Search
April 8, 2025

Posted on

MISO Discards Interim Participation Option from Order 2222 Plan

MISO on April 7 announced it will scrap its plan to use an existing demand response participation category to get aggregators of distributed energy resources participating on a limited basis a few years ahead of its full implementation of FERC Order 2222 in 2030.  

During a DER Task Force meeting, MISO counsel Michael Kessler said the RTO decided that trying to bend the interim plan to all Order 2222 requirements as FERC recommended would be “unduly burdensome.” Kessler said MISO plans to inform FERC by July that it will abandon its DR participation idea rather than try to make it fully compliant with the rule. 

FERC accepted MISO’s second try at Order 2222 compliance Jan. 16, granting the RTO until mid-2029 to prepare before fully accepting DER aggregators into its markets in 2030. (See FERC Permits 2030 Finish Date for MISO Order 2222 Compliance.) 

The commission accepted MISO’s explanation that its underlying computer systems need work over the next four years. However, it told the RTO its plan to allow DER aggregations in its markets earlier in a two-phase rollout needed to be either deleted or revised significantly. 

MISO proposed to use a two-stage approach to Order 2222 compliance. First, it would use an existing DR resource participation category to get DER aggregations participating sooner — albeit on a limited basis — and providing energy, contingency reserves and capacity through behind-the-meter generation or controllable load. MISO would have begun registering DER aggregations under its DRR Type I model by Sept. 1, 2026, and would have allowed participation to begin by June 1, 2027. DER aggregations would have been limited to 1 MW or larger under the model. 

But in its Jan. 16 order, FERC said MISO’s proposed 1-MW size threshold is too large, as Order 2222’s minimum for participation is only 100 kW.  

The commission also said MISO’s DR placeholder doesn’t address the coordination, data requirements or means to discourage double-counting of resource contributions required under Order 2222. It decided the RTO missed the mark on using an existing participation model to eke out partial compliance. 

FERC gave MISO 180 days to either explain how the DRR Type I participation model could comply with Order 2222 or strike the first phase of participation from its compliance plan. MISO decided over the last few weeks that it would not salvage that aspect for a separate filing to allow DER aggregations to provide some services by the middle of 2027. 

Kessler said MISO attempting to make its planned, interim step complaint with Order 2222 would likely require the same system changes that aren’t doable until full compliance with the rule in late 2029 through mid-2030. 

Posted on

Federal Briefs

Venture Global’s Calcasieu Pass LNG Facility Gets FERC Approval

FERC last week approved U.S. LNG developer Venture Global to commence service on the remainder of the facilities at the Calcasieu Pass LNG Terminal in Louisiana, according to a filing. 

Venture Global recently asked FERC for permission to begin operations at its entire Calcasieu Pass LNG export facility and TransCameron pipeline project, the final step before moving to commercial operations. 

More: Reuters 

FERC Approves Pipeline Extension

FERC last week approved a 122-mile natural gas pipeline expansion cutting through East Tennessee. 

The Ridgeline pipeline will stretch from Smith County to the TVA’s Kingston power plant. To fuel the plant, Enbridge’s pipeline company plans to extend its pipeline all the way to Roane County. 

Construction is set to begin in the fall and be completed by fall 2026. 

More: WATE 

BLM Extends Public Comment Period for Oregon Lithium Project

The Bureau of Land Management last week extended the public comment period for a lithium exploration project in Oregon to April 25. 

BLM has been reviewing Jindalee Resources’ proposal to explore federal land for lithium since 2022. The agency published its resulting environmental assessment in late March and gave the public just five days to review and comment. BLM received more than 1,500 comments in those five days. 

The proposal includes drilling at more than 260 sites across 7,200 acres of sagebrush desert in Malheur County, near the Oregon-Nevada border, in search of lithium. 

More: OPB 

Posted on

State Briefs

REGIONAL 

SouthCoast Wind Contract Delayed for a Third Time

SouthCoast Wind and utility companies in Rhode Island and Massachusetts last week announced a three-month extension to finish contract negotiations for the 147-turbine wind farm planned south of Martha’s Vineyard and Nantucket. 

The new June 30 deadline marks the third delay since Rhode Island and Massachusetts jointly unveiled plans in September to buy power from SouthCoast Wind following a solicitation that included Connecticut. Supply chain delays and inflationary pressures have driven up developer costs, prompting some companies, including SouthCoast, to renege on existing pricing agreements in hopes of a more lucrative deal. That has put more pressure on utilities and ratepayers to cover the rising expenses. 

More: Rhode Island Current 

COLORADO 

Polis Signs Bill Recognizing Nuclear as Clean Energy

Gov. Jared Polis last week signed a bill that will have the state recognize nuclear energy as “clean energy.” 

This year’s bill passed the Legislature with bipartisan support, with a 43-18 vote in the House and a 29-5 vote in the Senate. 

Nuclear energy production in Colorado has been dormant since 1989, when the state’s only nuclear power plant, Fort St. Vrain in Weld County, ceased operations.  

More: The Aspen Times 

IOWA 

MidAmerican Energy Seeks New Natural Gas Fee

MidAmerican Energy last week filed a request with the Utilities Commission seeking approval to add a 0.4% capital investment charge to the bill of residential gas customers. 

MidAmerican spokesman Geoff Greenwood said the charge, which would add about 17 cents to the average residential bill, would “cover costs that Mid-American has already paid out that are associated with certain natural gas system costs.” 

More: Radio Iowa 

MARYLAND 

Gov. Moore Issues Executive Order that Could Delay EV Sales Penalties

Gov. Wes Moore last week issued an executive order that could delay initial penalties for EV manufacturers who do not meet sales goals under a prescriptive state plan that is supposed to take effect next year. 

The order will maximize the Department of Environment’s enforcement discretion “to ease compliance” with the rule – including by declining to enforce penalties for model years 2027 and 2028. Moore’s order stated that President Donald Trump’s tariffs and actions on electric vehicles, including rescinding funding for charging infrastructure, also pushed Maryland to intervene to assist manufacturers. 

Maryland adopted Advanced Clean Cars II, which requires EVs to account for 43% of cars sold in the state by a manufacturer in the 2027 model year. The number grows to 51% in 2028, eventually reaching 100% by the 2035 model year. The state also adopted a similar rule for larger vehicles such as trucks. Moore’s order also opens the door for the DOE to avoid enforcing penalties on those vehicles for model years 2027 and 2028, unless the agency releases an assessment on the rule by Dec. 1. 

More: Maryland Matters 

MASSACHUSETTS 

DPU Acts Against National Grid over Billing, Service Issues

The Department of Public Utilities last week took action against National Grid, limiting how much it can collect from customers after months of billing failures and fining the company millions of dollars for service issues in 2023. 

The DPU told National Grid in its letter that it was not allowed to bill customers for several months of energy usage, saying, “For each customer who has not received a bill since the beginning of the peak season, the company shall waive charges for any usage occurring more than 60 days prior to the date the company sends the customer its next bill. For customers who did not receive a bill for more than 60 days, the company shall either waive collection of amounts owed for usage more than 60 days prior to the date of said bills or, if the customer has already paid, the company shall credit or refund such sums to each customer.” 

The DPU also fined National Grid $15 million “for service quality failures in 2023.” 

More: WBTS 

MONTANA 

Senate Committee OKs Bill to Give Governor Power to Appoint 3 PSC Members

A bill that aims to give the governor and the Senate the power to appoint and confirm three of the Public Service Commission’s five members passed the Energy, Technology and Federal Relations Committee with a 9-4 vote. 

Currently, all five members are elected by voters in five separate districts and can serve two four-year terms back-to-back. If the bill were to be signed into law, only two of the members would be elected by voters in the state’s two congressional districts. The other three would be appointed by the governor and would need confirmation by two-thirds of the Senate. 

A similar bill introduced in the House earlier this year failed to get out of committee. 

More: Billings Gazette 

PENNSYLVANIA 

Scranton Approves 1st Solar Farm

The Scranton Zoning Board last week voted 3-2 to approve what will be the city’s first commercial solar farm. 

Bear Peak Power of Denver will construct the 3.2-MW farm with 6,580 solar panels on 13.7 acres. 

Further reviews could take 12-18 months, with construction beginning after that. If so, it could be until late 2026 or early 2027 before the facility is operational. 

More: The Times-Tribune 

VIRGINIA 

Mecklenburg County Favors Solar Project

The Mecklenburg County Planning Commission last week voted 7-5 to recommend a special exception permit for the 7 Bridges Solar project. 

The 80-MW project is slated for 499 acres. 

The recommendation advances to the county Board of Supervisors, which is expected to take up the matter May 12. 

More: SoVaNow.com 

WYOMING 

PacifiCorp Changes Plans for Dave Johnston Coal Plant

PacifiCorp last week altered its plans for the Dave Johnston coal-fired power plant while solidifying plans to stop burning coal at the Naughton power plant by the end of this year. 

Rather than fully retiring two of four coal-burning units at the Dave Johnston plant in 2028, the utility now plans to convert those units to natural gas in 2029 and continue their operation. A third coal unit will be shut down in 2027, as previously planned, and the fourth, which had no retirement date, will now be converted to natural gas in 2030. 

The company’s plans for the Jim Bridger plant and the Naughton plant didn’t change. Two of four coal units at Jim Bridger were converted to natural gas last year, and the company still plans to retrofit the other two units there with carbon capture technology by 2030 or 2032. At Naughton, the first of three coal units was converted to natural gas in 2020. PacifiCorp confirmed it still plans to take the two remaining coal units offline by the end of this year and resume operating them on natural gas in 2026. 

More: WyoFile 

Posted on

Company Briefs

Delta Utilities Acquires CenterPoint’s Distribution Companies Serving La., Miss.

Delta Utilities last week announced it has acquired CenterPoint Energy’s three regulated natural gas local distribution companies that serve Louisiana and Mississippi. 

The sale includes around 12,000 miles of main pipeline serving about 380,000 customers. 

No financials were disclosed. 

More: KSLA 

Brookfield Nears $9B Deal for Colonial Pipeline

Brookfield Asset Management is said to be putting the final touches on a deal to acquire Colonial Pipeline, the largest U.S. fuel transportation system, for more than $9 billion including debt, according to people familiar with the matter. 

Colonial’s pipeline system stretches more than 5,500 miles from Houston to New York’s harbor. It moves more than 100 million gallons of fuel daily, including gasoline, jet fuel, diesel and heating oil, according to its website. 

A deal could be formally announced in the coming weeks, barring any last-minute snags, the sources added. 

More: Reuters 

APA Solar Invests $19.5M in Ohio Expansion

APA Solar, a solar racking company, last week announced it is planning to build a new 30,000-square-foot headquarters building in Ridgeville Corners, Ohio. 

The company said it will invest $19.5 million and hire 133 people as part of the expansion. The investment follows an upgrade in 2023 in which the company invested $10 million to expand its Henry County manufacturing facility. 

Construction of the headquarters is expected to be completed in early 2026. 

More: pv magazine 

Lithium Americas Reaches Final Investment Decision for Thacker Pass Mine

Lithium Americas last week said it has reached a final investment decision for constructing the first phase of the Thacker Pass lithium mine in Nevada. 

The Thacker Pass project is a joint venture between Lithium Americas and U.S. automaker General Motors. Phase 1 of the project is expected to be completed in late 2027. Once open, it is expected to produce 40,000 metric tons of battery-quality lithium carbonate per year in its first phase, enough for up to 800,000 EVs. 

More: Reuters 

Posted on

Industry Must Share Risk Over Nuclear-Powered Data Centers, Experts Say

LA JOLLA, Calif. — As the U.S. Department of Energy explores using federal land for data centers powered by nuclear energy, experts say public-private risk sharing will be crucial to making nuclear viable. 

The DOE on April 3 issued a request for information related to developing data centers on federal land, with 16 potential sites identified as “uniquely positioned for rapid data center construction, including in-place energy infrastructure with the ability to fast-track permitting for new energy generation such as nuclear,” according to a news release. 

The issue of nuclear energy and data centers also was discussed in La Jolla, Calif., during the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) on April 4.  

WECC’s 2024 Western Assessment of Resource Adequacy (WARA) found that annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and twice the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.) 

WECC said large loads are a major factor in the rapid demand growth, including data centers, factories and cryptocurrency mining. Electrification also plays a role.  

While there is widespread support for nuclear energy, which holds the potential to supply large amounts of baseload emissions-free electricity, there is a need for risk sharing, especially in the beginning as the industry navigates costs, construction cycles, regulations and other challenges, said Marcus Nichol, executive director of new nuclear at the Nuclear Energy Institute. 

“The utilities that might own and operate and build these, they’re willing to take on some risk,” Nichol said. “We’re actively working with them to help reduce the risk so that it’s more manageable. But they need help to be able to take this on.” 

Nichol noted that there are federal tax incentives in place, and U.S. Sen. Jim Risch (R-Idaho) introduced the Accelerating Reliable Capacity Act in December to accelerate investment in commercial nuclear projects by minimizing cost overrun risk. 

States also are “looking at their own state-tailored policies to be able to help contribute to taking on some of the risk,” Nichol said. Some data center developers also are looking to “contribute and take on some of the risk as well,” Nichol added. 

Meta, Microsoft and Amazon all have announced plans to power data centers with nuclear technology. (See Meta Seeks Nuclear Partners; AWS Boosts Efficiency.) 

For example, Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers. (See Constellation to Reopen, Rename Three Mile Island Unit 1.) 

Amazon, meanwhile, has committed $1 billion to early stage development work, said Nate Hill, head of energy policy at Amazon. 

“From Amazon’s perspective, we’re willing to put our capital at risk to help get some of these early stage projects off the ground,” Hill said. “Because, I mean, when you think about it, like some of the costs of these projects could be more than the market cap of some utilities. So, there’s going to have to be risk sharing.” 

Katie Rogers, manager of reliability assessments at WECC, noted that the numbers could change as WECC learns more about how much of the demand will be realized. 

Still, the industry must move toward holistic grid planning and share the burden, Rogers said. 

“It feels very much like that we maybe need to have a different approach to how we plan the grid, and maybe not looking at, you know, one person carrying or one subset of people carrying all the risk if it has broader implications to the grid,” Rogers said. “It needs to be looked at holistically with everything.” 

Posted on

FERC Approves ISO-NE Order 2023 Interconnection Proposal

FERC has accepted ISO-NE’s compliance proposal for Order 2023, setting the stage for sweeping changes to the RTO’s interconnection procedures.  

The April 4 ruling came nearly eight months after ISO-NE’s proposed effective date of Aug. 12, 2024, and followed months of stakeholder requests for rapid action to preserve the transition timeline and prevent significant delays to projects in the interconnection queue (ER24-2009, ER24-2007). 

FERC’s ruling largely accepted ISO-NE’s proposal but directed the RTO to make relatively minor changes in an additional filing.

Order 2023 and the follow-up ruling, Order 2023-A, require transmission providers to transition from serial interconnection processes to cluster study processes, in which interconnection requests will be studied simultaneously. 

ISO-NE filed its Order 2023 compliance proposal in May 2024 with the support of NEPOOL after an extensive process of stakeholder engagement and revisions. (See NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance and ISO-NE Order 2023 Compliance Proposal Fails to Pass NEPOOL TC.) 

In comments submitted to FERC, developers generally supported the filing, though several groups requested changes, such as a shorter cluster study timeline and reduced study deposit requirements. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.) 

Allco Finance had urged the commission to reject the proposal due to impacts it would have on distribution-level projects and argued ISO-NE does not have jurisdiction over state-level interconnection procedures. But FERC ruled the complaint was outside the scope of the proceeding, finding the company had not demonstrated ISO-NE failed to comply with Order 2023 or Order 2023-A.  

Despite arguments from some stakeholders that ISO-NE should adopt the 150-day cluster study timeline outlined by Order 2023, the commission accepted the RTO’s proposal for a 270-day process. ISO-NE said a 150-day timeline would be infeasible for the region. 

FERC agreed the 270-day timeline “reflects ISO-NE’s unique regional issues and the comprehensive scope of its studies, including electromagnetic transient studies for inverter-based resources.” 

The commission also approved ISO-NE’s proposal to reduce the cluster restudy timeline from 150 to 90 days, noting the RTO “will use the same base case data as the cluster study and will involve fewer interconnection requests, thereby allowing interconnection requests to proceed expeditiously through the interconnection study process.” 

FERC also accepted ISO-NE’s proposal to require a flat $250,000 deposit and a $50,000 application fee for the cluster study, writing that “extending the $250,000 deposit to smaller generators is reasonable due to regional differences because … project size is not a ready indicator of study cost or complexity for interconnection requests in New England.” 

It rejected arguments by Glenvale Solar that ISO-NE’s proposed deposit requirements are prohibitive for smaller projects participating in the process, saying the “proposed flat deposit structure reasonably approximates study costs in New England.”

The commission also approved ISO-NE’s proposal for a $500,000 initial commercial readiness deposit, writing that the amount will help deter speculative interconnection requests. Order 2023 requires commercial readiness deposits to be twice the size of study deposits. 

“While higher than the pro forma [Large Generator Interconnection Procedures], we find the variation is justified because the $500,000 amount reflects historically high network upgrade costs in ISO-NE,” FERC wrote.  

Optimism Around Transitional CNR Study

FERC also accepted ISO-NE’s initial prohibition of using surety bonds for deposits, despite Order 2023’s direction to do so, saying the RTO demonstrated it needs more time to develop the procedures for accepting the bonds. The order directed the RTO to submit more information about when it will begin accepting surety bonds for commercial readiness and study deposits. 

ISO-NE’s transition process for adopting the changes also largely complies with Order 2023, FERC wrote. The commission wrote that the creation of a transitional capacity network resource (CNR) group study helps to appropriately balance “the need to move expeditiously to the new cluster study process with the need to respect the investments and expectations of interconnection customers at an advanced stage in the existing interconnection process.” 

The transitional CNR group study is intended to allow projects with complete system impact studies to gain capacity interconnection rights without needing to go through the full cluster study. Going forward, interconnection customers will achieve capacity interconnection rights through the cluster studies.  

In recent months, project developers have raised alarms that FERC’s inaction on ISO-NE’s compliance proposal could threaten the ability to align the transitional CNR study with the qualification activities for ISO-NE’s 2025 reconfiguration auction (RA). (See New England Generators Remain in Limbo on Interconnection Reform.) 

ISO-NE had said it would need a ruling by March 31 to align the transitional CNR group study with the 2025 RA qualification process due to a show-of-interest submission deadline at the end of April. On March 31, FERC took the unusual step of informing ISO-NE and stakeholders that it planned to issue an order in the coming days. (See FERC Announces Impending Order on ISO-NE Order 2023 Compliance.) 

Alex Lawton of Advanced Energy United, who has been vocal about the importance of the transitional CNR study, said he’s optimistic FERC’s ruling will enable ISO-NE to proceed with the study.  

A representative of ISO-NE said the RTO “is reviewing the April 4, 2025, order in detail and assessing next steps.” 

The ruling also accepted independent entity variations related to site control requirements, the opportunity to reduce project size prior to a cluster restudy, energy storage modeling and the evaluation of alternative transmission technologies. 

FERC directed ISO-NE to make a series of relatively minor changes to its proposal within 60 days, including to correct multiple “unexplained deviations” from the pro forma language, and to add pro forma language that was omitted. The commission also found the proposal did not comply with Order 2023’s ride-through requirements. 

The commission accepted ISO-NE’s proposed Aug. 12, 2024, effective date and the June 13, 2024, deadline for interconnection customers to have a valid interconnection request to be eligible to participate in the first cluster study. While the RTO briefly reopened its interconnection queue April 1, requests submitted after this date will not be eligible to participate in the transitional cluster study. (See ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC.) 

Posted on

Groups Ask FERC to Axe Languishing Proposal to Cut Transmission Incentives

The Edison Electric Institute, GridWise Alliance and WIRES asked FERC on April 3 to end a proceeding that has been open for five years to consider cuts to transmission incentives (RM20-10). 

The commission opened the rulemaking in March 2020 and supplemented it a year later to propose eliminating the existing RTO membership transmission incentive for utilities that have been participating in an organized market for more than three years. The proposal would have focused project-specific incentives on the benefits to customers from transmission investment. 

“The commission’s current transmission incentives policy is working to the benefit of customers, transmission owners and the public interest,” they said in a joint filing. “With the rising demand for electricity, the commission’s existing transmission incentives policy has become even more essential.” 

A lot has changed since the rulemaking launch, they said, including a rapid and unforeseen return to demand growth because of large data centers, reshoring of industry and general electrification pressures. The COVID-19 pandemic led to an economic slowdown and uncertainties in the economic forecasts on which the industry relies. 

FERC also issued Orders 1920 and 1920-A, which are intended to identify considerable new transmission portfolios that might also introduce new risks to development because of the selection of larger and more complex projects, the groups argued. The world also is entering into a period of greater geopolitical tensions and competition, in which promoting domestic energy independence and security is considered a heightened priority. 

While the three trade groups want FERC to abandon the rulemaking, they argued even if the commission wants to go forward, it should take more comments so parties can update the record for the changes over the past half decade. 

President Donald Trump has declared a national energy emergency, in which he emphasized the urgent need to revamp and expand the grid to meet growing demand and ensure reliable supply, they noted. 

“This infrastructure is not only essential for accommodating the increasing power demands from various sectors, but also for maintaining and enhancing the overall resilience and efficiency of the nation’s energy system, which itself underlies the broader economy,” they said. “A reliable, resilient and efficient energy delivery system is the foundation to providing cost-effective electric service to customers of all kinds, thereby aligning with the administration’s broader goals of fostering economic growth and energy security.” 

The incentives date back to the Energy Policy Act of 2005, which acknowledged that increased levels of transmission infrastructure were needed to keep costs reasonable and the system reliable. FERC implemented them in 2006 with Order 679, which established tailored incentives to address risks and challenges associated with transmission development. 

“After nearly two decades, it is undeniable that the commission’s transmission incentives policy has provided the signal and support for transmission investments that ultimately benefit electric customers,” the groups said. As FERC considers changing the incentive policy, it has to weigh whether this would disrupt expectations, create uncertainty and possibly chill investment by eliminating rate treatments that cut risk and aid in lower financing costs to benefit consumers, they said. 

FERC’s proposed change would treat the RTO adder as an incentive to join an organized market, but the groups argued that was not Congress’ intent. 

“The commission is, ultimately, ‘a creature of statute and has only those authorities delegated to it by … Congress,’” they said. “Any action that would restrict eligibility for this incentive beyond the requirement that a transmission owner join an RTO is ultra vires [beyond its legal authority].” 

RTO membership requires TOs to transfer operational control of their facilities to the grid operators, which perform functions like planning, marketing and congestion management. The grid operators can require TOs to make investments in high-risk transmission projects, with the RTO adder helping to offset that risk. 

“Transmission owners in RTOs must also comply with a more expansive set of federal regulations, such as Order Nos. 719, 745, 841 and 2222, which significantly and disproportionally impact RTO regions,” the groups said. “Through these actions, the commission has fundamentally altered the business model, exposed certain future capital investments of transmission owners to competition, increased the potential that investments will be delayed and deprive customers of the benefits, and created significant uncertainty and related regulatory risk.” 

The RTO adder offsets risks incurred in delivering the benefits of RTO membership to customers such as access to cheaper power, efficient dispatch over a wide area and enhanced reliability, which together far outweigh the cost of the adder, they argued. 

Posted on

PJM TEAC Briefs: April 1, 2025

PJM Presents Scope Change to RTEP Projects

PJM presented a $97 million increase to a project included in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3. The change would remove two 230-kV lines between the Mars substation and Sojourner and Shellhorn facilities and reroute them to terminate at the south side of Mars to avoid intersecting with new lines being planned. The original scope is to build a 500-kV line between Mars and Golden and a 230-kV line from Mars to Lockridge and terminating at Golden. The changes bring the total cost to $439.9 million.

Projects included in the 2022 RTEP Window 3 also have obviated the need for two prior projects totaling $7.5 million. The rebuilding of a line between Loudoun and Morrisville will supplant a $4.5 million project to rebuild a 1.3-mile segment of that facility. A $3 million project to replace breakers at the Ox 500-kV substation also is being canceled as the same work is included in baseline projects.

Supplemental Projects

FirstEnergy presented a pair of projects amounting to $37.6 million to replace two 500/138-kV transformers and disconnect switches at its Pruntytown Substation in the APS zone due to the assets nearing end of life and experiencing maintenance issues. The projects are in the conceptual phase with in-service dates of Dec. 13, 2030, and June 13, 2031.

The replacement of another aging 500/345-kV transformer at Wylie Ridge is expected to cost $20 million with a projected in-service date of Dec. 13, 2030. The transformer has increased hydrogen and ethylene readings, moisture buildup and low dielectric strength, according to FirstEnergy.

American Electric Power presented a $50.4 million project to build a new 345-kV substation, to be named Navistar, in the AEP zone to serve a new customer bringing 437 MW of load to the New Carlisle, Ind., area. The facility would be cut into the Dumont-New Prairie 345-kV double circuit lines and would be configured as a breaker and a half with 11 345-kV breakers and two bus ties to the customer. The project is in the scoping phase with a projected in-service date of March 15, 2027.

Dayton Power and Light presented a $480 million project to serve two new customers located near Jeffersonville and Wilmington, Ohio, by expanding several 345-kV substations and linking the Clinton, Fayette and Atlanta facilities with new 345-kV lines. The Fayette and Atlanta substations would be expanded to breaker-and-a-half configurations to accommodate a 25-mile double circuit between the two sites, as well as two customer feeds from Fayette.

The Clinton facility would be expanded with equipment for a new 27-mile line to Fayette and two 345-kV customer feeds. The project is in the conceptual phase with a projected in-service date in January 2031. The Jeffersonville load is expected to come online in September 2026 and ramp up to 1.5 GW of load by 2031, while the Wilmington customer is expected to come on in 2028 and grow to 500 MW.

PPL presented a $101 million project to expand the proposed Tresckow 230-kV substation to include a four-bay breaker and a half 69-kV yard to serve a customer expected to bring 300 MW of load to Hauto, Pa., in 2028. Four 230/69-kV transformers also would be installed, as well as two 69-kV double circuit lines connecting Tresckow to the Frac-Tres 69-kV No. 1 and No. 2 lines. The project is in the conceptual phase with a projected in-service date of May 30, 2028.

Duke presented a $49 million project to build a new 345-kV substation, to be named Gold Finch, along the Silver Grove-Red Bank 345-kV line to serve a new customer seeking to interconnect 300 MW in Clermont County, Ohio. Gold Finch would be configured as a ring bus with four 345-kV breakers and a control building. The project is in the scoping phase with an in-service date of June 1, 2028.

Dominion presented a $450 million project to upgrade several lines and transformers to address load drop and thermal violations on the Ladysmith CT-Fredericksburg and Ladysmith CT-Four Rivers 230-kV lines. The violations were identified in the 2025 do no harm analysis. The project is in the conceptual phase with an in-service date of July 1, 2029.

Phase 1 of the project, expected to be complete in January 2028, includes rebuilding 6.5 miles of the Summit DP-Fredericksburg Sub 230-kV line with higher capacity conductor; reconductoring 7.3 miles of the Ladysmith-Ladysmith CT line; adding two 500-kV capacitor banks to Ladysmith; and building a new 230-kV line running between Ladysmith, New Post, Lee’s Hill and Allman using a mix of new structure and vacant arms.

Phase 2 would go online in July 2029 to expand the Kraken 500-kV switching station to cut into the Summit DP-Fredericksburg Sub 230-kV line, the St. Johns-Four Rivers 230-kV line and the planned Ladysmith-Allman 230-kV line. The St. Johns-Four Rivers and Four Rivers-Elmont lines also would be rebuilt. The 115-kV lines from Fredericksburg-Four Rivers, Pinewood-Four Rivers, Four Rivers-Elmont, and Pinewood-N. Doswell lines would be “wrecked” and a new double circuit 230-kV line would be built from Kraken to Allman, along with a single circuit line from Kraken to Elmont.

Several additional Dominion projects would serve new service requests across its footprint. A $10.1 million project would construct a 230-kV ring bus with four breakers at its Trabue substation; two new 230-kV substations, Ruther Glen and Carmel Church, would be added to the Ladysmith CT-Four Rivers line for $87 million; and two new 230-kV substations, New Post and Lee’s Hill, would be built along the Fredericksburg-Ladysmith CT line for $43 million.

The Wabash Valley Power Alliance presented an $80 million project to construct a 15-mile, 345-kV line between AEP’s Elderberry substation and NIPSCO’s Stillwell substation. The line will be operated by MISO and is being submitted to PJM’s supplemental planning process to allow study coordination.

Posted on

PJM MIC Briefs: April 2, 2025

Stakeholders Narrowly Endorse Uplift Changes

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a joint PJM and Independent Market Monitor proposal to rework how uplift and deviation charges are calculated for market sellers depending on how they respond to market signals and dispatch instructions. It passed with 53.3% support and is set to go for a first read at the Markets and Reliability Committee on May 21. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.) 

The changes would establish a new tracking ramp-limited MW desired (TRLD) metric to replace the three existing MW desired metrics used in calculating balancing operating reserve (BOR) credits and deviation charges. The TRLD would follow how a unit responds to instructions over time, rather than focusing on individual five-minute intervals as the ramp-limited desired, dispatch and locational marginal pricing-desired metrics do. 

PJM’s Lisa Morelli said that would address scenarios where a unit ignoring dispatch and keeping its output steady can avoid deviation charges. 

The TRLD would account for any dispatch instructions arising from ancillary services a market seller is responding to as well, such as regulation or sync reserve, allowing corresponding automatic exemptions from deviation to be eliminated. 

In past meetings, Morelli gave the example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch under the status quo. Additionally, because dispatch is limited by ramp rates in the next interval, PJM could bring it down only to 95 MW in the following interval. 

The proposal also would rework the BOR credit formula by taking the lesser of real-time output or the TRLD and adjusting for ramp parameters for each interval, which Morelli said would simplify the equation. The start and end points for uplift eligibility would be revised to align with when a market seller’s commitment began and to run through either the end of that commitment or the unit’s minimum run time. 

Morelli said PJM’s goal is not to reduce uplift and the changes are likely to be a net benefit for many participants, as they also address scenarios where generators are undercompensated in some scenarios. 

If endorsed by the Members Committee in July, Morelli said PJM would aim to file tariff revisions at FERC in September. The changes would be implemented in two phases, starting with simulated results in market settlements reporting system (MSRS) reports before affecting actual settlements in late 2026 or early 2027.  

Responding to stakeholders questioning how PJM could respond to any gaps or unintended consequences identified during the soft launch, Morelli said the intention is to have enough detail in the tariff language to give direction to how the TRLD would function, with finer detail spelled out in the manuals. Any edge cases stakeholders are concerned about could be addressed by adjusting the manuals without needing to make additional FERC filings. The governing document language likely would empower PJM to adjust the TRLD if there are instances where SCED would dispatch a unit inconsistent with locational marginal pricing or the unit’s offers. 

Committee Endorses Manual 11 Periodic Review

Stakeholders endorsed revisions to Manual 11: Energy & Ancillary Services Market Operations drafted through the document’s periodic review. The changes were deferred during the committee’s March 5 meeting after concerns were raised with the language designating data centers as plug load. (See “Periodic Review of Manual 11 Deferred,” PJM MIC Briefs: March 5, 2025.) 

PJM’s Joseph Tutino said the proposal was changed since the first read to include data centers and crypto mining as “business segment” load following feedback that plus load typically includes smaller devices, such as household appliances. He said the remaining changes are mainly typographical. 

PJM’s Maria Belenky told the committee in March that data centers are considered plug load for the purpose of curtailment service providers (CSPs) reporting load enrolled in demand response. 

First Reads on Manual Revisions

PJM presented a first read on revisions to Manuals 6, 11, 28 and 29 to conform with FERC’s May 2023 order accepting a PJM proposal on how it proceeds with settlement under a market suspension. PJM’s transmittal letter states that a market suspension never has occurred but could result from “extraordinary circumstances such as a failure of computer systems.” (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.) 

The filing stated that the tariff has no way of determining energy and ancillary service prices when zonal dispatch rates cannot be calculated by software. Three different sets of rules are included for determining real-time prices when suspensions last less than six hours, between six and 24, or for longer. Shorter suspensions would use the average real-time prices for each hour prior to and following the outage; for moderate duration events, day-ahead prices would be used if available, otherwise real-time prices would be used; and for suspensions exceeding a day, an aggregate supply curve would be developed (ER23-1431).  

The proposed Manual 28 language would use actual output for calculating energy offers during real-time energy market suspensions. Lost opportunity costs (LOC) would not be included for suspensions longer than one day, and BOR charges would be allocated to real-time load plus exports if a suspension exceeds one hour. 

PJM also gave a first read on revisions to Manual 18 to conform with FERC orders granting several changes PJM sought to make to its capacity market in recent months (ER25-682, ER25-785, ER24-2995). 

The bulk of the changes arise from FERC’s Feb. 14 order granting a host of capacity market changes meant to address tightening supply and demand. The corresponding manual revisions would codify delayed Base Residual Auction (BRA) dates; model resources operating on reliability-must-run (RMR) agreements as capacity; continue the use of a combustion turbine generator as the reference resource; and clarify that market sellers do not hold “safe harbor” from claims of market power exercise by holding a categorical exemption from the requirement that all resources holding capacity interconnection rights (CIRs) must offer into the capacity market. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

It also includes the elimination of must-offer exemptions for intermittent, storage and hybrid resources, requiring market sellers to offer those units into capacity auctions starting with the 2026/27 BRA scheduled to be conducted in July. Stakeholders and intervenors argued the exemption artificially increased auction clearing prices, while many generation owners argued the existing and proposed market rules do not allow them to reflect the risk exempt resources would take on with a capacity obligation. 

The final change would be to memorialize the removal of the energy efficiency addback and eliminate the resource class outright following the 2025/26 delivery year. PJM argued to the commission that the addback was a holdover from a prior set of rules and no longer was needed, as EE was captured in its load forecast. Removing capacity status for EE was sought as the RTO argued that it could not be demonstrated that capacity market revenues were used to reduce load. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.) 

Stakeholders Discuss Pseudo-tied Resources

The committee continued its discussions on how pseudo-tied generators are assigned to locational deliverability areas for the purpose of determining clearing prices and the amount of local capacity PJM models as available within a zone. The subject was brought up by the North Carolina Electric Membership Corp. (NCEMC) to explore whether a load-serving entity seeking to self-supply with pseudo-tied generation should receive the clearing price for an LDA or the RTO-wide clearing price, with the latter being the status quo. 

PJM’s Nebiat Tesfa said pseudo-tied resources are those that have an indirect connection to PJM, hold firm transmission service and are studied to ensure deliverability akin to internal resources. Those studies do not, however, determine whether any particular resource is deliverable to a specific LDA; to ensure the right to inject to an LDA, either incremental capacity transfer rights (ICTRs) or investment in qualifying transmission upgrades (QTUs) must be obtained. In some cases, modeling the flow from a pseudo-tied resource can use the reliability requirement for an LDA to increase, she said. 

PJM’s Tim Horger said the RTO’s priority going into the topic is ensuring there are no inconsistencies between internal and pseudo-tied resources when modeling congestion or transmission. 

In its own presentation, NCEMC said there were circumstances in the 2025/26 BRA where LSEs were exposed to price separation within their LDAs and were prevented from using their own resources adjacent to that zone and which they believe are electrically serving that load. It said analysis of dispatch data shows that those units are providing congestion management in Mid-Atlantic Dominion. 

Horger said PJM and stakeholders have to be careful when considering changes down the path of using distribution factor (DFAX) analysis to determine whether a given resource is helping a specific LDA. 

Carl Johnson, representing the PJM Public Power Coalition, said if resources are tied to an LDA, especially when it’s the same organization trying to serve load with its own resources, there should be a way of recognizing that the cost shouldn’t be different just because an LDA separates. 

PJM’s Jonathan Kern said the CETL study is agnostic about which capacity resource is supplying an LDA, so there’s going to be some association with the CETL and generation outside the LDA but not associated with any particular resource. 

Posted on

PJM OC Briefs: April 3, 2025

Stakeholders Endorse Manual Revisions

VALLEY FORGE, Pa. — The Operating Committee endorsed a pair of revisions to Manual 1: Control Center & Data Exchange Requirements and Manual 37: Reliability Coordination. 

The changes to Manual 1 would align with NERC standards IRO-010, TOP-003 and EOP-008 and include updating the Generation Scheduling Service table with generation periodic eDART and Cold Weather Checklist data requests. 

The periodic review of Manual 37 led to recommendations to update references throughout the document and remove the 3 p.m. posting deadline for next day reliability analyses. 

March Operating Metrics

PJM’s Marcus Smith presented the forecast error and operating metrics for March, which saw a 1.47% hourly forecast error and three days exceeding the 3% peak error benchmark. 

Warmer-than-expected temperatures March 4 led to load coming in lower than expected, pushing the peak error to 3.05%, while the hourly rate was 1.63%. March 6 saw cooler temperatures corresponding to peak loads being 4.14% lower than forecast. A similar dynamic was seen March 15, when the peak was 5.01% lower than forecast.  

Three shared reserve events, one high system voltage action, seven post-contingency local load relief warnings and six shortage cases were issued. Two of the shortage cases were on March 15 due to lines tripping. Four were on March 19 and were attributed to load increases and reduced reserves being available. 

Update on Regulation Market Design

PJM’s Damon Fereshetian presented an update on the implementation of PJM’s regulation market redesign, the first phase of which is set to go live Oct. 1, 2025. The second phase is scheduled to roll out a year later. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

Phase 1 includes consolidating the RegA and RegD signals into one bidirectional signal, shifting to 30-minute clearing from hourly, eliminating the accuracy and delay components of performance scoping to focus only on precision, and changes to opportunity costs and the regulation requirement. The RegD product provides fast response, while RegA is used for long deployments. 

Training on the changes is set to begin in May. Sandbox testing software will launch either that month or in June. PJM targets endorsement of manual language codifying the changes in August, with education sessions Aug. 12 and Sept. 5.