The CAISO Board of Governors and Western Energy Markets Governing Body on Nov. 7 unanimously passed a proposal to modify the calculation used to determine bid cost recovery payments for storage resources.
The product of four months of intense stakeholder engagement, the proposal aims to address what ISO staff and stakeholders identified in 2022: that BCR provisions for storage resources don’t align with the intent of BCR. (See CAISO Proposal Seeks to Refine Storage Bid Cost Recovery.)
The initiative, which kicked off in July, identified two main concerns: that storage assets are not exposed to real-time prices for deviating from day-ahead schedules, and that they may have an incentive to bid strategically to maximize their combined BCR and market payments.
Resources receive BCR payments when market revenues don’t cover the resource’s bid costs, such as startup, minimum load and transition costs. BCR also incentivizes resources to follow dispatch and bid efficiently by removing risk if the dispatch doesn’t cover costs.
But bids for storage resources are largely driven not by the cost to produce energy in a given interval, but rather by their state-of-charge limits. The ISO noted that a combination of ancillary service awards or self-provisions for regulation-down in the real-time market, coupled with relatively high energy bids, resulted in unusually high BCR payments to storage resources.
The final proposal recommends revising the calculation of real-time BCR for storage resources by basing the bid cost on an alternative to eliminate the opportunity for strategic bidding that inflates BCR.
For resources dispatched up, the alternative would be the minimum of the bid and the maximum of three alternatives: the real-time default energy bid, the real-time market-cleared price, or the day-ahead market-cleared price. For resources dispatched down, the alternative would be the maximum of the bid and the minimum of the three alternatives.
‘An Incomplete Approach’
In an opinion published Nov. 1, CAISO’s Market Surveillance Committee (MSC) agreed with the proposal, but indicated it should represent only a first step.
“We definitely agree with the ISO and the Department of Market Monitoring that there are important incentive problems that can result in both significant financial transfers that we believe are unearned in the form of excess bid cost recovery and, very importantly, market inefficiencies in terms of insulation from incentives that real-time prices are supposed to provide,” MSC Chair Ben Hobbs said in a Nov. 1 meeting.
The first goal should be to eliminate BCR “phantom losses” that result from including resource charging bids and discharge offers in the BCR calculation.
“We believe that this goal is likely to be partially but not completely accomplished by implementation of the ISO proposal,” Hobbs said.
The ISO’s Department of Market Monitoring (DMM) also showed cautious support of the proposal, viewing it as an interim solution that didn’t fully address both concerns.
According to Adam Swadley, DMM manager of market policy and analysis, the proposal targets the bid cost component of the BCR calculation by limiting bids used in the real-time BCR calculation but does not affect the revenue portion, allowing storage operators to remain insulated from real-time prices.
“DMM does not oppose management’s proposal. However, we do view it as an incomplete approach that does not address the underlying efficiency issues of the current BCR rules applied to batteries, and therefore we strongly encourage the ISO to immediately continue working with stakeholders to develop a more complete and effective solution for the fundamental problems,” Swadley said.
The ISO is kicking off a new storage design and modeling initiative next month to continue addressing the first concern related to real-time prices.
CAISO’s Board of Governors and Western Energy Markets (WEM) Governing Body on Nov. 8 approved ISO tariff amendments needed to implement the West-Wide Governance Pathways Initiative’s “Step 1” proposal, which would refine four key characteristics in the governance documents and the tariff.
The proposal seeks to elevate the power of the Governing Body by granting it “primary” authority over rule changes affecting CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), compared with the “joint” authority it currently shares with the ISO board.
The tariff amendments will modify the markets’ dispute resolution process to include a dual filing option and augment language considering the public interest. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)
When they approved the Step 1 proposal in August, the ISO and WEM boards directed CAISO to prepare revisions to governing documents for later approval. Implementing the changes would require amendments to three governing documents and a section of the tariff.
Changes to the charter for EDAM and WEIM governance include:
Adding refinements to the mission of the WEM Governing Body as it relates to considering the public interest and respecting state and local authority.
Revising the process for approving tariff amendments within the shared authority from the joint authority to the WEM Governing Body having primary authority, with approved amendments being placed initially on the consent agenda of the ISO board.
Revising the dispute resolution process to add a dual filing with FERC as a possible means of resolving a sustained disagreement between the two bodies.
Adding that the WEM Governing Body may initiate a review of governance if a majority of EDAM entities announce plans to leave EDAM.
Section 6 of the charter, which established the WEM Body of State Regulators, will be amended to clarify that the BOSR can provide opinions to FERC regarding any proposed tariff amendment within the scope of the Governing Body’s authority.
Additionally, references to “joint authority” will be revised to say “primary authority” in the corporate bylaws and decisional classification guidance for the WEM Governing Body. Tariff language also will be amended to enable dual filing.
The changes won’t occur until a trigger mechanism is enabled, which is achieved when utilities outside of CAISO’s balancing authority area representing equal to or greater than 70% of the ISO’s load have executed EDAM agreements. To avoid uncertainty about when the changes go into effect, management added a step that requires revised documents to become effective upon certification by the ISO’s CEO or COO.
While the trigger isn’t expected to be enabled until sometime in 2025, the ISO seeks approval of the changes now to allow time for FERC to issue an order on a tariff amendment.
AUSTIN, Texas — Somewhat unnoticed among the plethora of organizations and associations related to the electric utility industry sits the North American Generator Forum, an independent, member-driven organization designed to provide a “united voice” on reliability, resiliency and security to NERC.
During NAGF’s compliance conference and its annual meeting Nov. 6-7 at the Texas Reliability Entity’s headquarters, attendees shared their lessons learned and best practices with their peers. NERC staffers also called in with the latest developments at the agency.
The NAGF is modeled after the larger North American Transmission Forum. It relies on its more than 80 member companies, accounting for about 53% of the bulk electric system’s capacity in North America, to share information in providing that “unified voice.”
“We look to the Transmission Forum as kind of our guiding light,” Occidental Energy Ventures’ Venona Greaff, NAGF’s secretary, told ERO Insider. “We’re similar, but we’re quite a bit different because they have a full-time staff. We don’t. We do a lot of our efforts through the membership and through the volunteer efforts.”
The NAGF’s generators provide their comments through the forum’s seven working groups. They include cold-weather preparedness, cybersecurity practices and variable resources.
“They’re the experts specific to the standards that are applicable to that area,” said Greaff, a 30-year industry veteran who, in her day job, manages the NERC compliance program for Occidental Energy’s cogeneration fleet.
“It’s sharing information, both among member to member but also getting information from the outside,” she added. “The whole purpose is just to assist our members … to help the generator community in general with compliance responsibilities, reporting responsibilities, understanding of standards and knowing what’s coming down the pipeline toward them.”
Greaff and ERCOT’s David Kezell, director of weatherization and inspection, updated attendees at the annual meeting on revisions to NERC’s cold-weather standard (EOP-012-2, Extreme Cold Weather Preparedness and Operations). FERC accepted EOP-012-1 in 2023 but ordered revisions to be completed by 2024. That resulted in EOP-012-2, which the commission accepted in June while ordering that seven more changes be completed by March 2025. (See FERC Orders Further Cold Weather Standard Modifications.)
The drafting team, which includes Greaff and several other NAGF members, has gathered feedback from the industry, asking for specific suggestions to strengthen the standard. Kezell, who chairs the team, said he expects only one more ballot will be posted from the three that are scheduled. The ballot will be live in December, setting up the NERC Board of Trustees’ consideration of the standard in March.
To speed things along and meet FERC’s deadline, the team is using a shortened comment and ballot period of 20 days, rather than the usual 45 days.
“We’ve been trying to approach this expeditiously. It’s an accelerated effort,” Kezell said. “We’re hoping to be able to take the responses that we got and the comments that we’ve received from this initial ballot and put together something that would be acceptable and we could get the requisite number of yes votes on the next round.”
He said the biggest obstacle is coming up with an “appropriate” definition for generator cold weather constraints. The definition has been simplified to “any condition that would preclude a generator owner from implementing freeze protection measures on one or more generator cold weather critical components.”
The team created a new attachment that establishes “highly common circumstances that would be appropriate for close to a blanket constraint that would be easily approved by the ERO,” Greaff said.
“We called those pre-approved generator cold-weather constraints,” she said. “Ultimately, we may change that language, but the idea was to create a short list of things that we thought would be appropriately applied nearly everywhere.”
The team also listed criteria describing a constraint and included them in the review.
“We want to provide significant clarity to both the generator operators and to the regulatory personnel on what constitutes a valid generator cold-weather constraint,” Greaff said.
There’s more to come.
NERC is holding a technical conference on the cold-weather standard Nov. 12 at ERCOT’s headquarters. Speakers will review the FERC order, discuss the defined generator cold-weather constraints and share best practices.
“As generators, it’s our chance to speak with the regulators, to hear where the constraints lie, but also to share thoughts with the drafting team so that we can move forward with the best approach in revising EOP 12,” Greaff said, encouraging her listeners to attend.
The West Coast’s floating offshore wind industry is getting a boost from nearly $38 million in research and development funds from the California Energy Commission’s Electric Program Investment Charge (EPIC) program.
During a Nov. 5 CEC meeting, several companies presented projects intended to increase efficiency and reduce costs for the offshore wind sector, including through improved environmental monitoring around wind turbines, new designs for technical components and innovative manufacturing solutions.
The ratepayer-funded EPIC program invests in technology development to advance clean energy solutions. The program’s specific goals related to offshore wind are to lower costs and to reduce technical and financial risk, as well as inform environmental mitigation, deployment planning and permitting.
Two solicitations are currently in progress.
The first awarded nearly $9 million to a handful of companies to advance technologies that detect marine life or ecosystem processes to assess risks and impacts in wind energy areas.
The second solicitation awarded nearly $12 million to projects to advance designs for floating offshore wind mooring lines and anchors. Another $17 million will go to solicitations currently under consideration, including projects seeking to reduce turbine design costs and improve port readiness.
“We are, as many folks know, a much deeper environment than the existing offshore wind systems [in the Atlantic], so reducing the costs of mooring lines and anchors is going to be paramount,” Daphne Molin, supervisor of CEC’s Research and Development Division, said at the meeting. “Additionally, environmental impacts and potential concerns are extremely important. We want to make sure that those designs are put up front into the design work so that these designs can be best placed for California.”
Environmental Monitoring
California’s wind energy areas are rich with seabirds protected under the Migratory Bird Treaty Act and the Endangered Species Act. Integral Consulting presented an EPIC-funded project designed to analyze those risks.
“Birds like the albatross and the petrel may be more vulnerable to collisions with floating offshore wind turbines because of their reliance on wind rich areas to propel themselves long distances between their breeding and foraging grounds offshore,” Grace Chang, senior science advisor at Integral, said. “Some of these birds fly at night and some at heights that overlap with rotor swept zones.”
To address these vulnerabilities, Chang said her company identified the need to generate bird and bat collision risk models to estimate species-specific impacts. The models require information about wind farm and turbine characteristics, environmental covariance, and bird and bat qualities. Collision risk models are most sensitive to the “avoidance rate,” which requires detailed information about bird and bat behavior over time.
Integral’s project seeks to fill existing knowledge gaps in understanding collision risk models, bird and bat abundance, and behavioral patterns near wind energy areas. The project integrates real-time testing and validation, 3D sensing technologies to quantify bird and bat avoidance of wind farms, and collision risk across three scales — macro, meso and micro.
The macro scale refers to a species avoidance of the entire wind farm, while meso is avoidance of individual turbines or rotor-swept zones, and micro is a last-second avoidance of a collision.
Field testing is already underway. Integral collected three months of data in California’s Humboldt wind energy area and deployed drones and radars in coastal environments in San Luis Obispo and Santa Barbara counties.
“We have a very rich set of data — multiple terabytes of data actually — that we’re in the midst of analyzing,” Chang said.
The Lawrence Berkeley National Laboratory also received funds for a project to cost effectively monitor the impact of wind farms on underwater species. The project considers the need for mooring lines and other fixed structures that would be tethered to the ocean floor due to the deep waters of Pacific OSW areas.
“How do we deploy floating offshore wind responsibly and harvest clean energy while protecting the marine species?” Yuxin Wu, staff scientist and geophysics department head at the University of California, Berkeley, said. “That is a big challenge.”
The lab is developing a distributed technology that will use optical fibers to sense temperature, vibration and other characteristics more than 100,000 meters deep to monitor species behavior and potential collisions with wind infrastructure.
Anchors and Mooring Lines
Sperra, a renewable energy startup, received CEC funding to develop and deploy concrete anchors for floating offshore wind platforms that it says will be less expensive and more environmentally friendly than traditional anchors.
The company is using its expertise in 3D concrete printing to develop a “next-generation suction anchor and torpedo anchor made from concrete.” The process is expected to reduce manufacturing costs by 37%-82% and carbon emissions by 55%-96% compared with steel anchors, according to company CEO Jason Cotrell.
“Concrete is actually a relatively low-carbon material compared to steel on a per-pound basis,” Cotrell said. “It has half the carbon footprint, and it can be made more green with certain mixes.”
Sperra is manufacturing 3D-printed concrete anchors out of the Port of Los Angeles for a variety of different markets, all of which will be deployed in California. It’s also researching 3D printing for floating foundations and docks.
To determine the design of the concrete anchors, Sperra analyzed seismic activity and seabed composition information in the Humboldt and Morro Bay wind energy areas to conceptually design six concrete anchors and two steel anchors for reference.
Sperra’s hope is to expand and accelerate the growth of California’s concrete and floating wind workforce, research and development capabilities and innovation ecosystem.
Another award recipient was the University of Maine Advanced Structures and Composites Center, which is developing a synthetic mooring line system for a 15-MW-plus floating wind turbine in the Humboldt and Morro Bay wind energy areas that could minimize impact to the ocean ecosystem.
“For an estimated 15 GW of offshore wind capacity, you’re going to need over 1,000 kilometers of mooring lines. The supply chain can’t currently handle that amount of material,” Spencer Hallowell, senior engineer at the University of Maine, said. “And then the installation vessels that may be either flagged for the U.S. or internationally also aren’t available to do that type of installation.”
The use of synthetic ropes can help alleviate supply chain concerns by eliminating heavier components like steel, Hallowell said.
In addition to studying the environmental conditions to determine the exact design of the mooring system, the department will monitor the system for entanglement of marine species and of fishing gear that could also capture marine animals.
The Schatz Energy Center and consulting company H.T. Harvey and Associates won funding for the “MoorSEA” project, an effort to combine mooring and monitoring technology by developing sensors that sit on mooring lines. Project researchers are working to identify which types of species, fishing gear and debris are most likely to become entangled in offshore infrastructure.
A final award recipient, the National Renewable Energy Laboratory, is developing a shared mooring system that would allow individual floating offshore wind turbines to share mooring lines or anchors.
“We want to develop these shared comprehensive mooring solutions to minimize costs, minimize failure risk and also minimize environmental impact for large scale floating wind farms in California,” Matt Hall, senior engineer at NREL, said. “There’s potentially a lot of benefits we can unlock.”
PORTLAND, Ore. — The Bonneville Power Administration’s biggest risks in joining SPP’s Markets+ come down to footprint size and the limited transmission connectivity between the Northwest and Southwest entities most inclined to join the market, agency executives said during a Nov. 4 press briefing.
BPA held the briefing immediately after a sometimes-contentious meeting where agency officials updated stakeholders on the day-ahead market decision process and discussed results from a new production cost model study estimating the agency’s potential economic benefits from participating in either Markets+ or CAISO’s Extended Day-Ahead Market (EDAM). (See related story, Rising Tensions Evident at BPA Day-ahead Markets Workshop.)
The study, prepared by Energy and Environmental Economics (E3), found that BPA stands to realize the greatest savings in a single West-wide day-ahead market and would earn significantly more financial benefits from EDAM than from Markets+ under the most likely scenario reflecting the commitments a handful of key utilities have already made to joining the CAISO-run market.
Despite those findings, BPA has said it plans to hold fast to its staff recommendation that the agency choose Markets+ for more qualitative reasons, such as its independent governance from the get-go and the market design established under that governance. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)
“I think footprint is a fair issue [for risk in Markets+], especially when you look at production cost model studies,” Rachel Dibble, BPA vice president of bulk power marketing, said during the briefing. “That’s really where those [economic benefits] numbers come from … the size of the footprint.”
Dibble and acting BPA CIO Nita Zimmerman agreed that transmission connectivity between the two prospective Markets+ areas was another key point of risk for potential participants.
“It really impacts the ability for power to flow across the region,” Dibble said.
Dibble noted there is some connectivity between the Northwest and Southwest, but it’s “not particularly robust,” especially if NV Energy joins EDAM, a near certainty after the utility in May announced its intention to do so. (See NV Energy to Join CAISO’s Extended Day-Ahead Market.)
“More connectivity would be better, because it does give the chance to do more optimization across the two [regions], but there is some transmission” between them, she said.
“Flow will also go through California on California transmission as well,” Dibble added. “That’s still part of the market, because that transmission … also links the Northwest to the Southwest.”
Libby Kirby, BPA’s market initiatives policy lead, said the agency has few concerns about passing FERC market power screens under a scenario in which the two major parts of Markets+ are held together by limited transmission.
“One piece of the market design in Markets+ includes a ‘conduct and impact’ test,” Kirby said. “So it’s not just, ‘Is there the potential for market power?’ It’s like, ‘Are you actually impacting the price?’ So there’s kind of some additional steps that they check before they actually assess you for market power.”
During the workshop, some stakeholders pointed to the financial risk of BPA paying its $25 million share to fund the Phase 2 implementation phase of Markets+ if it later decides not to join the market, given that the funding is expected to be paid through future transactions in the market. Agency officials said the expense is worth ensuring the West has two viable day-ahead market options.
During the briefing, Dibble said she didn’t yet know when the $25 million would come due if BPA declined to join Markets+ and that such details would be worked out in the Phase 2 contract.
‘A Real Option’
Some workshop participants also expressed concern about BPA’s timeline for issuing a decision on its market choice, urging the agency to push back its May 2025 target to allow more time for legislative developments to play out around the West-Wide Governance Pathways Initiative.
Asked about the impact on the BPA decision timeline of FERC potentially issuing a second deficient letter on the Markets+ tariff, Dibble said: “It’s something we would have to play by ear. It depends on what’s in it, [and] how quickly it could be answered. But I think ultimately, until we have a FERC-approved market, we don’t have a market to join.”
Dibble pointed out that other Western entities aren’t waiting on BPA to make their market decisions. “And what concerns us is that Bonneville just gets pulled into whatever everyone else chooses, instead of it being a proactive choice that we are making based on what’s best for our customers,” she said.
“I don’t believe that creating a West-wide market is something that is Bonneville’s responsibility,” she added, reiterating a point BPA representatives have made throughout the agency’s decision process.
BPA recognizes the impact of its decision and wishes “no harm” to others in the Western Interconnection, Dibble said, “but our obligation and our fiduciary responsibility is to the people of the Pacific Northwest, and our decision will be what is best for the people of the Pacific Northwest and the subset of our preference customers that we have special obligations to.”
The most telling comments about BPA’s firmness on its Markets+ leaning came in response to a question about whether the agency will be looking for signals from the California legislature next year around Pathways’ “Step 2” proposal to implement a more independent governance framework for CAISO’s Western markets.
Dibble said that after a decade of waiting for California to grant CAISO more independence, BPA “decided to go out and work with the region and another market operator to create what we wanted.”
“So to now say, ‘OK, we know what option you have out there that satisfies your needs, but now tell us what your bare minimum is that California could do’ — we’re not going negotiate against ourselves that way,” she said. “We have an option that’s no longer hypothetical. It is a real option that has a real independent market governance structure that satisfies us, and that’s what we’re measuring everything else against.”
Duke Energy on Nov. 7 reported third-quarter earnings of $1.226 billion ($1.60/share), a dip of about 15% from the same period in 2023, as results were impacted by one of the biggest hurricane seasons to hit its territory in memory.
“I am proud of the remarkable response from our employees and utility partners to a historic storm season, including three consecutive hurricanes,” Duke CEO Lynn Good said in a statement. “Our team’s commitment to our customers was unwavering as they worked around the clock to restore 5.5 million outages as quickly and safely as possible and rebuilt large portions of our system in a matter of days.”
Duke’s multiple utility territories were hit by hurricanes Debby, Helene and Milton this season, and it is expected to spend $2.4 billion to $2.9 billion on restoration in the Carolinas and Florida.
The costs impacted third-quarter earnings, but the work continues in the fourth quarter. Most of those costs will be deferred for future recovery in regulatory assets on the condensed, consolidated balance sheets or related to capital projects, the company said.
“My heart goes out to all of those who are directly impacted by these catastrophic storms, especially those who lost loved ones, homes or businesses,” Good said on a quarterly call with analysts.
The firm’s workforce had to repair its system while, in many cases, dealing with the impacts from the storms in their personal lives, she added.
“Our field teams rose to the challenge, working around the clock to restore outages as safely and quickly as possible,” Good said. “And our customer care representatives, corporate responders, community relations managers and state president offices worked tirelessly to keep customers and policymakers informed.”
Helene’s impact on Asheville, N.C., was unlike anything Duke has dealt with before, company President Harry Sideris said on the call.
“Over the three hurricanes, we assembled more than 20,000 resources from across the U.S. and Canada and restored approximately 5.5 million outages in some of the harshest conditions,” Sideris said.
Debby hit in August, knocking out power to 700,000 customers in Florida and North Carolina, though most were restored within a day, he added.
Helene hit both states a month later and impacted every one of the company’s territories, with the hardest hit areas in western North Carolina, upstate South Carolina and Florida’s barrier islands, Sideris said.
“The storm brought record-breaking rainfall and flooding, created landslides, and washed out roads and towns,” he added. In total, Helene led to approximately 3.5 million outages.
Then, as work to repair from Helene was continuing, a week later, Milton hit Florida and knocked out power to an additional 1 million customers there.
“Our success in responding to storms of this magnitude is due to our strategic preparation ahead of the storms, near constant communication with customers and stakeholders, and most importantly, the tireless work of our employees and utility partners,” Sideris said.
Meanwhile, Duke has been in the early planning stages of considering small modular reactors (SMRs), with Sideris saying some of its large customers are interested in using the technology to provide clean power for their operations.
“But any decision as we move forward, we’ll have to address three key items,” Sideris said. “The first one is the first-of-its-kind risk that exists, really, around the maturity of the technology [and] the supply chain. The second item is cost overrun protection, to protect our investors and our customers. And then our third is to make sure that we can protect our balance sheet [when] making these investments.”
Good also commented on the biggest story of the week when she congratulated President-elect Donald Trump for his victory.
“I think the U.S. economy will be a focus and a priority of his, and our industry plays an incredibly important role,” Good said. “So, as we look at what we’re doing here in the Carolinas and also Indiana and Florida, we are putting infrastructure in place in order to serve economic development and believe there are lots of opportunities to work together.”
Rhode Island voters overwhelmingly approved a ballot proposal Nov. 5 to dedicate $53 million in bonds to several environmental infrastructure projects, including $15 million for the Port of Davisville, which is transforming into an offshore wind staging point.
The R.I. Ports Coalition, a maritime industry advocacy group that campaigned for the proposal, said the funding “will finance new berthing space, … prepare the port to serve as a key offshore wind hub for the North Atlantic and play a critical role in delivering clean energy to homes across the Northeast.”
The Port of Davisville, Rhode Island’s only public port, is close to the large offshore wind lease area southeast of the state, which hosts the operating South Fork Wind facility, the under-construction Vineyard Wind and Revolution Wind projects, and several other proposed projects.
“These infrastructure development projects will create additional jobs, position [the Quonset Business Park] to serve as a critical offshore wind hub in the North Atlantic, support Rhode Island’s clean energy goals and maintain the port’s position as one of the nation’s top auto importers,” the coalition said in a press release.
In 2023, the port hosted 57 offshore wind vessels after opening “a specialized harbor” intended to accommodate smaller vessels. Quonset Development Corp. (QDC), which oversees the port, is hoping to scale up this operation in the coming years.
“Given its proximity to the offshore wind leasing areas, the Port of Davisville is the ideal location for berthing offshore wind vessels, and with additional wind farms finalizing permitting, the port will continue to grow as a central location for marine logistics and operations,” QDC wrote in its 2023 annual report.
QDC has outlined plans for a new pier to “offer specialized berthing spaces to accommodate a variety of offshore wind vessels and cargoes,” along with new support docks and a boat ramp to “accommodate smaller boats and the short-term docking needs of small businesses, emerging companies and research and development organizations.”
However, the annual report identified a $40 million funding gap in the port’s master plan; the approved state bond will help address this need.
The green bond approval will also give $2 million to restore coastal habitats to help improve climate resilience, $10 million to the Rhode Island Infrastructure Bank for municipal resilience, $5 million to preserve working agricultural lands, $5 million to clean former brownfield sites and $3 million to preserve open space.
CARMEL, Ind. — MISO members will likely have to add 343 GW of installed capacity by 2043 to meet state policy goals while maintaining resource adequacy, the RTO said in preliminary results from its annual Regional Resource Assessment.
Of that 343 GW, members have already planned to add 163 GW in installed capacity. According to its early results, MISO said that leaves members filling in an additional 180 GW over the next 20 years.
“Achieving 343 GW of additional installed capacity by 2043 would require an average installation of 17 GW per year over the next 20 years to achieve, which is more than 3.5 times greater than the recent installation rate,” MISO Director of Strategic Initiatives and Assessments Jordan Bakke told the Resource Adequacy Subcommittee on Nov. 6.
From 2020 through 2022, MISO experienced an average 4.7 GW/year worth of installed capacity additions. Between 2029 and 2043, MISO foresees 27 GW in thermal retirements and 11 GW in thermal additions based on its members’ plans.
Bakke said that by 2043, MISO also estimates that wind and solar would account for 62% of installed capacity and have the potential to reach 87% of annual energy served.
“The purpose is not to speculate on the resource buildout but report back on what our members are planning,” Bakke said of MISO’s assessment.
MISO remains adamant that in 20 years’ time, the loss-of-load risk will move away from afternoon summer hours to concentrate in early mornings in winter. MISO also said systemwide ramp-up needs will pick up, with peak ramping needs occurring outside of summer and in evening, rather than morning, hours.
The number of additional megawatts MISO is signaling a need for is up sharply from 2022, when its assessment found members likely needed to add 200 GW of new installed capacity by 2041. (See MISO: 200 GW in New Capacity Necessary by 2041.)
In November 2023, a condensed version of the assessment also observed that retirement announcements are trouncing stated capacity additions. The grid operator said that beyond what members are planning, the footprint likely needs an additional 13 GW of accredited (not installed) capacity by 2027, 27 GW by 2032 and 34 GW by 2042 to fulfill demand. (See MISO Continues to Find Mounting Retirements, Inadequate New Capacity in Abridged Resource Assessment.)
MISO will hold a dedicated stakeholder workshop Dec. 18 to go over final results of the assessment.
Newly minted American Electric Power CEO Bill Fehrman held his first earnings call with financial analysts Nov. 6, promising to “embrace large load opportunities,” use expertise in 765-kV transmission and deliver more positive regulatory outcomes.
“I’m honored to join a leader like AEP at a pivotal time for both the organization and our industry,” Fehrman said during the call. “I need to establish a record of delivering on promises to you while demonstrating goodwill to our regulators and customers.”
AEP CEO Bill Fehrman | AEP
Since replacing Julie Sloat as CEO in August, Fehrman said he has met with staff and stakeholders — including four governors and more than 30 regulators and legislators — across AEP’s 11-state footprint for “robust” discussions about critical initiatives. (See AEP Selects Industry Veteran as Next CEO.)
He said those exchanges have helped shape AEP’s vision for the future.
“AEP has built a strong foundation for growth,” Fehrman said, alluding to a transmission system that represents 55% of the company’s total revenue stream. “However, we can improve reliability, streamline costs, use technology better and put power in the hands of local leaders to build financially strong utilities in our communities.”
That will include what he called an “optimization exercise” as the company “retools personnel and processes” over the coming months.
“The bottom line here is we have made progress transforming a business over the past three months, but we have significantly more wood to chop,” Fehrman said.
Still, AEP has increased its five-year capital plan to $54 billion, all allocated to its regulated businesses for reliability purposes and to meet demand growth. It has allocated 63% of that capital to wires functions and 26% to new generation, including renewables. The company said it expects rates to go up less than 3% annually through 2029.
The Columbus, Ohio-based company is part of a joint venture with FirstEnergy and Dominion Energy that is pursuing several multistate extra-high-voltage transmission projects in PJM. AEP is also eyeing potential 765-kV projects in ERCOT, PJM and SPP.
“We have a big opportunity in ERCOT around 765[-kV] down there in the event that they decide to go that way. … [There is] a significant opportunity on the various backbone growth areas for Texas that just alone is a good $4 [billion] or $5 billion of opportunity potential on the 765[-kV] front,” Fehrman said. “The fact that AEP is essentially the only U.S. company that knows how to build and operate 765[-kV] gives us a strong competitive advantage.”
AEP also recently filed a settlement agreement with the Public Utilities Commission of Ohio to help insulate customers from the cost risk of building infrastructure to connect data centers. It has filed similar large-load modifications in three other states and a complaint with FERC related to co-located load arrangements. (See AEP Ohio Proposes Revised Data Center Tariff.)
“Load growth from data center demand has the potential to benefit all stakeholders, including investors, customers and local communities, but only with fair and proper cost allocation,” Fehrman said. “We don’t have an issue with data centers looking to use nuclear power plants as an energy source. But we do have an issue when they use the transmission system and try not to pay for it. That’s a problem for us because that cost gets shifted to other customers.”
Fehrman did not comment on AEP’s discussions with the U.S. Securities and Exchange Commission over the Ohio nuclear bribery scandal, in which FirstEnergy was found to have paid state legislators to subsidize its plants. The SEC has twice subpoenaed AEP since 2021, but the company and its officials have not been criminally charged. Although the company has steadfastly said it does not believe it was involved in any “wrongful conduct,” it has set aside $19 million as a contingency. (See Feds: FE Paid $61M in Bribes to Win Nuke Subsidy.)
AEP reported third-quarter earnings of $959.6 million ($1.80/share). That was a slight improvement from the same period a year ago, when earnings came in at $953.7 million ($1.83/share).
The company’s share price fell to $96.25 on Nov. 6 on a down day for the S&P 500 Utilities index, dropping just over 4% from its $100.40 close Nov. 5. AEP’s stock rebounded slightly Nov. 7 and closed up 8 cents.
PORTLAND, Ore. — A largely polite discussion at the Bonneville Power Administration’s Nov. 4 day-ahead market participation workshop ended on a testy note as critics of a BPA staff recommendation that the agency join SPP’s Markets+ urged staff to rethink their position and consider once again delaying a decision beyond May 2025.
The workshop was the first BPA has held since announcing in August that it would postpone its final decision — originally scheduled for this month — into next year, with a draft decision targeted for March.
The discussion covered BPA’s intention to spend $25 million to fund Phase 2 of Markets+, the agency’s thoughts on the West-Wide Governance Pathways Initiative’s “Step 2” proposal and its reasons for delaying its decision.
But the key focus of the workshop was the recently released results of a production cost model study that Energy and Environmental Economics (E3) performed for BPA to estimate the comparative benefits of joining either Markets+ or CAISO’s Extended Day-Ahead Market (EDAM) under various market footprint scenarios and tested under different sensitivities, such as conditions of low hydro or stressed load.
The study, which supplements the Western Markets Exploratory Group (WMEG) study that E3 produced for BPA last year, found the agency would gain significantly more financial benefits from participating in EDAM rather than Markets+, with the largest projected take in a single, West-wide market: $251 million in savings in 2026 — compared with a “Business as Usual” (BAU) case — declining to $147 million in 2035.
But in an Oct. 31 press release announcing the study results, BPA made clear the findings would not shift its leaning in favor of the SPP market, although they would still factor into its final decision. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)
BPA officials reemphasized that view during the Nov. 4 workshop, at which two of the study’s authors, E3’s Jack Moore and Yuchi Sun, detailed the study’s structure, methodology and results.
Moore reiterated a point that E3’s Arne Olson made a year ago with the release of BPA’s original WMEG study: that the supplemental study, with its focus on production costs, was not designed to capture potential savings from lower capacity needs based on resource and load diversity, the ability to procure resources over a wider geographic area and coordinated regional transmission planning.
“It is useful to note that those investment savings [and] investment impacts can be significant and sometimes larger even than production cost impact in the long run,” Moore said.
EDAM supporters in the Northwest — and elsewhere — have repeatedly argued that point when urging BPA to join a single Western market based on EDAM rather than on Markets+, the latter of which will inevitably split the region into two markets given the unlikelihood that California utilities would choose the SPP-run market and the number of utilities already lining up for CAISO’s platform.
But BPA officials at the workshop pointed to the importance of other factors not captured in the E3 study, some of which are qualitative and difficult to measure in dollars, such as the benefit of participating in a market with independent governance from the get-go.
Others are more quantitative, but still difficult to estimate in a study, such as the absence of scarcity pricing in the EDAM, market power mitigation practices, the impact of energy bid caps and the potential for CAISO — as both market operator and balancing authority participating in its own market — to “bias” operations in its own favor during stress events.
Sara Eaton, a BPA senior policy specialist, said the agency even questioned whether the supplemental study accurately reflects the financial impact from stressed grid events.
“We don’t see the pricing levels for scarcity events near the impact that we see them in in today’s world,” Eaton said. “That’s an impact that we’re not seeing reflected in the studies. Our exposure to those sorts of pricing levels don’t get incorporated into the cost” represented in the study.
Quantitative vs. Qualitative
Representatives of the large number of Northwestern publicly owned utilities that have advocated for BPA to join Markets+ backed the agency’s approach of giving the supplemental study limited weighting in its decision.
“How certain are we that the analysis actually accurately represents what would happen?” Nicolas Garcia, policy director with the Washington Public Utility Districts Association (WPUDA), asked, noting the wide range of benefit estimates included in the study. “I do think we need to take [the findings] with a little bit of a grain of salt, and I would recommend perhaps using a few more zeros and a little less ones and fives, just because I think that even though that may be what the analysis came up with, the fact of the matter is that these things are a little bit uncertain.”
Michael Linn, director of market analytics at the Portland-based Public Power Council (PPC), said his group supported “broadening the conversation beyond the production cost studies.”
Linn said the E3 study is “clearly very valuable” and that E3’s work “shows directional benefits” of BPA’s participation in a day-ahead market. “But we also see that there’s considerable variability across those modeled outcomes.”
Both Linn and Garcia emphasized the importance of market factors that are “harder to quantify.”
Linn also reemphasized Eaton’s point about the unquantified cost of resource scarcity events.
“Every year there’s some sort of issue that is a $100 [million] to $200 million issue for everybody [and] involves reliability, and the market framework where Bonneville has an equitable say in the resolution of those policy choices needs to be highly prioritized, from PPC’s perspective,” Linn said.
Garcia said the issue of governance should carry greater weight than a study showing EDAM would provide more economic benefits for BPA.
“I will say that my members, which represent about 20% of Washington’s load, very much want independent governance, even if it doesn’t come up with anything different in terms of value. We like democracy. We like independence,” he said.
Rachel Dibble, BPA vice president of bulk power marketing, said governance determines market design, which in turn determines who gains and loses under stressed grid conditions.
“When you have a governance model that has a particular responsibility to one market participant, that’s reflected in the market design, and it’s reflected in the way that benefits and costs are allocated,” Dibble said, pointing to CAISO’s policy of curtailing wheel-throughs of “low-priority” energy transfers through its balancing area during emergency conditions, which sparked the ire of Arizona utilities during stressed grid events in the summer of 2020.
Sidney Villanueva, an attorney representing Avangrid Renewables, asked for more specificity on how governance affects market design.
Dibble explained how all Markets+ participants have voting rights and are responsible for designing the market and writing its protocols, which “really encourages collaboration.”
“So, we have differently situated entities that then can come to the table, and there is a lot of time spent in the work groups hashing through all of these issues and trying to get to consensus and through a collaborative process to find a solution that works for everyone,” she said.
‘Head-scratcher’
Henry Tilghman, a consultant representing the Northwest & Intermountain Power Producers Coalition — an EDAM supporter — said BPA will have to contend with CAISO’s market design regardless of whether it joins the EDAM and asked how joining Markets+ will “have any impact” on the issues the agency is concerned about.
“It’s not that we’re thinking that the Markets+ governance structure is going to resolve systemic issues in California, but why would we export that governance structure to a bigger footprint when we’ve seen these issues not get resolved historically?” Eaton asked.
Villanueva questioned whether the Markets+ process could guarantee an “equitable result” for all market participants, prompting BPA’s Libby Kirby to reply, “Democracy doesn’t make everybody happy all the time. We know that.”
Tilghman said it was a “head-scratcher” that BPA would not provide funding for the Pathways Initiative, given the size of BPA loads that will end up in EDAM.
Fred Heutte, a senior policy adviser at the NW Energy Coalition (another EDAM supporter), called out Dibble’s comment about CAISO’s policy of curtailing wheel-throughs.
“The question is: Has CAISO ever curtailed a high-priority wheel-through? The answer is ‘no,’” Heutte said, adding that the ISO has curtailed low-priority wheel-throughs “because that’s the structure that they are supposed to follow.” (See FERC Upholds CAISO Wheel-through Rules.)
“If they didn’t handle the high-priority wheel-throughs the way they have, then FERC would be on them in a minute,” he said. “And I’m really unhappy that Bonneville continues to allege that CAISO has not behaved properly with regard to priority wheel-throughs.”
Megan Capper, energy resources manager at Eugene Water & Electric Board, said her utility agrees with BPA about the importance of independent market governance but doesn’t believe it’s the only factor, citing transmission connectivity and footprint size as other critical elements to consider.
“It just feels like, with this [E3] analysis, that independent governance, if you’re going to put a price tag on it, is very expensive,” Capper said, recommending that BPA take an additional six-month delay to see how the Pathways Initiative plays out.
“We’ll take the feedback,” responded Nita Zimmerman, acting CIO at BPA. “At this time, as we’ve stated, we’re staying on our timeline. We’re looking forward to seeing where Pathways has gotten when we get to the point of releasing our draft decision in March and again in May.”
Just as the workshop was both heating up and winding down, Stefanie Johnson, strategic adviser at Seattle City Light (another EDAM supporter), joked that the last 45 minutes of the workshop seemed to cover two days’ worth of material. She said she would send BPA a list of questions “because I felt like I wasn’t supposed to ask them.”
“It’s very contentious these days. That’s why we’re here on a Monday,” Johnson said.
BPA is seeking comments on the workshop by Dec. 6 and plans to hold another two-day workshop in January.
