contracts in October 2023 — their total capacity is 4,032 MW. (See NY Announces Renewable Energy Projects Totaling 6.4 GW.) Final contract execution may come as soon as this quarter. 

If they all come to pass, these six projects would total 7 GW, and get the state most of the way to its 2035 goal of 9 GW.  

Beyond that, developers cancelled New York contracts for two other projects totaling 2,470 MW. But they did not cancel the projects themselves — they could be rebid into a future solicitation, though not necessarily New York’s. 

The three proposals submitted to the New York State Energy Research and Development Authority on Jan. 25 were Community Offshore Wind 2, Empire Wind 1 and Sunrise Wind.  

The names are familiar: Empire and Sunrise hold contracts that still officially are in effect but will be cancelled regardless of whether the projects win new contracts. And Community Offshore Wind 1 was one of the provisional contract awardees in October. 

Equinor and Ørsted both are moving to terminate their joint ventures and proceed solo on Empire and Sunrise, respectively. (See Offshore Wind Reset Complete in New York.) 

Both are mature plans with many regulatory and logistical hurdles already cleared, giving them a yearslong head start over newer proposals in a region of the state predicted to be at growing risk of capacity shortfalls as soon as 2025.  

The proposals submitted Jan. 25 illustrate the long timelines at play: Community’s projected commercial operations date is not until 2031. Sunrise projects commercial operations in 2030 if it is built to be ready for a meshed offshore transmission system, or 2026 if it is not meshed-ready. Empire also projects power generation starting in 2026. 

Most other details are redacted in the public versions of their supporting documentation. 

Equinor and Ørsted have continued actively moving the projects forward since declaring in June 2023 that the existing contracts were untenable without more money from the state, and since the state in October 2023 said no more money would be forthcoming. (See OSW Developers Seeking More Money from New York and New York Rejects Inflation Adjustment for Renewable Projects.) 

The latest update: On Feb. 1, Equinor announced New York City had approved its design for an offshore wind operations and maintenance building at the South Brooklyn Marine Terminal, a 73-acre facility the company envisions as an onshore hub for offshore construction and operations — both for itself and other developers. 

Ørsted, meanwhile, continues preparatory work for the onshore electrical infrastructure upgrades Sunrise would need. It plans to set up an operations and maintenance hub on the north shore of Long Island as part of the Sunrise project and open it in the third quarter of 2024. 

Community Offshore Wind is a collaboration by RWE and National Grid Ventures. In the summary of their proposal, they said they have made allowances for the economic risks and supply chain uncertainties that have bedeviled offshore wind developers since late 2022. The Community projects are designed with the flexibility needed to overcome these challenges, they added. 

Additionally, Community proposes nearly $50 million in workforce and supply chain investments; Equinor has been funding the Offshore Wind Innovation Hub; and Ørsted has funded the National Offshore Wind Training Center.