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April 14, 2026

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FERC Accepts SPP’s Western Interregional Transmission Coordination

FERC has accepted SPP’s tariff revision that establishes procedures governing interregional transmission coordination in the Western Interconnection between the grid operator and its neighboring planning regions following its RTO Expansion (ER26-1311).

SPP’s proposal also included a method for allocating interregional projects between SPP’s Western region and the planning regions that the commission found to be just and reasonable. FERC said in the April 10 order that the interregional coordination procedures and cost-allocation methodology comply with Order 1000’s requirements.

In a separate concurring statement, Commissioner David Rosner commended the RTO for reaching consensus with its new Western neighbors on the tariff provisions but also highlighted “broader deficiencies” with the commission’s current interregional transmission coordination framework.

He said that since 2011, Order 1000 has resulted in “exactly zero” interregional projects, noting that interregional transmission “time and time again over those 15 years” has made “meaningful” contributions to grid reliability during extremely stressful periods.

“It is imperative that the commission and industry advance meaningful action on interregional transmission planning as soon as possible,” Rosner wrote, saying he is ready to “take swift action” on any future industry filings. “Absent such filings, I intend to work with my fellow commissioners to move this critical ball forward.”

Pointing to NERC’s Interregional Transfer Capability Study, he said it identified a 35-GW gap that, if left unaddressed, “will contribute to a grid that is less reliable.”

“This is a concerning finding that we must address,” Rosner said.

The commission noted the tariff revisions deviated from the common interregional cost-allocation language by assigning project costs to the SPP region according to its existing mechanisms, as applied only to projects in the Western Interconnection. However, it said the revisions comply with Order 1000 because they ensure any project costs in the Western Interconnection allocated to the SPP region on a pro rata basis are allocated only according to SPP’s commission-accepted regional cost allocation method.

FERC found several other variations from the common tariff language to be just and reasonable because it said they clarify the appropriate handling of sensitive information and ensure that costs for projects no longer viable to SPP’s regional transmission needs are not allocated to its region.

The commission also accepted the RTO’s proposal to define CAISO as a “planning region.” It agreed with SPP that while CAISO is not contiguous with and does not neighbor the RTO’s new Western region, including it as a planning region will promote interregional transmission coordination.

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Company Briefs

PacifiCorp Dumps Renewable Energy Plans in 4 States

PacifiCorp updated its integrated resource plan to eliminate renewable energy plans in four states.

The utility has no plans to add more wind or solar facilities in Wyoming, Utah, Idaho and California from 2027 through 2045 following the repeal of tax credits in the Inflation Reduction Act. The company said the tax credits had reduced the cost of wind and solar projects by about 30%.

More: WyoFile

AES Withdraws from California Battery Project

AES withdrew its application to develop the Seguro battery system in Escondido, Calif.

The company intended to use a former horse ranch to house a 320-MW battery storage project but said it will prioritize other development efforts after facing intense local opposition.

More: Canary Media

VW to Stop Producing ID.4 at Tennessee Plant

Volkswagen announced it will cease production of its ID.4 EV at its Chattanooga plant and will shift focus to the Atlas and Atlas Cross Sport.

In January, the electric SUV was the slowest-selling vehicle in the U.S. The next generation of the Atlas will begin production this summer.

More: Chattanooga Times Free Press

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Federal Briefs

Brown Analysis: Iran War has Cost Americans $17B at the Pump

The Iran war has cost the U.S. economy roughly $17 billion solely by increasing gasoline and diesel prices, according to an analysis from Brown University researchers.

The analysis said much of the higher costs come from surging diesel prices, which have risen 48% since the war began. In all, Americans have paid an additional $8.8 billion for gasoline and an extra $8 billion for diesel.

More: Heatmap

EPA to Weaken Coal Ash Rules

EPA announced it will weaken cleanup requirements for hundreds of coal ash deposit sites.

The agency said it would repeal a 2024 Biden administration rule that required companies to examine the condition of coal ash sites at inactive power plants, and ease standards for monitoring and protecting groundwater near some sites.

The new plan would return much of the decision-making to states, while also letting local permitting agencies bypass national standards on a case-by-case basis.

More: The Guardian; The New York Times

EPA Tells Scientific Research Staffers to Relocate

EPA is making some of its staffers relocate and is reassigning a larger share of employees as part of its efforts to reorganize its scientific research.

The agency is reassigning 124 staffers, 35 of whom are being asked to relocate.

The move comes as the Trump administration attempts to eliminate its Office of Research and Development and conduct scientific research in a new office housed within the office of the administrator.

More: The Hill

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State Briefs

CONNECTICUT

Eversource Backs out of 3 State Solar Projects

Eversource informed the Department of Energy and Environmental Protection that it will opt out of three power purchase agreements worth 54 MW of solar power.

Eversource Deputy General Counsel Duncan R. MacKay sent a letter to DEEP and legislative leaders on March 27, saying the agency’s latest round of clean energy purchases was overpriced and likely will result in an increase to the public benefits charge. For those reasons — as well as a lack of “comprehensive” energy strategy — MacKay said the company would decline to enter the contracts.

Officials said it is still unclear what impact the decision will have on the projects moving forward.

More: CT Mirror

MAINE

Legislature Passes Data Center Moratorium

A bill that would place a statewide moratorium on large data centers passed both Democratic houses and awaits appropriations.

The bill bans data centers larger than 20 MW until November 2027. It also creates a Data Center Coordination Council that will provide input, facilitate planning considerations and evaluate policies to address the facilities. Democrats cited the potential costs to ratepayers and widespread local opposition, including in Bangor.

More: Maine Morning Star; Bangor Daily News

Gov. Mills Approves Plug-in Solar

Gov. Janet Mills signed a bill that will allow residents to install small, portable solar energy systems in their homes.

The measure allows customers to use certain small solar generation and battery systems that plug directly into wall sockets, similar to gas generators. One estimate found an 800-W system could save the average customer more than $250 annually.

More: Portland Press Herald

MICHIGAN

Sault Tribe to Adopt Data Center Moratorium

Members of the Sault Ste. Marie Tribe of Chippewa Indians voted unanimously to approve a moratorium on the development of AI data centers on tribal lands.

Tribe members cited concerns about the strain on local resources, long-term land use impacts and the uncertainty of whether a facility would yield long-term economic benefits.

The moratorium will remain indefinitely.

More: Michigan Advance

MINNESOTA

PUC Approves Xcel VPP

The Public Utilities Commission approved Xcel Energy to build and operate its own virtual power plant.

Under the Capacity*Connect program, Xcel will spend $430 million to deploy up to 200 MW of batteries, in 1- to 3-MW increments, over the next two years.

Xcel said it will place the batteries around local communities strategically to test how each can mitigate grid constraints.

More: Canary Media

NEW YORK

ORES Awards Permit to 99-MW Wind Farm

The Office of Renewable Energy Siting and Electric Transmission approved a siting permit to Liberty Renewables for a wind farm in Cayuga County.

The 99-MW Agricola Wind project calls for the construction of up to 24 turbines and will operate for 25 years.

The farm is expected to be operational by 2028.

More: Renewables Now

VIRGINIA

SCC Approves Dominion Energy Tx Project

The State Corporation Commission approved Dominion Energy’s request to build new high-voltage transmission lines through Loudoun County.

The SCC approved the shortest route at 8.3 miles for the 230- and 500-kV lines. It also said burying the lines underground was not practical due to an estimated $1.5 billion cost, much to the dismay of the project’s opponents.

More: Loudoun Now

ONTARIO

IESO Awards Contracts for 1.3 GW of Solar, Wind

IESO approved 14 renewable projects with a combined capacity of more than 1.3 GW under the first window of the Long-Term 2 procurement process.

The 20-year contracts will go to 12 solar and two wind projects. The three largest contracts will procure 200 MW each from the Dunns Valley Solar plant, the Gichigami Wind Project and the Northern Breeze Wind Project.

All projects are expected to begin commercial operations by May 1, 2030.

More: Renewables Now

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PJM MIC Briefs: April 8, 2026

Stakeholders Endorse Issue Charge on Dual-fuel Switching Downtime

PJM’s Market Implementation Committee endorsed an issue charge to explore how dual-fuel gas generators should reflect the downtime needed to switch fuels in their requirement to offer into the energy market.

Constellation’s Erik Heinle said the proposal would enhance reliability by ensuring resource limits are recognized by PJM. The issue charge was jointly sponsored by Constellation and PJM.

PJM’s Brian Chmielewski said, from a markets perspective, staff is interested in talking through the apparent inconsistencies between the parameters resources may submit and their limits. On the operations side, there’s interest in having more flexibility to preserve stored oil fuel.

Language was added to the problem statement ahead of the meeting to reflect stakeholder concerns about oil fuel inventories being depleted during winter events when gas prices are high. Since PJM’s scheduling software prioritizes cheaper offers, a dual-fuel unit might be asked to switch from gas to oil even when dispatchers would prefer to preserve stored fuel for later in the event.

Asked why the issue should be considered separate from ongoing work to consider how resources are committed, Heinle said Constellation is seeking to have the change in place ahead of next winter. He said because the issue charge is focused on a narrow issue and is likely to require only manual revisions, it could be advanced more quickly as a standalone item.

The issue charge was revised during the meeting to address stakeholder concerns that it was overly prescriptive around the possible solution and to reflect PJM’s desire to have more flexibility around when oil is burned.

PJM’s Kevin Hatch said resources going offline while switching fuels would be able to use the transition time as an exception from the must-offer requirement. The requirement is applicable to resources with a capacity commitment.

PJM Seeks Changes to LOC Eligibility for Flexible Resources

PJM presented proposed revisions to make flexible resources ineligible for lost opportunity credits (LOC) if they submit inflexible offers in the real-time (RT) energy market.

The changes would update the tariff’s definition of a flexible resource, inserting the phrase “all available schedules separately specify” ahead of “a combined start-up time and notification time of less than or equal to two hours; and a minimum run time of less than or equal to two hours.” A resource would be disqualified from receiving a LOC payment if it commits on a flexible schedule in the day-ahead (DA) energy market by submits inflexible offers in the RT market.

The issue stems from how PJM’s intermediate term SCED (IT SCED) software would evaluate an inflexible offer from a flexible resource. If the unit was committed in the DA market on a flexible cost-based offer because it would fail the market power mitigation test under a modeled transmission constraint, the start-up and notification parameters of an inflexible offer could be longer than the lookahead IT SCED uses. If the constraint does not manifest, IT SCED would be unable to schedule the unit.

PJM Presents Quick-fix Manual Changes for Fuel Cost Policies

PJM presented a quick-fix proposal to rework how it calculates penalties when a resource submits a cost-based offer that violates its fuel cost policy. The quick fix process allows a problem statement, issue charge and proposed solution to be considered concurrently.

Because LMP is a component of the penalty formula, the penalty could be negative if prices are negative when the violation is identified — effectively becoming a credit.

The proposed changes to Operating Agreement Schedule 2 would set the penalty at the greater of the existing rate or zero.

Monitor Investigating Fractional Clearing Contributing to High Regulation Prices

The Independent Market Monitor is looking into situations when a marginal resource being assigned a regulation commitment below 1 MW leads to high regulation clearing prices.

Chief Economist Howard Haas said costs can “explode” when partial or fractional commitments (between 0.1 and 1 MW) are the marginal resource in the regulation market  — depending on offer parameters and realized differences between market clearing LMP forecasts and realized LMP lost opportunity.

The Monitor is working with PJM to optimize how resources’ parameters interact with the regulation market design. Differences between the economic dispatch range and the regulation range and between bid in ramp and actual ramp may make regulation prices highly sensitive to differences between forecast and actual LMPs.

One of the Monitor’s initial recommendations is for a resource’s Reg Max parameter to be tied to its energy market Eco Max parameter. LOC would be determined on the basis of Reg Max falling below Eco Max.

PJM’s Michael Olaleye said the regulation redesign implemented in October 2025 has made price formation and procurement more efficient and positioned the market for increased renewable penetration. Uplift has fallen from 14% to 2% and the market now more accurately captures the cost for a resource to reduce its output for energy or regulation purposes.

He stressed there are no errors in how PJM clears or prices regulation resources and staff is monitoring the optimization engine results for improvements.

Manual 15 Biennial Review Changes Endorsed

Stakeholders endorsed revisions to Manual 15: Cost Development Guidelines intended to clarify how to update the format of the variable operating and maintenance (VOM) adder and the functioning of the opportunity cost calculator.

Under the changes, resource owners may change the VOM format only once per calendar year at the time of submission. Subsequent changes would not be permitted until the start of the following calendar year.

The changes state that, when simulating the hours of operation with the greatest energy market revenue excluding short run marginal costs, the opportunity cost calculator will model a unit as being dispatched between its economic minimum and maximum.

An additional paragraph states the adders the calculator produces are normally a dollar per megawatt-hour value, except when environmental or operational limits limit how often a unit can be started or operated during a compliance period. In cases when the resource is limited by starts per period, the adder is a dollar per start value and can only be applied to start-up costs. If the limit is run hours per period, the adder is dollars per hour and can only be included in no-load costs.

1st Read on Manual 11 Changes to Advance Commitment Offer Selection

PJM presented revisions to Manual 11: Energy & Ancillary Services Market Operations to distinguish between offer selection for advance commitments and resources scheduled in the day-ahead market.

Resources with start-up or notification times exceeding a day — those with advance commitments — would be scheduled on their cheapest cost-based offer available at the time they are committed, with updates not permitted. Resources with shorter start-up or notification times would be scheduled on their cheapest cost-based offer at the close of the day-ahead market.

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PJM OC Briefs: April 9, 2026

Manual 1 Revisions Endorsed

The PJM Operating Committee on April 9 endorsed a package of changes to Manual 01: Control Center and Data Exchange Requirements, including the elimination of a requirement that actual meter test results should be provided to the RTO. (See “Stakeholders Delay Vote on Manual 1 Revisions,” PJM OC Briefs: Jan. 8, 2026.)

Stakeholders held off on approving the language in January so that PJM staff could address concerns that without a reporting requirement, the RTO would be left to assume meter data are correct. Language was added stating that the provisions in generation interconnection agreements requiring periodic meter tests must be respected, recognizing PJM can request meter tests, and that discrepancies discovered should be resolved on by the settling parties. It also notes PJM holds five years of settlement data.

March Operating Metrics

PJM saw an average hourly load forecast error rate of 1.75% in March and an average peak hour forecast error of 1.68%. There were five days when the daily peak forecast error rate exceeded the 3% benchmark:

    • high temperatures on March 1 pushed loads 3.25% down;
    • low temperatures in several zones on March 13 led to a 3.95% underforecast;
    • cold weather on March 15 led to a 3.71% underforecast;
    • much higher temperatures than forecast on March 19 contributed to a 5.98% overforecast; and
    • temperature forecast error in several zones on March 22 led to loads coming in 4.23% higher than expected.

There were two spin events, four shared reserve events, one high-system-voltage action, three geomagnetic disturbance warnings, 19 shortage cases and 11 post-contingency local load relief warnings in March.

Three of the shortage cases occurred on March 1 starting at 7:35 p.m. because of a loss of generation. Nine were on March 12 between 7 and 7:40 p.m. owing to resource ramping limitations and solar generation falling off as load increased. Seven cases from 5:05 to 5:35 p.m. on the following day were attributed to ramp limitations and higher-than-forecast load.

The first spin event was on March 1 at 7:29 p.m. and lasted 11 minutes and 9 seconds. There were 2,416 MW of generation and 643 MW of demand response assigned, of which 1,335 MW and 499 MW responded, respectively, for an overall response rate of 60%. There were 1,225 MW of reserve penalties assessed.

The second event was on March 5 at 2:24 a.m. and lasted three minutes and 59 seconds. There were 1,996 MW of generation and 656 MW of DR assigned, of which 268 MW and 439 MW responded, respectively, for a 27% response rate.

Monitor Update on Synch Reserve Performance

The Independent Market Monitor presented the results of outreach to the owners of 14 resources that underperformed during a March 1 synchronized reserve event and found that communication issues are becoming less of an issue, while personnel and parameter issues continue to pull the response rate down.

The Monitor has been reaching out to owners of underperforming resources for months as part of an effort with PJM to address a lingering poor response rate for synchronized reserves.

There were 2,538 MW dispatched during the event, of which 72% responded. The Monitor has long recommended that PJM count overperformance when calculating the fleet-wide response rate; when adding that in, the response rate increases to 91%.

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PJM PC/TEAC Briefs: April 7, 2026

Planning Committee

1st Read on Manual Revisions to Eliminate 1st Use

PJM presented revisions to Manual 14H: New Service Requests Cycle Process to replace its standard for determining whether a resource point of interconnection on a distribution facility falls under federal or state jurisdiction. (See “Stakeholders Endorse Reworked Interconnection Jurisdiction,” PJM MRC/MC Briefs: Aug. 20, 2025.)

The language, presented to the Planning Committee on April 7, would conform with FERC’s approval of PJM’s proposal to shift to a “bright-line” test that would classify most POI over 69 kV as being under federal jurisdiction and lower-voltage facilities as being state-regulated. It includes a carve-out for instances in which a transmission owner or relevant electric retail regulatory authority has designated the POI as being either state or federal jurisdictional. The reigning “first-use” standard considers the first wholesale resource POI on a distribution facility to be state jurisdictional and all subsequent resources using that POI to be federal.

PJM Presents CIR Transfer Manual Revisions

PJM presented additional revisions to Manual 14H to conform with FERC’s approval of a streamlined process for transferring capacity interconnection rights from deactivating resources to replacement projects at the same POI (ER26-403). (See FERC Approves PJM CIR Transfer Proposal.)

Eligible replacement resources would go through an interconnection process with a smaller slate of studies to be completed, allowing for a shorter processing time of 180 days. Resources would be required to be able to enter service within three years of applying for a CIR transfer, and their capacity output would be limited to the CIRs held by the deactivating resource. Only projects with minor network upgrades would be allowed to proceed.

The commission initially rejected the proposal on the grounds that its aim of creating a fast-tracked pathway for replacement resources was undermined by the inclusion of an option for developers to extend the in-service requirement for their project and an exception from the three-year requirement for resource types broadly recognized to have lengthy development timelines, such as nuclear.

PJM Proposes Retiring Manuals 14A and 14E

PJM presented a pair of first reads to retire Manual 14A: New Services Request Process and Manual 14E: Upgrade and Transmission Interconnection Requests, as their contents have been shifted to Manual 14H. The documents would be retired on June 30.

Transmission Expansion Advisory Committee

Supplemental Projects for Large Loads

American Electric Power presented a $156.6 million transmission project to serve an 800-MW customer near Piketon, Ohio, by constructing a 345-kV substation to be named Monza.

The facility would connect to the Don Marquis substation with 1.8 miles of 345-kV line and to the customer site with two 0.2-mile 345-kV lines. Don Marquis would be expanded with four circuit breakers to support the additional lines. The project is in the scoping phase with an expected in-service date of Dec. 31, 2027.

The utility presented six needs statements for large customers seeking interconnection across Ohio:

    • a customer in Hilliard seeking to increase its peak load by 185 MW;
    • a customer in Pickaway County for 179 MW, to increase to 358 MW;
    • a New Albany customer seeking to increase its anticipated load at the planned Curleys substation by 638 MW;
    • a customer seeking to bring 415 MW to Johnstown by June 1, 2030;
    • a customer requesting service for 787 MW in Sunbury by June 1, 2030; and
    • a customer interconnecting 429 MW in New Albany by June 1, 2030.

PPL presented a need statement to serve a customer seeking 230-kV service for about 2 GW of load near Mount Carmel, Pa. The load is expected to come online initially in 2028 at 290 MW and ramp to 500 MW in 2029, 1,250 MW in 2031 and reach its full consumption in 2033. The utility also presented needs for 300-MW customers in Archbald and Allenwood, Pa.

Exelon presented a $174.5 million project to serve a biotech company and data center in Philadelphia by constructing a 230-kV substation, named Bellwether, cutting into the Island Road-Navy Yard line. The project would begin with the installation of a temporary radial 230-kV line from the Elmwood substation to the customer to serve the initial 140-MW load at the site. The second phase would construct the 20-breaker Bellwether substation and two feeds to the customer to supply its full 500-MW consumption. The project is in the engineering phase, with the first phase to be completed by Dec. 31, 2029, and the second by June 1, 2031.

The company proposed installing a second 500/230-kV transformer and circuit breakers at the Limerick substation to improve operational flexibility for maintenance outages. The $93 million project is in the engineering phase with an expected in-service date of June 1, 2032.

Exelon also presented a $181.3 million project to construct a 10-mile 230-kV line between the Navy Yard and Richmond substations and replace breakers and disconnect and bus equipment at Richmond. The project would provide a third 230-kV source to the Navy Yard substation. The project is in the engineering phase with a projected in-service date of Sept. 1, 2032.

Another Exelon project would rebuild sections of the 230-kV lines between the Linwood, Claymont and Edgemoor substations for $145.4 million. The scope includes the full 7.1 miles of the Claymont-Edgemoor line, 8.1 miles of Edgemoor-Linwood and 1 mile of Claymont-Linwood. The project is in the engineering phase with an expected in-service date of June 1, 2031.

Dominion Energy presented a $64.3 million project to serve a 234-MW data center in Loudoun County, Va. The project would construct a new substation, named Firehouse, cutting into the 230-kV BECO-Paragon Park line. The project is in the engineering phase with a projected in-service date of Dec. 31, 2030.

Serving another data center in Loudoun County, which would scale to 282.6 MW by summer 2030, would require the construction of a 230-kV substation, named Auto World, cutting into the Paragon Park-Golden line. The $31.8 million project is in the conceptual phase with a possible in-service date of Dec. 17, 2027.

Dominion also identified a need to replace 230-kV capacitor banks at eight substations to avoid possible voltage violations and cascading outage scenarios as the amount of load in the region is expected to grow. The 20- to 25-year lifespan of the capacitors is being impacted by increased deployment, overvoltage transients exceeding 110% of the units’ ratings and larger inrush current. The replacements would take place in 2027-2028 at the Pleasant View, Greenwich, Liberty, Clifton, Lanexa, Jefferson Street, Valley and Newport News substations.

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FERC Approves SCE’s Agreement With Battery Developer

FERC has approved an agreement between Southern California Edison and Longroad Development Co. regarding interconnection of a 500-MW battery energy storage project, with one commissioner acknowledging Longroad remains “between a rock and a hard place.”

In an April 10 order (ER26-518), FERC accepted a design, engineering, procurement and construction letter agreement between SCE and Longroad Development related to Longroad’s Rosa storage project, to be built in Moorpark, Calif.

The letter addresses shared network upgrade obligations for Longroad’s project under the CAISO tariff and SCE’s transmission owner tariff.

SCE filed the agreement with FERC for review in November 2025 because it differs from the pro forma agreement for interconnections SCE developed in response to FERC Order 2003. The agreement remains unexecuted after SCE and Longroad hit an impasse in negotiations in 2025.

Longroad submitted an interconnection request to CAISO during the Cluster 14 application window. The project was assigned a share of reliability network upgrades based on Cluster 14 interconnection studies. The Rosa project is “parked” in CAISO’s interconnection queue.

According to SCE’s filing, Longroad objects to the project payment schedule and requirement to post collateral to secure funding for its portion of the shared upgrades. Longroad said it planned to wait for the results of CAISO’s second deliverability allocation cycle to determine the commercial viability of the project before moving forward. Until that step is completed, Longroad doesn’t want to post $18.75 million in collateral.

Longroad posted $8.74 million for the project’s first financial security payment in 2023. The company argued that Appendix DD of the CAISO tariff — which applies specifically to customers parked in the Cluster 14 queue — establishes “a defined sequence” for interconnection financial security obligations, with the second payment preceding the third.

The CAISO tariff “links higher financial commitments to increasing informational certainty,” Longroad said.

In its own filing, CAISO said Longroad had misinterpreted the tariff.

“The bulk of Longroad’s protest argues that its election to park its project to reseek deliverability takes precedence over its obligation to finance its portion of shared network upgrades that ‘first-ready’ interconnection customers need to remain on schedule,” the ISO wrote. “These arguments contradict the plain language and intent of the CAISO tariff.”

The ISO said 64 interconnection customers in Cluster 14 completed all obligations, including financing, and 27 others withdrew.

In accepting the agreement between SCE and Longroad, FERC found it just and reasonable and not unduly discriminatory or preferential. The commission disagreed with Longroad that there is a defined sequence to the second and third financial security postings in the CAISO tariff.

Commissioner David LaCerte concurred with the order but issued a separate statement. He said CAISO’s tariff recognizes the importance of timely and efficient interconnection, particularly when it comes to shared network upgrades.

But two provisions of CAISO’s tariff “have placed Longroad between a rock and a hard place,” LaCerte said.

“Longroad is forced to choose between: (a) making an $18.75 million third milestone security payment for shared network upgrades before knowing whether it will have the transmission deliverability to utilize those upgrades; and (b) not making an $18.75 million third security payment for shared network upgrades, withdrawing from the queue and forfeiting its first milestone security payment,” LaCerte wrote.

“Should Longroad choose to play the long game and try again to interconnect to the CAISO grid in a later queue cluster … its odds of obtaining deliverability may be improved,” he added.

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Maryland Legislature Passes Utility RELIEF Act Aimed at Affordability

Maryland legislators passed the Utility RELIEF Act, which responds to rising power prices by trimming surcharges for a state efficiency program, eliminating the RTO adder for its utilities and requiring the Public Service Commission to review supplemental transmission projects.

The House of Delegates version (HB 1532) and the Senate version (SB 841) went into the weekend with different amendments, but leadership from the two houses and Gov. Wes Moore (D) announced a deal April 13 to get the legislation through on the last day of the session.

“Over the past year, energy prices have soared and people are getting crushed,” Moore said at a press conference. “Since just last year when this new federal administration came on board, energy prices are up 13% in the state of Maryland.”

An “all-of-the-above” approach to energy works because the state should be supporting what is fastest and cheapest to help address a looming capacity shortfall in PJM, he said. The fastest resources that can come online are renewables like solar, which have run into problems with the federal government.

Moore was among the bipartisan group of governors who attended a White House event in January where they called for a backstop capacity auction and an extension of a cap on prices in the main auction, which are being implemented. (See White House and PJM Governors Call for Backstop Capacity Auction.)

The cap on capacity prices is expected to save the average PJM customer $400. Moore said the state law would save hundreds of dollars more.

The bill addresses the backstop auction being developed by PJM to ensure the costs of it are allocated to data centers, Senate President Bill Ferguson (D) said at the press conference. (See PJM to Present Initial Reliability Backstop Proposal.) It also sets up a registry at the PSC to deal with “phantom load” from speculative data center projects, he added.

“Under this law, data centers will pay for the grid upgrades they need and not the people of the state of Maryland,” Moore said. “Under this law, utility companies can’t come back after the fact and stick you with extra charges. Utility companies can no longer pass their unlimited salaries onto ratepayers.”

The bill requires utility participation in PJM and would make it so they are not eligible for the adder to transmission rates, with Moore saying the bill “ends that loophole.”

The legislation also requires the PSC to review most new transmission lines above 69 kV, with some exceptions for projects that are just rebuilding old lines on existing rights-of-way with minimal changes. Any proceedings for a certificate of public convenience and necessity will require that utilities analyze whether advanced transmission technologies could be used, the bill said.

While the bill was popular with Democrats, in the end Republicans generally voted against the bill, which passed the Senate by 35 to 11 and the House by a vote of 105 to 27. Democrats enjoy substantial majorities in both chambers.

In remarks before the final vote, Senate Minority Leader Steve Hershey (R) called the legislation “a bill about talking points” that saves just a little bit of money.

“Leadership and the governor can come to the people of Maryland and say, ‘hey, we did something for you,’” Hershey said. “And what we’ve said all along is you might have done something — you’ve done the absolute bare minimum.”

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Vineyard Wind Seeks to Force GE Renewables to Finish Work

Vineyard Wind is asking a court to block its turbine manufacturer from walking away from a nearly complete offshore wind project as the two squabble over hundreds of millions of dollars in cost overruns.

Vineyard Wind 1 outlined the dispute with GE Renewables US in a memorandum filed April 8 in Suffolk County Superior Court in Boston (2684cv01041).

Vineyard maintains that its 2021 turbine supply agreement with the subsidiary of GE Vernova clearly allows Vineyard to withhold payments in the amount that GE Renewables owes to Vineyard as determined through an impartial review by the project engineer.

The 806-MW wind farm off the coast of Massachusetts has sustained two years of delays and more than $1 billion in damages from component failures that GE Renewables admitted were its own fault, Vineyard said, particularly the replacement of turbine blades determined to contain manufacturing defects.

The project engineer so far has decided claims worth $853 million in Vineyard’s favor, the court filing states, and Vineyard has withheld $308.1 million. The contract is worth approximately $1.32 billion, according to the filing.

No reply by GE Renewables was present in the docket as of April 13, but the parent company told RTO Insider in a prepared statement:

“GE Vernova recently completed the installation of all 62 wind turbines at the Vineyard Wind Farm. The majority of these turbines are now generating electricity for homes and businesses in Massachusetts. Unfortunately, Vineyard Wind has chosen to withhold payments for more than 18 months, totaling more than $300 million, for work performed.

“Consequently, GE Vernova exercised its contractual right to terminate the ongoing project agreements for non-payment. The company remains committed to the safety of the wind farm and stands by our performance and our contractual obligations. We will vigorously defend our position through the appropriate legal process.”

GE Vernova has suffered continuing losses and setbacks in its offshore wind business and has indicated it will be stepping back from the offshore sector after it fulfills its contract obligations.

But stepping back prematurely would be disastrous for Vineyard Wind, the plaintiffs say, dooming the project to failure and leaving behind a “dormant wind farm graveyard.”

GE Renewable Energy’s 13-GW Haliade-X was billed as the most powerful offshore wind turbine on the market when introduced. It has been deployed only at Vineyard and at Dogger Bank, under construction in the North Sea.

The Vineyard turbines still have dozens of significant nonconformities curtailing their performance, the court filing states, and will require specialized maintenance for their entire service lives.

The Haliade-X is larger and more complex than other turbines, the filing states. Most or all troubleshooting, optimization and repair work will rely on GE Renewables’ propriety tools and components.

The manufacturer is irreplaceable in the project, Vineyard says, which is why the parties agreed to a contract provision requiring GE Renewables to continue working during any dispute resolution process or related court proceeding.

Vineyard’s April 8 emergency motion for preliminary injunction and temporary restraining order seek to force it to do just that.

GE Renewables gave notice to Vineyard on Feb. 27 that it would terminate the contracts effective April 28 on grounds that it is owed more than 5% of the contract price. The two parties met as recently as April 6 but were unable to reach an agreement.

Vineyard said that under a mutually agreed timeline, GE Renewables will file an opposing brief by April 15 and if it chooses to reply, Vineyard will do so by April 17. A hearing will follow the week of April 20.