FERC has ordered two New York utilities into hearing and settlement judge procedures over their proposed return on equity (ROE) on transmission investments to support the state’s renewable energy goals (ER23-1816, ER23-1817).
The commission’s Dec. 4 order accepts for filing Rate Schedule 19 formula rate protocols and templates for Avangrid’s New York State Electric & Gas (NYSEG) and Rochester Gas and Electric (RG&E) effective July 3, 2023, subject to refund.
In response to a protest by the New York Association of Public Power (NYAPP), FERC called for hearing and settlement proceedings on the utilities’ proposed 10.87% “ceiling base” ROE — a fixed value in the formula rate that would be subject to a lower ROE authorized by the New York Public Service Commission.
NYAPP said FERC should adopt the ROE and capital structure approved by the New York commission in the most recent retail case for NYSEG — 9.2% for 2024, with a capital structure of 52% equity and 48% debt and customer deposits.
FERC agreed that the 10.87% ROE had not been shown to be just and reasonable. “We find that applicants’ proposed ceiling base ROEs raise issues of material fact that cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures ordered below,” it said.
Schedule 19 and the Cost Sharing and Recovery Agreement (CSRA) — a voluntary participant funding agreement among the six New York state-regulated public utility transmission owners — are intended to provide a cost recovery and allocation framework for local transmission upgrades needed to meet the state’s Climate Leadership and Community Protection Act and the Accelerated Renewable Energy Growth and Community Benefit Act.
Historically, local transmission upgrades have been funded via bundled, local transmission and distribution rates. Under the CSRA, the costs are instead shared statewide and recovered on a volumetric load-ratio share basis from load-serving entities.
FERC’s order requires the settlement judge to file a report on the status of the settlement discussions in 60 days after the judge’s appointment.
While FERC sided with NYAPP on the ROE issue, it rejected the group’s contention that the formula rate misallocates administrative and general expenses.
The proposed Cross-Tie transmission project — a 214-mile line across Utah and Nevada that’s seen as a missing link in the Western transmission system — is moving through the federal approval process with a targeted in-service date in 2027.
TransCanyon LLC has proposed the 500-kV HVAC line connecting PacifiCorp’s Clover substation in Utah with NV Energy’s Robinson Summit substation in Nevada.
The U.S. Bureau of Land Management, the lead federal agency for the project, released a draft environmental impact statement for the proposal last month. BLM expects to decide in 2024 whether to grant the developer’s right-of-way request.
TransCanyon is a joint venture between Berkshire Hathaway Energy’s BHE U.S. Transmission and Pinnacle West Capital, the parent company of Arizona Public Service (APS).
The 1,500-MW Cross-Tie transmission project will cost an estimated $750 million and is expected to begin service in 2027, according to TransCanyon’s website. TransCanyon plans to develop, own and operate the transmission facilities.
Delivering Renewables
TransCanyon called Cross-Tie a “missing pathway” in the Western transmission system that would enhance resilience and reliability and boost the delivery of renewable energy.
At its eastern end, Cross-Tie would connect to the southern tip of PacifiCorp’s 416-mile Gateway South transmission line, which runs across Wyoming, Colorado and Utah.
At Cross-Tie’s western end is the Robinson Summit substation, the northeastern vertex of NV Energy’s planned transmission triangle around Nevada. The triangle consists of the proposed Greenlink North and Greenlink West lines and the existing One Nevada Line.
TransCanyon said that Cross-Tie, in concert with PacifiCorp’s Energy Gateway projects, the Greenlink projects and the Harry Allen-to-Eldorado project in southern Nevada, would provide needed transmission capacity between the Intermountain West and the Desert Southwest.
“This additional transmission capacity would facilitate access between the significant existing and planned renewable resources, primarily wind in Wyoming and wind or solar resources in central Utah and eastern Nevada, to the diverse utility load profiles in the Desert Southwest/California,” TransCanyon said in a development plan submitted to the BLM.
In addition, Cross-Tie might reduce solar curtailments and battery storage needs in California and the Desert Southwest, the plan said.
During a virtual public meeting hosted by BLM on Dec. 5, one attendee asked whether any contracts are in place that would guarantee Cross-Tie will deliver renewable energy.
TransCanyon representative Roger Yensen said the developer plans to complete the environmental review process with BLM before entering into contracts.
But given its strategic location, Yensen said, “we anticipate there will be a significant portion of energy that will be carried on the Cross-Tie [project] that will be from renewable resources.”
In October, the U.S. Department of Energy announced it would become an anchor off-taker for three interstate transmission projects, including Cross-Tie. (SeeDOE to Sign up as Off-taker for 3 Transmission Projects.) Yensen said negotiations with DOE are underway.
TransCanyon isn’t currently planning to connect Cross-Tie to the Intermountain Power Plant in Utah, even though the transmission project’s path runs near the facility. But that could be considered in the future, according to the development plan.
Alternative Routes
In its environmental review of Cross-Tie, BLM is examining the developer’s proposed transmission path as well as several alternatives that would add four miles to about 150 miles to the route. BLM staff said the transmission project will cost roughly $3.5 million per mile.
One alternative route addresses concerns from the town of Leamington, Utah, about the project’s impacts on scenic views.
“Why would any project be proposed that destroys the view the residents of Leamington have enjoyed and cherished for over 150 years when a viable alternative is readily available?” Leamington’s mayor said in a written comment submitted for the virtual meeting.
Other alternatives were designed to reduce impacts to cultural resources, environmentally sensitive areas or the U.S. Department of Defense’s Utah Test and Training Range. BLM has not yet selected a preferred alternative.
In addition to the virtual public meeting, BLM held four in-person meetings on Cross-Tie in late November.
The deadline to comment on the draft environmental impact statement is Jan. 2.
ORLANDO, Fla. — Several MISO stakeholders took exception to the RTO’s proposal before FERC to cap the volume of interconnection requests it accepts annually.
MISO made two filings with FERC last month to establish an annual megawatt cap on projects, enforce stricter proof of land use, enact automatic and escalating monetary penalties for withdrawals, and increase milestone fees for its generator interconnection queue (ER24-340 and ER24-341). (See MISO’s More Stringent Interconnection Queue Rules Go Before FERC.)
DTE Energy said a queue cycle cap would be “unprecedented” and argued it won’t address “the root cause of MISO’s inability to timely process interconnection requests.”
DTE said it’s not the number of projects overall, but the percentage of speculative projects in the queue that’s the problem. Developers have resorted to “over-saturating the interconnection queue with projects as an insurance strategy to secure a position” because of long wait times in the queue, DTE argued. DTE supported the other aspects of MISO’s queue rule changes.
MISO has said there are only so many potential generation projects it can simultaneously consider in interconnection studies while still achieving accurate results. (See MISO Relaxes Proposal on Stricter Queue Ruleset.)
But the Coalition of Midwest Power Producers argued MISO wants to impose a megawatt cap “without articulating how a lower volume will ensure accelerated queue processing.” The coalition said MISO didn’t detail “unique processes or additional computing power to resolve the volume and study pace issues that have been the albatross of the MISO queue process.”
NextEra Energy agreed MISO didn’t provide evidence to show a cap will “remedy or mitigate the factors leading to its unwieldy, inefficient and untimely interconnection queue.” It said the cap will stymie competition and create barriers to entry for smaller generation developers.
Ameren said it thought the cap “is a blunt tool that is not fully thought out and may result in unjust outcomes.”
Xcel Energy, on the other hand, said MISO has sufficiently explained a megawatt cap is key to alleviating the overstuffed queue. Entergy agreed the sheer size of the interconnection queue is interfering with “realistic” study results and not giving developers a clear picture of whether they should proceed with generation projects.
The Organization of MISO States also threw its support behind the cap, saying a “backstop mechanism is needed — at least temporarily — to ensure MISO can produce realistic network upgrade studies based on a smaller, more manageable queue size.”
“MISO’s queue is oversaturated with projects that are vying to identify the cheapest locations to interconnect, causing MISO to choose to effectively shut down its interconnection queue,” OMS told FERC.
MISO’s current generator interconnection queue contains more than 1,300 projects at nearly 230 GW — nearly double MISO’s summertime peak demand.
“It is not reasonable to expect MISO to continue to try and work through this level of requests in its queue process,” Xcel said.
In a joint protest, the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance argued that limiting projects annually is diametrically opposed to the rapid transition of clean energy resources. They said it’s only natural MISO’s queue has expanded rapidly in recent years.
“If accepted, the cap proposal would create perverse incentives that will create havoc, increase uncertainty and discriminate against the very clean-energy resources that the region needs,” the clean energy groups contended.
Alliant Energy argued MISO’s proposal to cap queue cycles is an odd choice when the grid operator has been telling stakeholders new capacity additions are crucial. Alliant referenced OMS’ most recent resource adequacy survey showing the footprint runs the risk of a 9-GW capacity shortfall by 2028.
MISO Leadership Hopeful for ‘More Confident, Less Speculative’ Projects
At MISO Board Week in Orlando, Executive Director of Resource Planning Scott Wright said even though there are some complaints, stakeholders’ comments reveal “a broad consensus that the staggering queue line was unsustainable.”
Wright said an annual megawatt cap on projects, an automatic penalty scheduled for withdrawal and increased milestone fees will encourage a “more confident, less speculative” class of projects to enter the queue.
“Many of the projects in the queue are highly speculative despite our past rule changes to use a ‘first-ready, first-served’ approach,” he said. Wright also said MISO’s existing withdrawal process are too “low-consequence.”
Wright added that the “staggering” number of queue projects is developers’ “rational” response to more favorable economic conditions for renewable energy development. He said it’s natural MISO found itself having to tighten requirements, so its historically “high-quality” queue isn’t compromised.
Wright said since the last Board Week in September, members have announced more retirement plans, with Michigan adopting a clean energy pledge by 2040.
MISO predicts it will add about 250 GW in installed capacity over the next 20 years, but it will only amount to a 38-GW increase to MISOS’s current 172 GW in accredited capacity.
50 GW in Greenlit and Unfinished Projects Haven’t Budged
Today, 50 GW across 316 projects are awaiting construction, with 50% of those developers saying wait times will average 650 days until commercial operation. Most of the on-hold projects are solar generation, accounting for 32 GW.
By year’s end, Wright said that amount could grow to nearly 60 in approved but unbuilt generation projects.
Vice President of System Planning Aubrey Johnson said nationally, 260 GW in generation projects have signed interconnection agreements in the organized markets and yet remain unconstructed. Johnson said that side of the issue deserves more awareness in conversations about the country’s interconnection woes, when usually, inadequate transmission planning is emphasized.
“This is something that needs national attention. It’s something that we call attention to at every turn,” Johnson said.
FERC on Nov. 6 rejected new contracts the Wabash Valley Power Alliance had filed for its members and a distributed generation policy proposed by the generation and transmission cooperative (ER24-36).
The commission said the rejections were without prejudice and opened a show cause proceeding (EL24-16) to determine whether Wabash’s tariff is just and reasonable and not unduly preferential.
Indiana-based Wabash serves wholesale customers in both MISO and PJM, meaning it has to buy transmission and ancillary services from both RTOs. However, two of its members — Tipmont Rural Electric Membership Cooperative and Citizens Electric Corporation — alleged that Wabash failed to separate out those purchases in contracts with those customers, running afoul of FERC’s unbundling rules.
The new contracts, filed in 2023, should be subject to FERC Order 888 because its unbundling rules have been in effect for all contracts since July 1996, the complainants argued.
Wabash argued that, while Tipmont and Citizens are members of the alliance, the two co-ops declined to sign 2023 contracts and should not be allowed to participate in the FERC proceeding. The pair’s arguments are based on existing contracts and should not have an impact on FERC’s review of the 2023 deals, Wabash said.
FERC found that the contracts do not run afoul of the commission’s unbundling rules because they do not establish a bundled rate, but merely incorporate the rate established by the Wabash tariff, which is on file with the commission.
But the commission said it could not accept the contracts as written in part because they require member co-ops to provide 31 years of notice to avoid an automatic five-year extension.
“While we do not here decide whether it might ever be just and reasonable to include a provision requiring 31 years of notice to avoid an automatic five-year extension in a requirements agreement, it is incumbent on the applicant in an FPA section 205 proceeding, i.e., Wabash, to affirmatively demonstrate that such a provision is just and reasonable with regard to the agreement presented to the commission for its approval,” FERC said. “Wabash does not support this proposal other than to observe that the executing members desired the long-term stability of their contractual relationship with Wabash and that they signed the 2023 contracts.”
Wabash did not adequately show its proposal to be just and reasonable, instead focusing more on Tipmont’s arguments against it and claiming that the co-op failed to prove the 31-year notice requirement was unjust and unreasonable, the commission said.
Tipmont and Citizens also argued that several policies that should be included in the tariff are not. In any future filing, Wabash will have to include them or show that they do not affect rates and service significantly.
The two members also filed protests against “Buyout Policy D-2” in the contract, which determines the amount of money a member would owe Wabash when departing from the cooperative. Tipmont is pursuing exit from Wabash in a separate, ongoing proceeding, and Citizens complained that Wabash just applied the methodology from that case to all members even though it was only designed for Tipmont.
FERC also rejected Buyout Policy D-2, saying Wabash failed to make clear how it will use any methodology developed in Tipmont’s exit case and instead relied on unclear language saying it would take the case “into account” when dealing with future exits.
FERC additionally rejected Wabash’s Distributed Generation Policy, which determines how much of that type of resource its members can use. The commission found fault with Wabash’s proposal that it could waive that policy for any given member based on 75% approval of its board.
The rule “would give the board unfettered discretion when considering a member request to waive the terms of a policy that the commission had otherwise found just and reasonable,” FERC said.
While none of the contracts ran afoul of FERC’s unbundling rules, the commission said it could not say the same for the tariff, which will be the subject of the show cause proceeding. Unbundling is needed to implement non-discriminatory open access transmission, and it is unclear whether the tariff provides it, FERC said.
Wabash will have to come back to FERC within 60 days to either alter the rules in question or explain why they do not run afoul of unbundling requirements. Interested parties will be able to file comments 21 days later.
Wabash can revise its tariff to deal with the unbundling issues under Section 205 of the Federal Power Act, which would place the Section 206 show cause proceeding in abeyance, FERC said.
BOSTON — New England policymakers and stakeholders must not overlook the need for electric affordability in the energy transition, officials from Massachusetts, Rhode Island and Connecticut told attendees of the New England Power Generators Association’s fifth annual New England Energy Summit on Dec. 6.
Rhode Island Public Utilities Commission Chair Ron Gerwatowski compared juggling the priorities of decarbonization, reliability and affordability to “adopting a coyote, a wolf and a bunny rabbit, putting them in the same corral, and asking how you can get them to get along without harming each other.”
“The coyote and wolf might find a way to coexist, but that bunny rabbit, I don’t know about it,” Gerwatowski told attendees.
The bunny rabbit, in Gerwatowski’s analogy, is affordability. With decarbonization and reliability considered nonnegotiable in the region, affordability is being overlooked, he said.
“When we add up the combination of rising costs from distribution, transmission, regional markets and renewable procurements, electricity rates are driven upward, and affordability gets severely strained,” he explained.
To prevent rates from skyrocketing, Gerwatowski said that policymakers should consider impacts on ratepayers when weighing different decarbonization strategies, and potentially avoid funding transportation and heating decarbonization initiatives through electric rates.
Additionally, states should consider providing stronger price signals and demand response incentives for consumers to reduce their electricity consumption during times of peak loads to limit the overall demand on the system and bring down prices, he said.
“I’m not suggesting that we slow down our pursuit of a carbon-free future,” Gerwatowski said. “What I’m saying is that it’s not too late to adjust the way we plan for our future.”
Rebecca Tepper, secretary of Massachusetts’ Executive Office of Energy and Environmental Affairs, agreed with Gerwatowski’s concerns about affordability and noted that the Massachusetts Department of Public Utilities is planning to open a docket focused on rate affordability.
“Addressing things on the demand side is extremely important,” Tepper said, pointing to the results of ISO-NE’s 2050 Transmission Study, which found that reducing the 2050 winter peak load from the projected 57 GW to 51 GW would save the region roughly $8 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) Tepper floated the idea of a “6-GW Earthshot challenge.”
Tepper added that the region should “think as creatively as we do about generation with demand response. We’ve all started thinking about energy efficiency as our first fuel; reducing demand needs to be our second fuel.”
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said collaboration between Northeastern states around clean energy generation and infrastructure will be “the key to addressing affordability challenges.”
Dykes added that collaboration can both enable states to unlock lower prices through larger contracts and help states share the costs of projects that provide regionwide reliability benefits.
“We’re benefiting in Connecticut from the investments that Massachusetts is making in transmission to import hydropower,” Dykes said. “The entire region is freeriding on the support that Connecticut ratepayers are providing to prevent the Millstone nuclear facility from shutting down.”
Building Local Support
The officials and other industry speakers also stressed the importance of building local support for clean energy projects by communicating the climate benefits and providing tangible local incentives for communities to host infrastructure.
“We need to get communities excited about the energy infrastructure that’s in their towns,” Tepper said.
The “fundamental question,” said Mike Cuzzi of Cornerstone Government Affairs, is whether “the social and political will is there to build these things.”
Cuzzi added that building community partnerships early in the development process and speaking to the self interest of local communities are essential aspects of building support for projects.
“Listening to the people, early, upfront and understanding where you’re going to have problems … all those pieces are very important,” Cuzzi said. “Even that may not lead to success, but you’re at least going to win some degree of the public relations war.”
Gerwatowski called upon environmental activists and organizations that advocate for clean energy legislation to support clean energy infrastructure in regulatory proceedings and help communicate the climate benefits of electric infrastructure to local communities.
“They’re noticeably absent in these proceedings,” Gerwatowski said. “Why aren’t you coming out in droves like when it’s time to pass a bill?”
Massachusetts has moved to discourage new investment in natural gas infrastructure by blocking utilities from recovering costs unless they can show they first considered non-gas alternatives.
The order issued Dec. 6 by the Department of Public Utilities in Docket No. 20-80 follows more than three years of work by the DPU to engineer a reduction in the state’s greenhouse gas emissions.
But it is only a first step, an attempt to discourage and dissuade rather than to ban. Ratepayer discretion is preserved, and the order’s effectiveness will depend in large part on the decisions they make.
There are many more steps to come as the DPU works to balance all the moving pieces, competing interests and still-unknown factors to create a climate-protection solution that is workable, affordable and equitable.
The Acadia Center, which had been pushing for a strong statement by the DPU, applauded Wednesday’s order, calling it a potentially transformative measure that addresses many of the clean energy advocacy group’s priorities.
Eversource Energy and National Grid, which combined have more than 1.5 million gas customers in the Bay State, said in separate statements they support the state’s net-zero goals and are reviewing details of the 140-page order.
Consider the Options
With the order, the DPU no longer will allow a utility to recover what it spends on natural gas infrastructure unless the utility can prove it considered alternatives such as electrification or district geothermal heating. It also will not allow cost recovery for efforts to promote expansion of natural gas.
It sets the framework for much more, including management of stranded costs for utilities, cost control for customers, environmental justice and workforce transition.
In announcing the order, DPU Chair James Van Nostrand called it a “forward-thinking framework that charts a path for moving toward clean energy and enhancing the state’s ability to achieve its climate goals while ensuring a fair, equitable and orderly process.”
The gas utilities will need to file climate compliance plans every five years and undertake pilot projects with the preferred alternatives to gas — electrification and networked geothermal.
The order excludes renewable natural gas and hydrogen as potential decarbonization solutions. Concerns surround the cost, availability and carbon footprint of RNG and hydrogen. Both may well have a role in Massachusetts’ journey to net-zero status, the DPU said, but at this stage of the process, utilities cannot use them as an alternative to fossil natural gas to comply with Wednesday’s order.
Some other components of the wide-ranging order:
The gas utilities each have their own mechanism to calculate the cost of line extension; the DPU will move to standardize them.
Close coordination will be required between gas and electric utilities because reduced gas use likely means increased electric use, and grid capacity may vary by region, or even from one neighborhood to the next.
The cost of the clean energy transition may be considerable, but the need for the transition is too pressing to slow the timetable. Instead, the DPU in a separate proceeding will investigate solutions to the cost burden the transition will place on low- and middle-income ratepayers. A change in its statutory authority likely will be needed for it to carry out some of those solutions.
Utilities will continue to recover the billions of dollars they have invested in natural gas infrastructure — the order affects future efforts, not past spending. But the DPU will scrutinize future infrastructure spending to limit future stranded costs.
It is important, the order states, for gas utilities to move beyond “business as usual” and actively participate in developing innovative solutions in what is expected to be “an exceedingly complex undertaking.”
The Massachusetts Clean Energy and Climate Plan calls for net zero greenhouse gas emissions by 2050, with an emissions reduction of at least 85% from 1990 levels.
Reactions
Wednesday’s order prompted responses from some of those affected.
National Grid said: “We support the commonwealth’s goals and are committed to achieving net zero emissions. Our proposed strategy will reduce energy use, right-size and decarbonize our network, and maintain affordability and reliability for customers, while recognizing the critical role the gas networks play in keeping people warm and our economy going. We are reviewing the order and will have more to say later how we think it achieves these outcomes.”
Eversource said: “We are working every day to help the commonwealth achieve its nation-leading decarbonization goals and we remain fully engaged with other utilities and stakeholders to define a practical path forward to reach them. We are currently reviewing the order and are thankful to the Department of Public Utilities for bringing together all stakeholders in an open and transparent process. Our customers’ energy needs are diverse, and it’s important that the clean energy transition provides access to safe, reliable and affordable energy for everyone.”
The Beyond Gas Coalition said: “Today’s ruling is a historic and transformative climate decision. Not only is the DPU’s decision a major victory for the millions of Massachusetts gas customers who would otherwise be stuck paying for risky, unproven gas utility ventures, but sets a precedent for utility regulators across the country to rein in gas utility spending. From the outset, it has been clear that plans to blend ‘renewable’ natural gas with hydrogen for home heating would not only fail to measurably reduce emissions, but would be dangerous, expensive and not feasible. Highly efficient electric equipment, paired with weatherization and better insulation, is the only viable way to affordably build healthier communities and meet Massachusetts’ ambitious climate goals. The DPU is absolutely right to throw cold water over these risky utility plans and instead protect consumers.”
Gas Transition Allies said: “The Department makes clear that the commonwealth is committed to ensuring that there is a just transition that includes equity for both customers and gas workers. Gas companies must not only address the potential for stranded assets that risk leaving customers holding the bag for gas companies’ imprudent investments, they must also work with electric companies to develop integrated plans to decarbonize buildings through increased electrification.”
The Acadia Center said: “The 20-80 order today from the DPU has the potential to be one of the most transformative decisions in Massachusetts climate history. … That being said, implementation and follow-through will be incredibly important, as always. Thoughtful planning by the Department and the commonwealth will be needed to ensure positive outcomes on key areas such as customer affordability, a just transition for gas workers, and infrastructure planning and management. This order therefore serves as an important midpoint in a multiyear process, as this decision will now lead to other key dominos like evaluation of gas utility stranded asset risk, decoupling mechanism revisions, systematic consideration of non-gas pipeline alternatives, and reassessment of gas utility policies on new and existing customer connections.”
FERC on Dec. 5 approved a $150,000 civil penalty on Black Hills Corp. (BHC) and its three electric public utility subsidiaries for their failure to timely file 103 jurisdictional agreements (IN23-10).
The stipulation and consent agreement between FERC’s Office of Enforcement (OE) and BHC and its subsidiaries — Black Hills Power; Cheyenne Light, Fuel and Power; and Black Hills Colorado Electric — stems from a prolonged FERC investigation triggered by the utilities’ self-reporting of their omissions.
Jurisdictional agreements detail rates, terms and conditions of services regulated by FERC and are essential for ensuring transparency, regulatory compliance and fair pricing.
On July 14, 2017, Black Hills Power reported to FERC that it had failed to submit six jurisdictional agreements as mandated by the Federal Power Act and FERC regulations (ER17-2095). This lapse led to Black Hills Power refunding $8,621 to customers.
This incident prompted BHC to conduct a more extensive investigation into its subsidies to determine if there were any other unfiled contracts.
By November 2021, BHC expanded its self-report to include an additional 97 unfiled contracts, leading to an estimated $1.2 million in refunds.
As of October 2021, BHC had filed all 103 previously unfiled agreements with FERC, some of which have been accepted, while others are still under review.
“As a result of these violations,” the stipulation said, “Black Hills provided jurisdictional services without an accepted just and reasonable rate on file at the commission.”
The agreements consisted mainly of short-term firm and nonfirm transmission service contracts, but also included transmission wires-to-wires interconnection agreements, delivery service to wholesale customers over distribution assets agreements, and joint ownership agreements and operation and maintenance services agreements on transmission assets.
FERC acknowledged BHC’s cooperation with the OE throughout the investigation.
In addition to the financial penalty payable to the Treasury, BHC was required to admit its non-compliance and implement measures to prevent future violations.
These measures include submitting semi-annual status reports that detail the status of each of the 103 previously unfiled agreements every six months for two years or until FERC has accepted or disposed of all the unfiled agreements. It must also undergo compliance monitoring for two years following the acceptance or final disposition of all filed agreements by the commission.
BHC must pay the civil penalty within 20 days of the agreement’s effective date and submit its first semiannual status report six months thereafter.
FERC Commissioner James Danly did not participate in the order.
ORLANDO, Fla. — MISO and its Independent Market Monitor agree that legal action is likely on the horizon concerning the RTO’s payments to SPP for a market-to-market flowgate.
Monitor David Patton said congestion costs remain high at nearly $600 million over the fall in MISO. At a Dec. 5 Markets Committee of the MISO Board of Directors, he singled out the 230-kV Charlie Creek-Watford line, a market-to-market flowgate with SPP, as a major source of congestion.
The line recently began delivering power to 220 MW in new load from a cryptocurrency mining operation in northwest North Dakota. Patton said Charlie Creek-Watford’s status as an M2M constraint should be revoked because MISO can offer SPP little relief.
Patton also suggested MISO’s millions of dollars in firm flow entitlement payments to SPP involving the constraint might be improperly calculated by SPP. He added SPP has had challenges in modeling use of the line.
“This is a mess,” Patton said. “This is really a bad scenario for MISO customers … I think there’s a good chance we head to litigation at FERC because we can’t keep these payments up.”
Patton said the line accounts for most of the current funding shortfalls in MISO’s financial transmission rights market.
“This one is going to be a legal issue in how we interpret the joint operating area, and we just need to sit down with SPP to work it out,” MISO CEO John Bear said.
MISO Executive Director of Market Operations J.T. Smith said new load was allowed to be activated in an already constrained SPP load pocket. Smith said while transmission upgrades are planned for the area, they’re not yet in place to help the situation. The load pocket is served by several other lines in addition to the line in question.
SPP maintains it and MISO have “robust coordination procedures in place to ensure the market-to-market congestion management processes are working as intended” and in accordance with the RTOs’ joint operating agreement.
“Over the last few months, the RTOs have extensively discussed the congestion issues associated with the Charlie Creek-Watford market-to-market flowgate that is being impacted by the operation of both markets,” SPP spokesperson Derek Wingfield said in an emailed statement to RTO Insider.
Wingfield said if SPP and MISO are unable to reach a solution through informal discussion, SPP is still optimistic that it and MISO will be able to leverage the formal dispute resolution procedures contained in their JOA. SPP is hopeful for a “mutually agreeable outcome prior to this becoming a legal matter at FERC,” Wingfield said.
ORLANDO, Fla. — An Iowa court has formally struck down the state’s right of first refusal (ROFR) law, deciding the procedure used to pass the bill is unconstitutional.
The decision stands to affect $2.6 billion in projects that are located at least partly in Iowa from MISO’s $10 billion long-range transmission plan (LRTP) portfolio.
The Polk County District Court’s decision Dec. 4 stops any current permitting processes on Iowa’s portion of five of MISO’s LRTP projects where incumbent developers had benefited from the law (CVCV060840). Incumbents ITC Midwest, MidAmerican Energy and Cedar Falls Utilities all exercised their option to build the LRTP projects, shutting out competition from other developers, including LS Power, which instigated the case.
The court said that since the March remand of the ROFR, “no party has presented any additional information that would lead this court to reach a different conclusion than the one reached by the Iowa Supreme Court when it issued the preliminary injunction in this case.”
That means the state Supreme Court’s rationale that the ROFR’s passage ran counter to Iowa’s rule that an act should address just one subject in the title stands unchanged. (See Iowa Regulators Ponder MISO Tx Projects After ROFR Ruling.)
“As the parties concede, this court’s analysis of plaintiffs’ constitutional claims must begin and end with the title and text of H.F. 2642,” the court said, referencing the name of the 2020 appropriations bill that contained the ROFR law.
Through spokesperson Brandon Morris, MISO said it’s reviewing the court’s decision. The grid operator did not elaborate on whether it’s communicating with the incumbent transmission owners or whether it might be preparing to issue requests for proposals on the affected LRTP projects.
“I would love to say I have a firm grasp of the order [already],” Deputy General Counsel Kristina Tridico told MISO members at a Dec. 6 Advisory Committee meeting during the RTO’s quarterly Board Week in Orlando.
Tridico said MISO will “be more responsive” once it pores over the decision and has a clearer idea of the implications. She reminded members MISO is not a party to the proceeding, and it will track closely defendants’ and intervenors’ next steps and how those will impact the timeline of the LRTP projects.
In a joint statement, MidAmerican and ITC Midwest said they’re disappointed with the decision and are discussing their options.
The two said it’s important to remember the district court’s decision is predicated on the ROFR’s inclusion as part of a larger appropriations bill and not on the merits of the ROFR itself. They also said the Iowa legislature for years has rolled laws together using appropriations bills without incident, and the ROFR “is no exception.”
“As public policy, the ROFR protects Iowa landowner interests, meets the needs of energy consumers, and ensures a coordinated approach to planning and safely operating the electric grid to support a growing Iowa economy,” MidAmerican and ITC Midwest said.
The five 345-kV LRTP projects located at least partly in Iowa likely to get a regulatory restart in the Iowa Utilities Board are:
The Webster-Franklin-Marshalltown-Morgan Valley line.
The Beverly-Sub 92 line.
The Orient-Denny-Fairport line.
The Madison-Ottumwa-Skunk River line.
The Skunk River-Ipava line.
Seemingly before it was aware of the ruling, MISO reported at its Board Week that four of the first cycle of LRTP projects have entered regulatory processes for approval, including the Webster-Franklin-Marshalltown-Morgan Valley line.
At a Dec. 6 System Planning Committee of the MISO Board of Directors, Executive Director of Transmission Planning Laura Rauch said she was excited to begin delivering status updates on LRTP projects as they progress in permitting.
The other three lines that have been introduced to regulators are located in and near Minnesota.
“Kudos to Minnesota,” Rauch said.
Rauch said MISO has seen good outreach and preparation work from all the developers of its LRTP projects. She said MISO has coordinated with developers on how best to manage the outages of existing transmission that must take place during LRTP construction. The lines under the first LRTP portfolio made extensive use of existing rights of way, so outages will be necessary, Rauch said.
“That is a technical challenge that we are stepping forward and engaging on,” she said.
MISO Moving Toward 2nd Portfolio of LRTP Projects
MISO is conducting analyses that will yield a second LRTP portfolio that again will focus on MISO Midwest.
Vice President of System Planning Aubrey Johnson said MISO is striking a balance between devoting due diligence on concerns the Independent Market Monitor has raised and moving forward with badly needed planning. (See IMM Criticizes MISO’s Modeling Software Used for Long-range Tx Planning.)
Johnson said MISO’s initial reliability and economic modeling shows MISO will need more “arteries” on the system to flow power and avoid overloads.
“Our system is like 5 p.m. at the 405, and we’re going to add more cars,” Johnson said, referencing an Amtrak route.
Johnson said if MISO doesn’t incorporate another major transmission buildout, MISO members will have to add significantly more generation than already planned to serve load. The transmission future MISO is using to plan the second LRTP portfolio predicts load will be 125% of current levels by 2042.
Johnson added that MISO will test a “lower bound” of fleet transition on the second LRTP portfolio to make sure the lines demonstrate value under a variety of settings.
“We’re at the phase where our engineers are at Disneyland, excuse me, SeaWorld. You get the idea, an amusement park,” he joked with a nod to MISO Board Week’s location at the Renaissance Orlando at SeaWorld.
Johnson said he borrows a phrase from a song in the movie “Smokey and the Bandit” to sum up planning in MISO: “We’ve got a long way to go and a short time to get there.”
Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, urged MISO to move quickly on planning the second LRTP portfolio,
“Every delay in building this grid costs customers,” she said.
Cappel-Vickery said new, long-range lines will provide benefits to consumers for decades by reducing congestion, avoiding generation outages and allowing access to low-cost renewable energy.
Members Support 2024’s Ancillary Services Methodology, Despite Costs
ERCOT stakeholders endorsed the grid operator’s proposed ancillary service methodology for 2024, but only after extracting a commitment from staff to bring the proposal back for further review by April 30.
The approval came after ERCOT’s Independent Market Monitor, Potomac Economics, said the methodology has generated artificial shortages that produced “massive” inefficient market costs totaling about $12.5 billion this year through Nov. 27.
The Monitor also told the Technical Advisory Committee that the methodology diminishes reliability by withholding units needed to manage transmission congestion, is not based on sound reliability criteria, and has led to excessive reserves procurements that far exceed those by other grid operators.
“I don’t want to exaggerate how bad this is, but this is the worst performance we’ve ever seen since the beginning of organized electricity markets almost 25 years ago,” Potomac’s David Patton said. “I’ve been racking my brain to try to figure out whether I’ve ever seen anything like this, and I really haven’t.”
Patton, whose firm also monitors the MISO, NYISO and ISO-NE markets, said there’s no way to pretend the costs are “efficient,” as ERCOT was not experiencing shortages during periods with $5,000 capped prices.
“We weren’t close to being in shortage and yet the market, with this large increase in 10-minute reserves that gets held out of the energy market, perceived a shortage that didn’t really exist,” he said.
“Inefficiency is not how we operate in this market and provide reliability. Our objective is to provide reliability at lowest cost,” said MD Energy Consulting’s Mark Dreyfus, who represents the city of Eastland and 154 other commercial consumers. “Since the very beginning of this market, commercial consumers have been very clear. They support competitive market outcomes, wherever possible. By supporting competitive market outcomes, we will get the lowest cost reliability possible.”
At issue is ERCOT contingency reserve service (ECRS), the grid operator’s first new ancillary service in 20 years that was deployed early this summer. Dreyfus called for a commitment to reconsider how the service is used and to better understand the Monitor’s report.
The service is economically dispatched within 10 minutes of deployment, using capacity that can be sustained at a specified level for two consecutive hours and supplementing the ISO’s conservative operations posture of setting aside ample reserves.
The IMM has said ECRS essentially meets the same reliability requirements that previously were met solely by responsive reserve service. In its initial assessment of ancillary services, the monitor said ECRS “likely” raised the real-time market’s energy value by at least $8 billion. (See ERCOT Board, IMM Debate Ancillary Service Costs.)
ERCOT disputed the Monitor’s analysis, noting the $12.5 billion figure is not the direct cost of procuring ECRS, but a study that estimates how much lower real-time energy costs would have been if resources were not reserving capacity to provide ECRS. It said in a statement that actual costs were likely much less than that and other factors, such as the historically hot summer, contributed to increased prices.
Potomac urged stakeholders to reject the AS methodology and requested that ERCOT use a reliability analysis that models the uncertainties that drive reliability problems and then quantify the needed reserves. It said staff could mitigate its concerns with several changes, including reducing ECRS’ deployment back to one hour.
ERCOT staff has made minor changes to the 2024 AS methodology. It said the ECRS proposal reflects the minimum volume of 10-minute reserves needed to cover the risks should a large unit trip offline or frequency losses occur.
However, the grid operator also allowed that a “separate, broader discussion is warranted” to identify improvements to the ECRS market.
Given that caveat and as required by the protocols, TAC endorsed the 2024 methodology with a 21-3 vote. Six members abstained. An earlier vote to approve the methodology as recommended by ERCOT failed 12-7 with 11 abstentions.
Potomac’s four-year contract as ERCOT’s Independent Market Monitor expires Dec. 31. It remains the only listed applicant to the Public Utility Commission’s request for a new four-year contract, but no announcement has been made (55222).
Staff Withdraws DRRS Change
The committee approved ERCOT’s request to withdraw a nodal protocol revision request (NPRR1203) implementing a new ancillary service that faces a tight statutory timeline.
Staff had proposed adding dispatchable reliability reserve service (DRRS) as a subtype of non-spinning reserve, saying it was the only way to meet a Dec. 1, 2024, deadline set by state law. TAC tabled the NPRR in October after lawmakers objected to ERCOT’s plans and said the standalone service should be developed even if it fails to meet the deadline. (See ERCOT Technical Advisory Committee Briefs: Oct. 24, 2023.)
The PUC last month linked its approval of the budget to meeting several performance metrics. They included implementing the DRRS product “aligning it with the real-time co-optimization plus battery project (RTC+B). (See Texas PUC OKs Smaller Budget, Admin Fee Increases for ERCOT.)
Kenan Ögelman, ERCOT’s vice president of commercial operations, said staff plans to develop DRRS as a standalone service “as expeditiously as possible” and will file a draft NPRR by April that aligns with real-time co-optimization’s (RTC) implementation. He also agreed with stakeholders’ requests for a workshop to review the NPRR’s details.
“The goal would be to make sure everybody is fully informed on the functionality and features that we were putting into the NPRR and that we absolutely got stakeholder feedback on making that better or adjusting it, such that we had a product that the stakeholder community was comfortable with and that also met the statutory goals,” he said.
“The feedback I’ve gotten so far from the commission is RTC+B is the priority,” Ögelman said.
TAC endorsed ERCOT’s plan 28-0, with Luminant and Lower Colorado River Authority (LCRA) both abstaining over the statutory deadline concerns. Luminant’s Ned Bonskowski said his company did not want to stand in the way of those wanting to move forward.
“I am a little worried about certain policy decisions being driven by secondary timeline goals,” LCRA’s Emily Jolly said.
Staff also withdrew two other binding document requests (OBDRR049, OBDRR050) related to NPRR1203.
West Texas Projects Endorsed
TAC endorsed two Tier 1 transmission projects in the West Texas weather zone projected to cost a combined $1.17 billion, placing both on the combination ballot.
The Regional Planning Group’s West Texas Synchronous Condenser project accounts for the bulk of the costs at $892.2 million. It involves installing synchronous condensers at six 345-kV substations to address reliability risks in West Texas driven by the region’s increased penetration of inverter-based resources (IBRs). ERCOT expects more than 42 GW of IBR capacity by 2026 in the zone.
Staff said the prevalence of IBRs coupled with the lack of conventional synchronous resources has further weakened the system and increased the likelihood of potential instability issues, such as the recent Odessa disturbances. (See NERC Repeats IBR Warnings After Second Odessa Event.)
The project, involving Wind Energy Transmission Texas, LCRA Transmission Services Corp. and Oncor, has an in-service date of May-October 2027.
ERCOT’s proposed synchronous condensers at six 345-kV substations in West Texas. | ERCOT
The second project, submitted by Texas-New Mexico Power, is projected to cost $273.1 million. The upgrade involves the construction of two 345-kV substations, two 345/138-kV substations and 20 miles of 138-kV line to address reliability needs. The project is expected to be completed by June 2027.
With capital costs exceeding $100 million, the Tier 1 projects must be approved by ERCOT’s board, which next meets Dec. 18-19.
TAC Remembers Brad Jones
Members shared the memories of the late Brad Jones, who chaired TAC at one point and served as ERCOT’s interim CEO and COO. Jones, who also served as NYISO’s CEO, passed away Nov. 8. (See Brad Jones, Former ERCOT, NYISO CEO, Dies at 60.)
Reliant Energy Retail Services’ Bill Barnes, who attended a memorial service Saturday in Austin along with many other stakeholders, said ERCOT’s membership was one of his most important families.
“We heard a lot about Brad’s optimism,” he said. “The thing that I will take with me forever is the spirit of compromise. That’s why we’re here, to hear from different perspectives, hear from other segments, each other’s opinions, and think about how we can work together as a team to solve the very challenging problems that face us.”
“You could argue with Brad up and down, back and forth, and respect was always maintained through that entire process,” said Engie’s Bob Helton, whose relationship with Jones goes back to the market design work of the late 1990s. “That’s one of the things that was wonderful about Brad. He would listen to you, argue with you, and we’d come to a good decision.”
“Brad is one of the core reasons we have what we have today,” Golden Spread Electric Cooperative’s Mike Wise said. “He’s one of the godfathers of our market.”
“Obviously, Brad was a very special and influential person at ERCOT. He had two stints with us, made amazing contributions, and brought a lot of joy and laughter to the folks at ERCOT,” Ögelman said. “In some of our darkest moments, he was our shining light as we were trying to deal with the aftermath of Winter Storm Uri. I certainly miss him every day and appreciate all that he’s done for everybody in this room and in the industry and ERCOT as well.”
Retail Choice Coming to Lubbock
TAC’s unanimous endorsement of the combo ballot resulted in approval of a change to the retail market guide (RMGRR176) that lays out the processes Lubbock Power & Light must use when it begins offering customers their choice of electric providers March 4.
Oncor’s Debbie McKeever, chair of the Retail Market Subcommittee, told the committee that more than two dozen electric retailers are preparing to offer plans in LP&L’s service territory.
The municipal utility is migrating the final 30% of its load from SPP to ERCOT by Dec. 11. LP&L first announced its intention to join ERCOT’s competitive market in 2015. Texas regulators approved the transition in 2018. (See Six Years in the Making: LP&L Migrates Load to ERCOT.)
The combo ballot included three other NPRRs that, if approved by the board and the PUC, would:
NPRR1181: Require qualified scheduling entities representing coal or lignite resources to submit to ERCOT a seasonal declaration of coal and lignite inventory levels and to notify ERCOT when the inventories drop below target and critical-level protocols.
NPRR1201: Reduce exposure from resettlements and default uplift invoices for historical operating days by limiting resettlement timelines due to errors that are discovered and a market notice is provided to the market within one year after the operating day. This limit does not apply to alternative dispute resolution resettlements, a procedure for return of settlement funds or a board-directed resettlement addressing unusual circumstances.
NPRR1204: Implement the state-of-charge (SOC) concepts necessary for awareness, accounting and monitoring energy storage resources’ SOC within the RTC+B project.
