SEA PJM Flash 25-6: Issued: February 12, 2025

SEA's most up to date Legislative Tracking Spreadsheet can be found here. Please feel free to contact John Keene with any questions regarding PJM Footprint legislative tracking.

RTO PJM

PJM Market Implementation Committee discusses IMM proposal for DR availability window

On February 5, 2025, at the Market Implementation Committee meeting (see agenda), PJM Interconnection, LLC (PJM) provided a presentation on proposed changes to its Demand Response (DR) Availability Window to accommodate seasonal changes in capacity that DR can offer into the market. We covered PJM’s proposal, which was presented at a Special Session of the Market Implementation Committee on January 27 in PJM Flash 25‑5. Currently, Winter Peak Load (WPL) values are used to determine the winter value of DR. PJM asserted that the formula results in a total WPL that “overstates the expected load and corresponding reduction capability of the DR fleet in any one hour, as different customers experience their peak loads at different times of the day.” Additionally, PJM asserted that the current Effective Load Carrying Capability (ELCC) modeling also overestimates the reduction capability of DR during the performance window.

PJM’s Internal Market Monitor (IMM) provided an updated presentation on the DR availability window. In addition to its prior recommendations presented at the January 27 meeting, the IMM provided several other recommendations. The IMM proposed applying the same rules for summer and winter windows, consistent for all hours. The IMM proposed basing the WPL coincident peak hour used on analysis of DR customer load data for all hours rather than only five hours, as proposed by PJM. The IMM proposed introducing a “resource specific performance adjustment factor consistent with other [Effective Load Carrying Capability (ELCC)] resources.” The IMM also proposed adopting criteria for when PJM will dispatch load management DR resources. The IMM recommended addressing all ELCC issues at the same time due to “interaction effects.” The IMM contended that in the 2025/2026 Base Residual Action, the Installed Capacity (ICAP) of DR resources was overstated, resulting in overpayment to DR resources.

PJM submits Hybrids Phase III Proposal with enhancements to current market rules; Comments due Feb. 19

On January 29, 2025, in FERC Docket ER25-1095, PJM Interconnection, LLC (PJM) filed proposed tariff revisions to update its market rules for the participation of Hybrid Resources. Last discussed in PJM Flash 25-3, these revisions come as Phase 3 of an ongoing, three-year process PJM has been undertaking. Revisions consider enhancements to and clarification of existing market rules for solar-storage (co-located solar and storage) and other inverter-based hybrids and defining additional market rules for non-inverter-based hybrid configurations, e.g., gas-storage. Phase 3 was introduced in November 2023 (see problem statement).

A Hybrid Resource is a resource consisting of multiple fuel types behind one interconnection point that operates as a single resource in the market. Hybrid Resources can include configurations of multiple inverter-based technologies, such as wind-battery, solar-wind, solar-storage, and solar-wind-battery, among others. Phase 1 was initiated in July 2020 and defined the market rules for co-located generation and energy storage hybrids generally, but specifically focused on solar-storage hybrids. FERC approved the solar-storage participation model PJM in a July 2022 Order and it went into effect in July 2023. Phase 2 was initiated in February 2022 and expanded the hybrid definition and participation model to all combinations of inverter-based technologies. FERC approved the inverter-based technology participation model in a September 2023 Order approving the proposed revisions in September 2023.

PJM proposed the following tariff revisions:

Hybrid Resources with a Non-Inverter Component and a Storage Component

PJM proposed permitting a non-inverter component to pair with a storage component located behind the same point-of-interconnection to form one integrated Hybrid resource. PJM also proposed removing the qualification that only Hybrid Resources consisting of inverter-based components are eligible to be dispatched for positive and negative MWs, expanding eligibility to all Hybrid Resources. PJM noted that it is not expanding this proposal to include the participation of non-inverter resources paired with a storage component as a Hybrid Resource, contending that the market participation rules for different Hybrid configurations must reflect differences in operational characteristics. PJM proposed clarifying that Mixed Technology Facilities (MTFs) with non-inverter generation components and intermittent components are “still only eligible to participate as Co-Located Resources.”

Open-Loop and Closed-Loop Hybrid Resources

PJM proposed revising the definitions of Open- and Closed-Loop Hybrid Resources to allow participants to choose the resource’s classification depending on whether the resource will charge its storage component from the grid or from on-site generation only. PJM would remove language requiring that these resources be “physically or contractually [capable/incapable] of charging.” Instead, PJM would allow the resource to distinguish whether the resource “[does/does not] operate by charging its storage component.” PJM also proposed changes to the Network Integration Transmission Service (NITS) Agreement to accommodate this shift by not charging Closed-Loop Hybrid resources under the NITS Agreement.

Energy Market Must-Offer Requirement

PJM proposed requiring Hybrid and Capacity Storage Resources with capacity obligations to self-schedule the unit “where the hourly day-ahead self-scheduled values for such Hybrid Resources or Capacity Storage resources may vary hour to hour from the capacity commitment” to satisfy their energy market must-offer requirement.

Uplift Rules Regarding Lost Opportunity Costs

PJM proposed clarifying that, resources that increase charging when instructed to do so and that would otherwise already be charging based on their offer curve, will not be compensated for Lost Opportunity Costs (LOC). PJM contended that “it would not be appropriate to compensate a unit for lost generation revenues when the unit was, in fact, not generating.” Energy Storage Resource (ESR) Model participants would only be eligible for balancing operating reserve (BOR) credits. PJM also proposed allowing Hybrid Resources to demonstrate why they should be eligible for LOC compensation.

Hybrid Resources Eligibility to Provide Reserves

PJM proposed explicitly stating that Hybrid Resources comprised exclusively of wind and solar components cannot provide Synchronized Reserves or Secondary Reserves. Currently, eligibility rules and offer requirements for providing certain reserves “do not distinguish between generation-only (e.g., wind plus solar) and generation plus battery hybrids.” Under the new rules, Hybrid Resources with a battery component would be eligible to provide these reserves but Hybrid Resources comprised of all inverter-based components would not be able to provide reserves.

Definition of Hybrid Resource Class

PJM proposed broadening the definition of the Hybrid Resource Class to include resources made up of multiple components which, for example, would allow a Hybrid Resource with two generation components, like wind and solar, to participate.

PJM proposed an effective date of March 31, 2025. Comments are due February 19 by 5:00 pm ET

Stakeholders submit responses to PJM’s answer in RRI proceeding, PJM files subsequent response to stakeholder comments

As last discussed in PJM Flash 25-5, on December 13, 2024, in FERC Docket ER25-712, PJM Interconnection LLC (PJM), submitted—despite substantial stakeholder opposition—its Reliability Resource Initiative (RRI) proposal to allow additional resources to participate in Transition Cycle #2. We discussed the details of PJM’s RRI proposal, stakeholder feedback, and PJM’s initial reply comments in PJM Flash 24-47, PJM Flash 25-2, and PJM Flash 25-5, respectively. More than 50 stakeholders filed Motions to Intervene and submitted comments in this proceeding.

Between January 31 and February 4, 2025, the following parties submitted responses to PJM’s reply comments:

Clean Energy Associates (CEA)
Constellation Energy Generation (Constellation)
Invenergy Renewables LLC (Invenergy)
Sierra Club

We summarize the core positions of each commenter as follows:

In its comments, Invenergy noted that it strongly opposes the RRI proposal, citing financial harm to projects already in Transition Cycle #2 (TC2) Invenergy asserted that those projects already in TC2 would face an estimated $8 billion in new network upgrade costs (due to the RRI). Invenergy argued that PJM’s RRI proposal violates the filed rate doctrine by allowing queue jumping and undermines established expectations for developers who complied with the original process.
Sierra Club alsoopposed the RRI proposal on policy and environmental grounds. Sierra Club asserted that the RRI violates open access principles, favors thermal resources over renewables, and oversteps PJM’s jurisdiction by influencing the generation mix, which, under the Federal Power Act should fall under state control.
CEA also opposed the RRI proposal for both financial and procedural reasons, emphasizing that PJM failed to meet its burden of proof under the Federal Power Act. CEA also argued that the RRI proposal violates the filed rate doctrine, undermines the interconnection process’s integrity. Additionally, CEA proposed that FERC require PJM to use a “but-for” cost analysis to protect TC2 projects from additional costs. In this proposal, TC2 projects would fund the lesser of their standalone (existing TC2 projects only) or combined (existing TC2 plus RRI) upgrade costs.
Constellation supported the RRI proposal, defending it as necessary for addressing reliability concerns and arguing that it is legally sound. Constellation rejected claims of queue jumping, asserting that TC2 projects had no settled expectations of exclusivity in the queue. They also criticized Invenergy’s financial impact analysis as unreliable and speculative.

On February 5, PJM submitted a response to the latest round of reply comments. In its response, PJM continued to assert that its RRI proposal is just and reasonable and not unduly discriminatory or preferential. PJM argued that the proposal is critical to address near-term reliability concerns in the PJM region and continued to request that FERC accept the RRI proposal by February 11, 2025, with an effective date of December 14, 2024. PJM also contested Invenergy’s claim that the RRI will impose $8 billion in additional network upgrade costs on TC2 projects, arguing that Invenergy’s model is flawed and skewed to overstate the financial impact. Specifically, PJM criticized Invenergy for using the 2027 Regional Transmission Expansion Plan (RTEP) base case instead of the 2028 RTEP base case, which PJM said omits critical inputs, such as (i) projected load increases from new data centers, (ii) planned generator deactivations and their impacts on system capacity, and (iii) the reduction of projects in Transition Cycle #1.

In addition, PJM disputed the claims from Invenergy, CEA, and Sierra Club that the RRI proposal violates the filed rate doctrine or constitutes retroactive ratemaking. PJM argued that the RRI is a prospective tariff change that applies only to future interconnection requests. PJM also noted that FERC has previously upheld similar reforms (e.g., MISO’s queue cap proposal—which we discuss elsewhere in this Flash Update), finding that they do not violate open access principles. PJM also refuted the arguments that the RRI results in queue jumping, asserting that no interconnection customer has a guaranteed right to be the only project studied in a particular cycle, and that the scoring mechanism and project selection criteria are designed to ensure fair access and prevent undue preference.

PJM presents wind and solar dispatch proposal

As discussed in PJM Flash 25-2, on January 10, 2025, at the PJM Interconnection, LLC (PJM) Distributed Resources Subcommittee (DERSC) meeting (see agenda), PJM presented design options for “Wind and Solar Resource Dispatch in Real-time Market Clearing Engines.” At the February 3, 2025DERSC meeting (see agenda), PJM presented an update (the February update). As noted in the presentation, these are options that PJM can support and implement but PJM is open to considering other options as well. As discussed in PJM Flash 24-32 the dispatch methodology for intermittent resources creates operational challenges for PJM’s Real-Time (RT) Market Clearing Engines (MCE), and as a result, PJM is initiating the process to determine potential enhancements to the dispatch methodology for solar and wind resources.

The February update shows numerical examples of the design options presented earlier this year showing how a solar/wind unit would be dispatched if curtailed, operating above bid parameters and while in transition between the two. PJM concluded that “constraint volatility may be minimized, it is not eliminated with this proposal” and notes that it will continue to work on the proposal and present further updates in future meetings. PJM did not identify any next steps.

PJM files CIR Transfer Reforms with FERC, proposing new Replacement Generation Interconnection Process; Comments due Feb. 21

As discussed in PJM Flash 24-50, on December 9, 2024, the PJM Interconnection, LLC (PJM) Board of Managers (the Board) issued a Letter that, in part, noted the Board’s support for PJM’s stakeholder-supported solution package to enhance capacity interconnection rights (CIRs) transfer efficiency. As discussed in PJM Flash 24-40, PJM has explained that under its current market rules, owners of existing generation capacity resources can transfer their CIRs to new resources; however, this process faces delays of up to four years before the transferred CIRs can be used due to the timing of generator deactivations and interconnection studies and other logistical difficulties.

On January 31, 2025, in FERC Docket No. ER25-1128, PJM filed the solution package as proposed Tariff changes (the CIR Transfer Reforms). If approved, the CIR Transfer Reforms would establish a serial (not cluster) Replacement Generation Interconnection Process, separate from PJM’s standard cluster interconnection process, for proposed new generation resources expecting to receive the CIRs from a deactivating generation resource. To qualify for the Replacement Generation Interconnection Process, a proposed resource must:

Be the designated transferee on a “Notice of Intent to Transfer CIRs” form submitted by the transferring deactivating resource before its deactivation date
Submit a Generation Interconnection Request within one year of the deactivation date, thus claiming the CIRs
Connect at the same voltage level at the same interconnection substation as the deactivating resource
Not exceed the nameplate capacity (MW) of the deactivating resource

The Replacement Generation Interconnection Process would consist of three phases over approximately 300 days, as follows:

Application Phase (60 Days): Applicant submits necessary documentation (e.g., Notice of Intent to Transfer CIRs, site control, project data), followed by a review and a scoping meeting. As a serial interconnection process, there is no application window, and applications would be processed on a rolling basis.
Impact Study Phase (180 Days): PJM performs thermal, voltage, short circuit, and stability analyses. If a material adverse impact is found, the applicant may make changes to the project to mitigate the impact. Subsequently, the transmission owner (TO) performs a Facilities Study to identify required interconnection facilities and network upgrades and provide cost and time estimates.
Generator Interconnection Agreement (GIA) Negotiation Phase (60 Days): PJM, the TO, and the applicant negotiate and execute a GIA.

Other notable provisions include:

The Replacement Generating Resource may be of any fuel type, including standalone battery storage, regardless of the deactivating resource’s fuel type.
A project may have both an active Replacement Generation Interconnection Request and an active New Service Request (i.e., for the standard cluster interconnection process).
In the event that a project is, or is deemed to be, withdrawn from the Replacement Generation Interconnection Process, the project can retain its CIRs so long as it has an active New Service Request. PJM would provide notice of such an occurrence to allow the project time to submit a New Service Request.
In the event that a project is, or is deemed to be, withdrawn from the Replacement Generation Interconnection Process, the project can retain its CIRs so long as it has an active New Service Request (i.e., for the standard cluster interconnection process). PJM would provide notice of such an occurrence to allow the project time to submit a New Service Request.
The Replacement Generating Resource cannot begin commercial operation prior to the actual deactivation date of the deactivating resource. However, the commercial operation date (COD) must be within three years of the later of the deactivation date, the date on which the GIA is executed, or the date on which the developer requests that PJM file the GIA with FERC unexecuted.

There is a one-time option to extend the COD beyond three years regardless of cause, and the developer may otherwise extend the COD for “unforeseen regulatory or construction delays that could not be remedied … through the exercise of due diligence.”
The three-year deadline does not apply to resources with “industry-recognized significant construction timeframes, such as nuclear and combined-cycle.”
Should a Replacement Generating Resource fail to meet its COD requirements, it must submit a New Service Request or lose its CIRs.

Any network upgrade costs are wholly allocated to the Replacement Generation Resource and are not shared with other Replacement Generation Resources or resources in the standard cluster interconnection process.

According to the Combined Notice of Filings, the deadline for stakeholder comments is February 21 at 5:00 pm ET.

IMM issues Report Parts D, E, and F reviewing PJM’s capacity auction results for commitment year 2025/2026

On February 4, 2025, Monitoring Analytics, the Independent Market Monitor (IMM) for PJM Interconnection, LLC (PJM), published Part E and Part F of its Analysis of the 2025/2026 Reliability Pricing Model (RPM) Base Residual Auction (BRA). Report Parts D (issued December 6, 2024), E and F build on prior analysis (Part A, discussed in PJM Flash 24-39, Part B discussed in PJM Flash 24-42 and Part C discussed in PJM Flash 24-47), in which the IMM had first evaluated the impact of certain capacity market traits independent of each other and then in combination with each other. Part C of the report discussed the impact of changes of policy related to inputs of the capacity market auctions on the price of 2026/2027 auction. IMM expects to publish a consolidated report combining all these intermediate reports as it does after every capacity auction, but the publication date has not yet been confirmed.

Report D

Report D examined sensitivities to the 2025/2026 capacity auction results and implications of market design changes for the 2026/2027 auction results. In the latest round of sensitivities on the 2025/2026 auction prices, the IMM considered the following sensitivities (scenario 50)

Maximum point on the demand curve to be calculated as 1.5 times Net CONE of a combustion turbine (CT) resource (instead of a combined cycle resource used for the 2025/2026 auctions)
A forward net revenue offset
2.5% increase in net load forecast
Marginal ELCC values based on winter accreditation
All categorically exempt resources who did not offer, did offer
Reliability must run resources were offered at $0/MW-day in BGE

The IMM analysis suggests that these changes would have seen a price decrease of 37.6 percent compared to the actual results for the 2025/2026 capacity auctions and a 6% increase in capacity. As a result of this part of the analysis, the IMM recommended that PJM should use 1.5 times Net CONE used as the maximum price on the demand curve (VRR curve) rather than Gross CONE.

Report E

Report E examined the impact of updating the 5.0% load growth scenarios to include updates to Gorss CONE and Net CONE values, and to include scenarios with 1.5 times the Net CONE. Specifically, Report E looked at the effects of the following variables on capacity market revenues:

Using a Combustion Turbine as the reference resource under different Net and Gross CONEs
Excluding two reliability must-run (RMR) plants from the capacity market supply curve
Using summer ratings rather than winter ratings for Combustion Turbine and Combined Cycle reference resources
Withholding by categorically exempt resources

IMM asserted that “the results of the scenarios analyzed in Part E confirm the results in Part C and Part D.” The IMM found that using Gross CONE as the maximum price in the Variable Resource Requirement (VRR) curve “results in a significant increase in revenues” for the 2025/2026 BRA, as compared to both the actual results and using 1.0 or 1.5 times the Net CONE as the maximum price. The IMM also found that, with the use of Gross CONE, including the RMRs in the supply curve at $0/MW-day resulted in an increase in revenues compared to actual results, using 1.0 times the Net CONE, and 1.5 times the Net CONE.

Report F

Part F of the report examined two things:

the impacts of using a maximum price of $325/MW-day and a minimum price of $175/MW-day in UCAP terms for the capacity market demand curve and
the 5.0 percent increase load growth in all scenarios

The maximum and minimum price also represent PJM’s agreement with Pennsylvania Gov. Shapiro (as discussed in PJM Special Flash 25.1) to implement certain changes in the PJM capacity market rules for the immediate term of 2026/2027 and 2027/2027 auctions. The IMM recommended implementing these changes in addition to the below for an effective implementation of the agreement between PJM and Gov. Shapiro.

removing the categorical exemption for intermittent resources
including the capacity of RMR resources at $0/MW-day and
calculating ELCC using winter capabilities

According to the IMM, this would result in a lower capacity market price compared to PJM’s proposal to define the price cap as the maximum between Gross CONE or 1.75 times the Net CONE.

PJM Market Implementation Committee to discuss implementing offer cap for long lead scheduled resources

On February 5, 2025, at the Market Implementation Committee (MIC) meeting (see agenda), PJM Interconnection, LLC (PJM) released an Issue Charge and Problem Statement to consider setting an offer cap for resources “scheduled prior to the Day-Ahead [DA] Energy Market,” or long-lead scheduled resources. As explained in the problem statement, PJM can schedule resources before the DA market if it deems that conservative resource scheduling is necessary. PJM noted this effort comes as “entities have raised concerns with potential market power and manipulation.” PJM intends to review existing governing documents and provide education on the existing scheduling process. PJM clarified that Day-Ahead and Real-Time offer capping is not in scope for the issue charge.

Phase One will consider the appropriate schedule to commit resources scheduled prior to the DA Energy market and Phase Two will consider how to enhance existing rules “to more accurately reflect fuel costs in cost-based offers of resources that are scheduled prior to the [DA] Energy Market.” PJM expects Phase One to be initiated in March and completed by May. PJM expects Phase two to be initiated in April and completed in October.

PJM files motion to withdraw Welcome Solar ISA notice of cancellation as project not in breach of any milestone

On February 4, 2025, in FERC Dockets No. ER25-453, ER25-454, and ER25-455, PJM Interconnection, LLC (PJM) filed Motions to withdraw Notices of Cancellation for Welcome Solar, LLC, Welcome Solar II, LLC, and Welcome Solar III, LLC (collectively Welcome Solar) (as last discussed in PJM Flash 24-50). PJM requested the Notices of Cancellation be withdrawn in accordance with its conclusion that Welcome Solar is no longer in breach of any milestone under the Welcome Solar Interconnection Service Agreements (ISAs).

Background

On December 6, 2024, Welcome Solar filed an Amended and Restated Complaint after PJM filed Notices of Cancellation (Welcome Solar, Welcome Solar II, Welcome Solar III) on November 15 for ISAs for the Welcome Solar projects. Two of the projects are located in Mercer County, PA, and one in Crawford County, PA. Two have a capacity of 19.9 MW and one has a capacity of 17.9 MW.

Welcome Solar filed the Amended Complaint to “take into account subsequent developments” since the original Notices of Breach were issued by PJM on September 5. Welcome Solar requested a shortened Answer period of seven-days. On October 4, following the Notices of Breach, Welcome Solar filed its original Complaint, to which PJM responded, requesting that FERC deny the Complaint. In the Notices of Cancellation, PJM claimed that Welcome Solar failed to meet applicable project milestones, including “substantial site work.” PJM requested an effective date for the cancellation of the Welcome Solar ISAs of January 15, 2025. In its Amended Complaint, Welcome Solar alleged that PJM made “materially misleading misrepresentations” to FERC regarding the status of the projects and information Welcome Solar provided to PJM in response to the September 5 Notices of Breach.

Current Status

PJM noted in its Motions to Withdraw that Welcome Solar undertook good faith efforts to meet project milestones.

PJM Board responds to letters received on Capacity Market Must Offer Exemption proposal

On February 4, 2025, the PJM Interconnection, LLC (PJM) Board of Directors (PJM Board) responded to letters received from stakeholders regarding the proposed elimination of exemptions from the Capacity Must Offer requirement for certain resources in the PJM capacity market (as discussed in PJM Flash 25-1).

The PJM Board responded to two letters: one from the Organization of PJM States (OPSI) (see response to OPSI) and another from Advanced Energy United, American Clean Power Association, MAREC Action, and the Solar Energy Industries Association, together, the Clean Energy Associations (CEAs) (see response to CEA). The PJM Board noted that many of the concerns expressed in the letters have been addressed in the Proposal that PJM submitted to FERC in Docket No. ER25-785. In the Proposal, PJM proposed to eliminate the categorical exemption available to certain resources and thereby extend the Must-Offer Requirement in its capacity market to all generation capacity resources (as discussed in PJM Flash 24-52) The PJM Board had approved the filing before it was submitted to FERC.

In its response to CEA, the PJM Board noted that they recognize the risks to generators whose categorial exemption is proposed to be removed, despite the need to remove such exception for the broader market. The PJM Board pointed out other efforts being made by PJM or already made to alleviate these risks such as

Being allowed to consider non-performance risks in capacity market offers
Changing the actions (or inactions) that can trigger a non-performance penalty
Adjusting the Capacity accreditation methodology to ensure that capacity is calculated correctly

Other RTO PJM News of Note

PJM submits informational filing about certain transmission projects approved by PJM Board: On January 31, 2025, in FERC Docket No. ER13-198-000, PJM Interconnection, LLC (PJM) submitted an Informational Filing Regarding Immediate-Need Reliability Projects. As required by Schedule 6 Section 1.5 of the PJM Governing Documents, PJM must post a list of the Immediate-Need Reliability Projects designated to an existing transmission owner in the prior calendar year every January. Appendix A of the Filing lists the Immediate-Need Reliability Projects designated to a transmission owner in 2024. Appendix B provides a status update on the 13 Immediate-Need Reliability Projects carried over from the 2024 Informational Report.

Back to Headlines

New Jersey

Rate Counsel files comments opposing Attentive Energy’s motion to stay on financial payments, recommend funds placed in escrow

On February 3, 2025, in New Jersey Board of Public Utilities (BPU) Docket No. QO22080481, the New Jersey Rate Counsel filed comments opposing Attentive Energy’s Motion to Stay two payments required by the BPU’s January 2024 Order approving the Attentive Energy Two 1,342 MW offshore wind project as a qualified project to sell offshore renewable energy credits (discussed in PJM Flash 24-0). As discussed in PJM Flash 25-5, Attentive Energy specifically sought to stay the initial commitment security and the unpaid portion of the research and monitoring fee associated with New Jersey’s Research and Monitoring Initiative. Attentive Energy cited delays in “prebuilt and non-prebuilt infrastructure” as well as uncertainty relating to the federal permitting timeline for the project as the rationale for the stay. Prebuilt infrastructure refers to the duct banks and associated cable access vaults that would be installed at the qualified offshore wind ports specified by the January 2024 Order. Attentive emphasized that it is seeking a limited stay on only those two provisions and would comply with all other requirements from the January 2024 Order.

In its Comments, Rate Counsel asserted the stay is not limited, and Rate Counsel requested seeks approval of the following:

Additional time for Attentive Energy and BPU Staff to consider and address the unexpected external events
BPU starts its review of the supplemental compliance filing 180 days in advance of the initial commitment security payment
Additional time for Attentive to secure the financial backing already approved in the January 2024 Order

Rate Counsel noted that it does not oppose additional time for the BPU and stakeholders to consider these external events, the stay should be denied as it is not a prerequisite for fostering a discussion with the BPU regarding the payments, and it would not be in the public interest to delay the required payments. The Rate Counsel suggested that at a minimum, the BPU requires that Attentive Energy place the funds in an escrow account while these external events are considered.

Stakeholders submit comments on dual-use solar energy pilot program

As last discussed in PJM Flash 24-44, on October 29, 2024, in Docket QO23090679, the New Jersey Board of Public Utilities (BPU) issued an Order establishing the Dual-Use Solar Energy Pilot Program. Dual-use solar, also known as agrivoltaics, refers to solar that is sited on active farmland. According to a BPU press release accompanying the Order, the Program has a capacity of 200 MW over three years, with the potential to be expanded after the initial period. The pilot program also requires participating projects to allow research conducted by the Rutgers University Agrivoltaics Program (RAP) on the project site, the results of which will inform a permanent program that may include standards for construction and operation for dual-use projects. On December 3, in Docket QX24080597, the BPU issued a set of proposed rules for the program, requesting stakeholder comments by January 31, 2025.

By January 31, the following stakeholders filed comments on the proposed rules:

BlueWave Solar (BlueWave)
ForeFront Power (ForeFront)
Lightstar
Mid-Atlantic States Career and Education Center and Tatleaux Energy (MASCEC/Tatleaux)
New Jersey Division of Rate Counsel (NJDRC)
Renewable Properties

We summarize the comments below, sorted by topic area:

Incentive levels and ratepayer impact: Under the proposed rules, developers would apply with an incentive level that would be incremental to the Administratively Determined Incentive (ADI) under New Jersey’s Successor Solar Incentive (SuSI) Program, needed to cover incremental project costs. NJRDC recommended that the scoring rubric used for project selection give at least 50% weight to the incentive level offered by the developer. Renewable Properties sought clarification on whether the dual-use incentive adder estimate provided in the prequalification application phase is binding. NJRDC recommended against any future expansions of the program’s initial 200 MW capacity and opposed capacity carve-outs for specific project types, citing ratepayer impacts. NJRDC also recommended that the BPU require a deposit with applications.

Community Solar participation: Under the proposed rules, dual use projects would not be allowed to participate in the Community Solar Energy Program (CSEP) but would be allowed to participate in Remote Net Metering (RNM). BlueWave and ForeFront argued that dual-use projects below 5 MW should be able to participate in CSEP. ForeFront requested that projects be allowed to apply for RNM designation before they have secured a specific RNM offtaker, arguing that it is impractical to contract RNM customers for a project which is in the early stages of development. MASCEC/Tatleaux requested that BPU make rules that allow developers to sell energy to residential consumers, but did not specify whether it was referring to RNM or CSEP.

Control area: Under the proposed rules, dual-use projects would be required to set aside a 3-acre portion of farmland as a “control area” without any solar development. Lightstar and BlueWave argued that the 3-acre control area is too large, noting that most family farms in New Jersey are on small acreage. Lightstar and BlueWave proposed that the rules be amended to require control plots to be 15% of the total project site acreage, with a minimum of 0.5 acres and maximum of 3 acres. Lightstar, Bluewave, and ForeFront requested that the control area be able to be sited on an adjacent parcel if the parcel belongs to the same owner.

Research period: Participating projects are required to allow research conducted by the Rutgers University Agrivoltaics Program (RAP) on the project site. ForeFront requested clarification on the length of the required research period. Lightstar requested clarification on the farmers’ responsibilities in carrying out the research.

Stakeholders submit comments following NJBPU technical session on PJM’s Order 2222 compliance approach

As discussed in PJM Flash 24-31, in February 2020, in FERC Docket No. ER22-962, PJM Interconnection, LLC (PJM) submitted its Initial Compliance Filing to comply with FERC Order No. 2222 (Order 2222). As summarized in PJM Flash 20-0, Order 2222 required Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) to allow distributed energy resource (DER) aggregations (DERAs) to participate in wholesale markets (i.e., energy, capacity, and ancillary services markets). PJM has since submitted further compliance filings, including a filing on October 23, 2024, in which PJM requested that FERC permit a delay of the effective date of its compliance from February 2, 2026, to February 1, 2028. FERC has yet to act on that filing.

As discussed in PJM Flash 24-52, on December 12, in Docket EO24020116, the New Jersey Board of Public Utilities (NJBPU) issued a Notice setting a Technical Conference to be held on January 17, 2025, to discuss PJM’s Order 2222 compliance and “identify potential paths for implementation of Order 2222 within the [S]tate.” The NJBPU also requested that stakeholders file comments on the matter.

By the deadline on January 31, the following stakeholders filed comments:

Coalition Advocating DER Regulation Efficiency (CADRE)
Collaborative Utility Solutions (CUS)
DER Task Force (DERTF)
New Jersey Utilities Association (NJUA)
Public Service Electric and Gas Company (PSEG)
University of Delaware EV R&D Group (UDelaware)
Uplight
Vote Solar

CADRE provided “14 best practices” for State implementation of Order 2222, including implementing DERA licensing that requires “technical fitness to engage with and manage data from the [electric distribution companies (EDCs)]” and recovering DER interconnection costs via a fixed $/kW charge or by socializing the costs across ratepayers.

DERTF recommended that the NJBPU align this proceeding with the Grid Modernization (Docket QO24030199) and Advanced Metering Infrastructure (Docket EX24090717) to more “holistically” support DER integration and encouraged near-term investment to improve visibility into and use of DER-related data.

NJUA and PSEG emphasized the need to prevent simultaneous wholesale and retail compensation for DERAs (prohibited under Order 2222) and recommended that the NJBPU establish working groups to further consider certain issues, such as cost allocation and recovery, DERA registration and regulation, and interconnection standards.

UDelaware recommended measures that would facilitate the participation of EVs as behind-the-meter (BTM) storage resources in retail and wholesale markets.

Uplight recommended that the NJBPU hold further technical sessions, including on cost recovery and the experience of end-use customers, especially low income and disadvantaged community customers. Uplight recommended that the EDCs serve as DERAs to ensure access to wholesale markets for all customers with DERs.

Vote Solar recommended that the NJBPU require EDCs to develop cost estimates for “aggregation compliance and market facilitation” that include the distribution-level benefits of DERs.

Silver Run Electric posts quarterly update for New Jersey Clean Energy Corridor project designed to provide interconnection points for offshore wind

On January 28, 2025, in New Jersey Board of Public Utilities (BPU) Docket QO20100630, Silver Run Electric, LLC (Silver Run) filed its Quarterly Status Report on its Silver Run Expansion Project, a high-voltage transmission project connecting New Jersey and Delaware. he Silver Run Expansion project will add new submarine cables next to the existing cables currently in service beneath the Delaware River (see details here).

According to the status report, Silver Run has applied for various permits with the New Jersey Department of Environmental Protection (NJDEP) and the Delaware Department of Natural Resources and Environmental Control (DNREC) making the permitting and land acquisition scope to be 20% complete. In terms of construction, Silver Run has negotiated agreements for procuring submarine cables while evaluating costs for other materials. Silver Run expects to secure adequate project financing by October 2027 but has not secured any financing yet. There has been no change in the anticipated in-service date for the line, which is expected to be June 2029.

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Maryland

Maryland legislative leaders file bills on electricity supply and grid reliability, would require procurement for new nuclear and gas generation, establish solar and storage siting processes, and require integrated planning

On February 3, 2025, legislative leadership of the Maryland General Assembly, including House Speaker Adrienne A. Jones (D), Senate President Bill Ferguson (D) and energy committee chairs from both chambers announced the introduction of a slate of bills to address the historically high prices in the recent 2025/2026 Base Residual Auction (BRA) held by the PJM Interconnection (PJM), and retail electric rates generally. The legislative leaders held a press conference, reported on by multiple news sources, in which they announced they would introduce three bills with the intent to increase electric supply in the State to bring down prices and ensure continued electric system reliability.

The public rollout of the bills and the explicit support from the leadership of both chambers highlights the political pressure that elected officials are under to address energy costs, and therefore the strong political momentum behind these bills. Given these dynamics, we expect these bills to be some of the main legislative vehicles for energy policy this session. No hearings have been scheduled yet for the bills.

We note as context that Maryland has attempted to incent in-state generation in the past, ultimately resulting in the Hughes V. Talon Energy Marketing Supreme court decision. In that ruling, the Supreme Court ruled that a Maryland program to incent new gas generation in the State intruded into FERC jurisdictional wholesale markets. However, the Decision noted that “Maryland’s program is rejected only because it disregards an interstate wholesale rate required by FERC. [The program has used a contract for differences with an express requirement that the generation clear the capacity market and thereby lower the capacity price.] Neither Maryland nor other [s]tates are foreclosed from encouraging production of new or clean generation through measures that do not condition payment of funds on capacity clearing the auction,” thereby allowing other types of programs.

We summarize the introduced bills below:

HB 1035 and SB 937 Public Utilities – Electricity Generation Planning – Procurement, Permitting, and Co-Location (Next Generation Energy Act). If enacted, this legislation would:

Require Maryland Energy Administration (MEA), in coordination with the Maryland Public Service Commission (PSC) and the Maryland Department of Natural Resources (DNR) to:

Pursue cost-sharing agreements with other states in PJM to mitigate the risk of building new nuclear facilities, and pursue agreements to locate new small modular reactor nuclear generating sites on federal lands.
Prohibit electric generation owners from contracting for the direct supply of electricity to commercial and industrial customers in a way that bypasses interconnection with transmission and distribution system (i.e. co-locating bend the meter) unless the generator increases its capacity to meet 100% of the new large customer’s load, or creates new generation to meet 100% of the large customer’s load.
Mandate the issuance of a competitive solicitation for constructing or expanding dispatchable energy in Maryland on or before October 1, 2025. The bill defines dispatchable energy as a generating resource or energy storage with an effective load carrying capacity (ELCC) of 65% or higher and lower greenhouse gas (GHG) emissions than an oil or coal plant. The solicitation must:

Procure an amount of dispatchable generation “greater than the combined summer peak capacity profile of coal and oil generating stations … under Table 9 of the Commission’s Ten-Year Plan (2024-2033) of Electric Companies in Maryland,” or at least 3.1 GW by 2030. There is no upper limit on the amount of procured dispatchable generation, but the amount of procured natural gas generation is capped at 3.1 GW.

Any procured natural gas facility must be able to be converted to a zero-carbon fuel source but only on a vague timeline of “when the conversion is feasible.”

Specify certain evaluation criteria, including ratepayer impact, construction and grid connection timelines, and whether any Tier I eligible resources are co-located with this dispatchable energy resource.
Specify certain application requirements, including:

Certain analyses, including:

A cost-benefit analysis to include impacts on income, wages, and taxes
An analysis of the environmental and health benefits and impacts to the State
A ratepayer impact assessment, including the project’s effect on energy and capacity markets
An analysis of the impact on Maryland businesses and other benefits from in-state construction and maintenance

A proposed timeline, including the projects interconnection queue position and an assessment of its ability to procure materials

Specify that “the costs related to the construction or operation of a dispatchable energy generation project … may not be recovered through utility rates.” It is unclear how the procurement would otherwise be funded.

Require the PSC to accept applications for the construction or upgrade of nuclear generating facilities. Any such application should include and would be evaluated on its impact to ratepayers, including on energy and capacity prices and transmission costs; environmental impacts; construction timeline; and waste management practices. The bill would also require the PSC to set a ratepayer impact price cap above which applications would not be accepted.
Require the PSC to create and adopt regulations related to long-term nuclear purchases, including several provisions nearly identical to the energy section of bills introduced by Gov. Moore, discussed elsewhere in this Flash. Specifically, the PSC would be required to:

Open at least three nuclear generation procurement application windows prior to January 1, 2031, and make a determination on application approval no later than one year after each application window closes. We summarize the proposed application requirements below. Applications must include:

A detailed project description and financial analysis, including a proposed financing method
Certain other analyses, including:

A cost-benefit analysis to include impacts on income, wages, and taxes
An analysis of the environmental, health benefits and impacts to the State
A ratepayer impact assessment, including the project’s effect on energy and capacity markets

A proposed long-term pricing schedule that includes a price for energy, capacity, ancillary services, and environmental attributes
A decommissioning and waste storage plan
A plan for engaging small businesses

In its evaluation, consider an applicant’s plan to use skilled labor and the project’s sitting and feasibility
Require any applicants seek investors to “make serious, good-faith efforts to solicit and interview a reasonable number of minority investors,” defined as an individual who is a member of any group listed in § 14–301(K)(1)(I) of the State procurement article. If approved, an awardee would be required sign an agreement with the PSC to “use best efforts” to obtain contractors and subcontractors that are minority business enterprises. Approved applicants would also be required to enter into a community benefit agreement.

Authorizes electric distribution companies (EDCs) to include nuclear pricing costs on customer bills as a non-by-passable surcharge paid by all EDC customers and would require the PSC to establish and supervise an escrow account to facilitate the transfer of revenue and pricing payments. EDCs would be required to procure nuclear energy from the escrow account equal to the EDCs percentage of sales each year based on sales reported by PJM. Approved nuclear projects would be required to sell all energy, capacity and ancillary services to PJM and deposit revenues into the PSC established escrow account. The PSC would distribute deposited revenues to EDCs who would credit customer accounts.
Issues a broad policy statement that Maryland supports renewal of Calvert Cliffs nuclear reactor licenses, which are currently scheduled to expire in 2034 and 2036
Streamlines process for permitting new generation and energy storage projects with decisions required within six months

HB 1036 and SB 931 Public Utilities – Generating Stations – Generation and Siting (Renewable Energy Certainty Act). If enacted, this legislation would:

Establish that, for proposed 2+ MW community solar arrays that meet certain requirements:

The PSC, when considering an application for a Certificate of Public Convenience and Necessity (CPCN), must ensure that the developer has met certain public engagement, setback, screening, landscaping, lighting, and decommissioning requirements
Are exempt from personal and real property taxes, though the host community may instead require a payment of up to $5,000/MW

Establish certain requirements for the development and construction of energy storage systems (ESSs) (e.g., landscaping, fencing), and provide that local jurisdictions may not prohibit the construction or operation of ESSs
Require local jurisdictions to expedite the review and approval of site development plans for proposed solar arrays that meet certain requirements
Authorize local governments to establish automatic enrollment programs for community solar projects under certain circumstances
Establish requirements for the sellers, lessors, and installers of certain residential rooftop solar systems (e.g., provide 5-year warranties, inform customers of the expected minimum weather-adjusted energy output)
Require the PSC to investigate and develop a process to establish partnerships between electric companies and suppliers for generation projects; it must submit its findings to the General Assembly no later than December 1, 2026

HB 1037 and SB 909 Energy Resource Adequacy and Planning Act. If enacted, this legislation would:

Establish an Integrated Resource Planning Office (the Office) as a component of the PSC, with its director appointed by the Governor
Require the Office to coordinate with the PSC, MEA, Power Plant Research Program, Maryland Clean Energy Center, and the Maryland Department of the Environment to establish a 25-year “comprehensive energy forecast” and submit a report containing its findings on or before December 31, 2026
Require the forecast consider “energy scenarios and policy options for meeting the state’s energy needs and greenhouse gas emissions reduction goals while ensuring electric distribution system reliability and cost–effectiveness consistent with the long–term energy needs of the state” and require the delivery of short and long-term recommendations based on the study to the General Assembly.
Require that the study consider the viability of energy storage as a transmission asset, the necessity of an independent system operator, the feasibility of utilizing small modular reactors on former generation sites, and various questions regarding the state’s procurement approaches and authority.
Require that the Office completes modeling of recommended strategies contained in the forecast (including detailed requirements regarding what such studies must consider) and report results to the General Assembly on September 1, 2027, and every 2 years thereafter
Require the PSC to adopt regulations by December 1, 2025, requiring the electric distribution companies (EDCs) to develop an integrated resource plan for submission to the PSC by July 1, 2026, and update such plans every five years thereafter

Stakeholders comment on draft energy storage regulations, proposing refinements but generally supporting overall direction

As last discussed in PJM Flash 25-1, on December 30 2024, the Maryland Energy Storage Workgroup (Workgroup) filed a Request to Resume RM85 Rulemaking Session, and proposed regulations for implementing the Maryland Energy Storage Program (MESP), previously referred to as the Maryland Energy Storage Initiative (MESI). On December 30, in Docket RM85, the Maryland Public Service Commission (PSC) issued a Notice of Rulemaking Session & Comment Period inviting interested parties to submit comments on the matter through January 29. Seven stakeholders filed comments (Items 17-22):

We summarize these comments, organized by topic, below:

Eligibility and Participation Requirements: AEU expressed concerns that the revised MESP regulations may unintentionally exclude residential behind-the-meter storage devices from participation, mainly because applicants must apply before construction. They recommended explicitly allowing pre-existing energy storage devices to apply regardless of installation date. Similarly, REV emphasized the need to prioritize front-of-the-meter, transmission-connected storage in Maryland’s procurement process and urged the PSC to include transmission-level storage in the initial procurement round explicitly.

Stakeholder Engagement and Administrative Burden: NineDot raised concerns about extensive stakeholder engagement requirements for small-scale (Front of the Meter) FTM projects, arguing that the one-mile engagement radius in urban areas creates excessive burdens. They proposed reducing the radius to 0.25 miles and exempting FTM projects under 20 MWh from specific procedural requirements while also allowing developers with multiple nearby projects to consolidate their outreach efforts. PowerFlex similarly objected to the application of stringent engagement requirements to all FTM storage projects, regardless of size or location. They proposed an exemption for non-utility-owned FTM projects under 20 MWh sited in commercial or industrial zones, warning that the current framework requiring project-by-project exemptions would create unnecessary administrative complexity.

Regulatory Clarity and Procedural Certainty: MJEU called for greater clarity and structure in the proposed regulations, raising concerns about the ambiguity of Code of Maryland Regulations (COMAR) 20.50.14.07(H), which allows blanket exemptions for multiple energy storage devices. They recommended removing this subsection and advocated for replacing discretionary language like “may” with “shall” in COMAR 20.50.14.11(A & C) to ensure clear deadlines and procedural certainty. OPC also stressed the need for more precise language, pointing out that the proposed rules lack critical details on program design and implementation. They urged the PSC to explicitly define “cost-effective” and ensure that all FTM storage devices comply with safety, siting, and environmental standards. Additionally, OPC warned that the revised language in COMAR 20.50.14.11 weakens PSC approval requirements for FTM storage applications and called for restoring firm approval requirements to maintain regulatory oversight.

Procurement and Market Mechanisms: REV urged the PSC to adopt procurement mechanisms aligned with statutory requirements, recommending a partial-toll procurement model similar to one used in California. They emphasized the importance of clear county and municipal approval timelines to prevent unnecessary delays and opposed technology carve-outs in procurements, arguing that a market-driven approach should determine the most cost-effective storage solutions. AEU also expressed support for the swift implementation of the regulations but urged the PSC to ensure that all viable storage technologies and configurations remain eligible to contribute to Maryland’s energy storage goals.

Energy Storage Regulations and Market Growth: MJEU raised concerns that allowing blanket exemptions for multiple energy storage devices could create regulatory loopholes, calling for clearer procedural requirements to prevent delays and inefficiencies in storage deployment. NineDot warned that excessive stakeholder engagement requirements could hinder market growth for small storage projects, particularly in urban areas. PowerFlex highlighted that leading markets like New York and California apply similar engagement requirements only to projects larger than 20 MWh, suggesting Maryland should adopt a similar threshold. REV pointed to high PJM capacity prices as evidence of Maryland’s urgent need for new in-state storage capacity and reinforced the importance of a streamlined procurement process.

Senate Education, Energy and the Environment and House Economic Matters Committees to meet Feb. 20 and Feb. 21 to consider Gov. Moore energy bills

The Maryland Senate Education, Energy and the Environment (EEE) Committee and House of Representatives Economic Matters (ECM) Committee scheduled hearings to consider two identical bills requested by Governor Wes Moore (D).

EEE scheduled a hearing on February 20, 2025, in Room 2 of the West Miller Senate Building to consider SB 434. The agenda and bill text are now available.

ECM scheduled a hearing on February 21, 2025, in Room 230 of the House Office Building to consider HB 505. The agenda and bill text are now available.

SB0434/HB0505 Empowering New Energy Resources and Green Initiatives Toward a Zero-Emission (ENERGIZE) Maryland Act. If enacted, among other things, this legislation would amend the name of the Maryland Renewable Portfolio Standard (RPS), administered by the Maryland Public Service Commission (PSC) to the Clean Energy Portfolio Standard (CEPS) and update the name wherever referenced throughout the Maryland Code.

The legislation would establish a 100% clean energy goal and identify three categories of energy generating sources that are eligible to meet CEPS requirements: (i) Tier 1 renewable sources (ii) Tier 2 renewable sources, both unaltered from the RPS, and (iii) nuclear generation, including small modular reactors (SMR) connected to the distribution grid serving Maryland. To achieve the 100% clean energy goal the State would be required to facilitate the construction of at least 3,000 MW of clean energy generation. We note that the current RPS fulfills 50% of the CEPS goal, the Calvert Cliffs Nuclear facility fulfills 25% of the CEPS goal, leaving the remaining 25% of the goal to come from new nuclear or Tier 1 renewable energy. We summarize the proposed annual CEPS requirements below.

60.5% in 2025, including at least

35.5% for Tier 1 renewable sources

At least 7% from solar
An amount set by the PSC, not to exceed 10% from offshore wind
At least 0.25% from geothermal systems

2.5% from Tier 2 renewable sources

63% in 2026, including at least

38% for Tier 1 renewable sources

At least 8% from solar
An amount set by the PSC from offshore wind, including at least 400 MW of Round 2 offshore wind projects
At least 0.5% from geothermal systems

2.5% from Tier 2 renewable sources

66.5% in 2027, including at least

41.5% for Tier 1renewable sources

At least 9.5% from solar
An amount set by the PSC from offshore wind, including at least 400 MW of Round 2 offshore wind projects
At least 0.75% from geothermal systems

2.5% from Tier 2 renewable sources

68% in 2028, including at least

43% for Tier 1renewable sources

At least 11% from solar
An amount set by the PSC from offshore wind, including at least 800 MW of Round 2 offshore wind projects
At least 1% from geothermal systems

2.5% from Tier 2 renewable sources

74.5% in 2029, including at least

50% for Tier 1renewable sources

At least 14.5% from solar
An amount set by the PSC from offshore wind, including at least 1,200 MW of Round 2 offshore wind projects
At least 1% from geothermal systems

2.5% from Tier 2 renewable sources

75% in 2030, including at least

49.5% for Tier 1renewable sources

At least 12.5% from solar
An amount set by the PSC from offshore wind, including at least 800 MW of Round 2 offshore wind projects
At least 1% from geothermal systems

2.5% from Tier 2 renewable sources

Nuclear generation sources connected to the distribution grid serving the State and approved by the PSC would qualify to meet the CEPS. The legislation would establish criteria, conditions and provisions the PSC must follow when evaluating nuclear generation sources for CEPS approval. The PSC would be required to open at least three nuclear generation procurement application windows prior to January 1, 2031, and make a determination on application approval no later than one year after each application window closes. We summarize the proposed application requirements below. Applications would be required to include but would not be limited to the following.

A detailed project description and financial analysis, including a proposed financing method.
A cost-benefit analysis to include impacts on income, wages, and taxes. An analysis of the environmental, health benefits and impacts to the State. A ratepayer impact assessment, including the project’s effect on energy and capacity markets
A proposed long-term pricing schedule that includes a price for energy, capacity, ancillary services, and environmental attributes.
A decommissioning and waste storage plan
A deposit of at least $6 million into the Maryland Clean Energy Business Development Fund
A plan for engaging small businesses

While not application requirements, in its application evaluation, the PSC would be required to consider among other provisions, an applicant’s plan to use skilled labor, and the project’s sitting and feasibility.

Applicants seeking investors would be required to “make serious, good-faith efforts to solicit and interview a reasonable number of minority investors,” defined as an individual who is a member of any group listed in § 14–301(K)(1)(I) of the State procurement article. If approved, an awardee would be required sign an agreement with the PSC to “use best efforts” to obtain contractors and subcontractors that are minority business enterprises. Approved applicants would be required to enter into a community benefit agreement.

The legislation would authorize electric distribution companies (EDCs) to include nuclear pricing costs on customer bills as a non-by-passable surcharge paid by all EDC customers and would require the PSC to establish and supervise an escrow account to facilitate the transfer of revenue and pricing payments. EDCs would be required to procure nuclear energy from the escrow account equal to the EDCs percentage of sales each year based on sales reported by PJM. Approved nuclear projects would be required to sell all energy, capacity and ancillary services to PJM and deposit revenues into the PSC established escrow account. The PSC would distribute deposited revenues to EDCs who will credit customer accounts.

Streamline the development of offshore wind projects by reducing barriers and modifying several statutory provisions related to offshore wind. The definition of qualifying offshore wind projects would be expanded to include projects that interconnect to PJM service territory. We note that the current RPS excludes offshore wind projects that do not interconnect to a point on the Delmarva Peninsula. Specific projected net rate impact restrictions on both residential and nonresidential customers are removed from the PSC approval process and the bill authorizes the PSC to determine net rate impact restrictions. The legislation would also require the PSC to establish an escrow account and requires Offshore Wind Renewable Energy Credit (OREC) applicants to deposit at least $5,000 per MW of nameplate capacity for the purpose of encouraging developers from pulling out of the OREC process.

The legislation would amend the name and expand the purpose of the Offshore Wind Business Development Fund (OSWBDF) to the Clean Energy Business Development Fund (CEBDF), administered by the Maryland Energy Administration (MEA). Offshore Wind developers awarded ORECs would be required to deposit at least $6 million into CEBDF. We note that the current RPS requires OREC awardees to deposit at least $6 million into the OSWBDF. The legislation would also re-establish the Offshore Wind Business Development Advisory Committee, renaming it to the Clean Energy Business Development Advisory Committee, and expanding its composition by adding two representatives from the following industries (i) nuclear energy (ii) solar energy, and one member from the energy storage industry

The legislation would also alter alternative compliance payments (ACP) associated with solar energy requirement shortfalls under the CEPS. Beginning on January 1, 2025, ACP would be held at six cents per kWh and maintained thereafter. We note that under current statute, solar ACP decreases annually, beginning in 2025 from five- and one-half cents per kWh through 2030 to two- and one-quart cents per kWh and is maintained thereafter.

If either bill is enacted, it would take effect on July 1, 2025, and apply retroactively to CEPS compliance years beginning on January 1, 2025.

Stakeholders may register to testify on SB 434 by creating a “My MGA” account. The Senate Education, Energy and the Environment Committee YouTube channel will livestream the hearing

Stakeholders may register to testify on HB 505 by creating a “My MGA” account. The House Economic Matters YouTube channel will livestream the hearings.

House Environment and Transportation Committee to meet Feb. 20, and Feb. 26 to consider EV and Building Performance Standard Bills

The Maryland House of Representatives’ Environment and Transportation (E&T) Committee scheduled hearings on February 20, and February 26, 2025, at 1:00 pm in Room 250 of the House Office Building to consider energy related bills. The agenda and bill text are now available. The E&T Committee is scheduled to hear the following bills:

HB 897 Maryland Department of Transportation – Electric Vehicle Charging Infrastructure Expansion – Plans and Programs. If enacted, this bill would require the Maryland Department of Transportation (MDOT), in collaboration with the Maryland Energy Administration (MEA), to estimate the number of EVs to achieve the State’s greenhouse gas (GHG) emission goals under § 2–1205(C)(2). We note the State is required to reduce GHG 60% from 2006 levels by 2031 and net zero GHG emissions by 2045. The bill also requires MDOT and MEA to assess the number and density of EV charging stations needed to support the level of EV adoption required to meet the State’s GHG goals. Additionally, they must implement programs to ensure the necessary charging infrastructure is in place. If enacted, this bill would take effect on October 1, 2025.

HB 212 Maryland Building Performance Standards – Fossil Fuel Use and Electric-Ready Standards. As discussed in PJM Flash 52-4, on January 23, 2025, the House Economic Matters Committee scheduled a hearing to consider HB 212, but it was removed from the agenda. If enacted, this bill would require newly constructed buildings in the State to meet all energy demand without the use of fossil fuels. Buildings under seven stories are required to meet the new energy standards by October 1, 2027, and newly constructed buildings over seven stories are required to meet the new energy standards by October 1, 2031. We note that this bill was introduced in the 2024 Regular Session as HB 210, but did not have any action taken after its one hearing. If enacted, this bill would take effect on October 1, 2025.

Stakeholders may register to testify by creating a “My MGA” account. The House Environment and Transportation Committee YouTube channel will livestream the hearing.

House Economic Matters to meet Feb. 20 and Mar. 6 to consider several energy bills related to eligible RPS sources, data centers, DG siting and solar studies

The Maryland House of Representatives Economic Matters Committee (EMC) scheduled hearings on February 20, and March 6, 2025, at 1:00 pm in Room 230 of the House Office Building to consider several energy related bills. The agenda and bill text are now available. The EMC is scheduled to hear the following bills:

February 20 hearing:

HB 220 Renewable Energy Portfolio Standard – Eligible Sources – Alterations (Reclaim Renewable Energy Act of 2025). HB 220 is cross-filed in the Senate as SB 10. As discussed in PJM Flash 52-4, on January 23, 2025, the EMC scheduled a hearing to consider HB 220, but it was removed from the agenda. If enacted, this bill would eliminate waste-to-energy and refuse derived fuel as RPS eligible resources, however poultry litter-to-energy and thermal energy from a biomass system would remain as eligible RPS resources. We note that this bill is cross-filed with SB0010 and sponsored by the Senate President. This bill was introduced in the 2024 Regular Session as HB166. If enacted, HB 220 would take effect October 1, 2025.

HB 900 Electricity – Data Centers – Rate Schedule and Requirements. If enacted, this bill would require electric distribution companies (EDCs) and data center facilities (DCFs) with a peak load requirement exceeding 2,500 MW to enter a contract of at least 20 years that requires DCFs to purchase its peak load requirements on a monthly basis for the duration of the contract. Prior to contract execution the EDCs are required to conduct a load study paid for by the DCF. The contract must include the following provisions

An early termination exit fee equal to 120 months of service
Minimum monthly distribution and transmission billing not less than 90% of contract load
DCF collateral equal to 50% of the minimum charges for the entire contract term
Requires the DCF to reimburse the EDC 100% of the buildout cost is the DCF cancels or delays the project for more than 12 months

The Bill also requires EDCs to develop a rate schedule for DCF customers for approval by the Maryland Public Service Commission (PSC). If enacted, HB 900 would take effect July 1, 2025.

The EMC will hold its subsequent hearing on March 6, the agenda for which can be found here, on the following bills:

HB 827 Solar Energy – Distributed Generation Certificate of Public Convenience and Necessity, Ground-Mounted Solar, and Small Solar Siting Workgroup. HB 827 is cross-filed in the Senate as SB 983. If enacted, this bill would establish a process to grant a Distributed Generation Certificate of Public Convenience and Necessity (DGCPCN) to construct a community solar generating system with a capacity between 2 MW_AC and 5 MW_AC, not located in a municipal corporation.

The bill would require the Power Plant Research Program (PPRP) within the Maryland Department of Natural Resources (DNR) to develop standard licensing conditions and siting and design requirements for a generating facility required to apply and receive a DGCPCN. The PSC would be required to adopt regulations to implement the PPRP standards.

We note this bill was introduced in the 2024 Regular Session as HB1046, but did not have any action taken after its first hearing. If enacted, HB 827 would take effect July 1, 2025.

DGCPCN applicants would be required to submit a copy of the application to PPRP and the county in which the proposed facility is and PPRP would be required to issue a determination if the application satisfies the DGCPCN standards adopted by the PSC within 90 days. The PSC is required to schedule a public hearing to consider the application within 60 days after the PPRP determination is issued.

We note this bill was introduced in the 2024 Regular Session as HB1046, but did not have any action taken after its first hearing. If enacted, HB 827 would take effect July 1, 2025.

HB 904 Department of Planning – Study on Solar Energy Project Sites. EMC scheduled a meeting to consider HB 904 on March 6, 2025. If enacted this bill would require the Maryland Department of Planning (MDP) and the Maryland Energy Administration (MEA) to identify Maryland Department of Public Safety and Correctional Services (MDPSCS) property suitable for new solar energy generation projects and submit a report to the Governor and General Assembly by October 1,2027. If enacted, HB 904 would take effect on October 1, 2025.

Stakeholders may register to testify by creating a “My MGA” account. The House Economic Matters YouTube channel will livestream the hearings.

Senate Education, Energy, and the Environment Committee to meet Feb. 13, Feb. 18, Feb. 20, and Feb. 27 to consider bills related to RPS alterations, EV regulation, OSW installation requirements, and building energy performance standards

The Maryland Senate Education, Energy, and the Environment (EEE) Committee scheduled hearings on February 13, February 18, February 20, and February 27, 2025, at 1:00 pm in Room 2 of the West Miller Senate Building to consider r=bills related to renewable energy. The agenda and bill text are now available. The EEE Committee is scheduled to hear the following bills on the dates indicated below:

February 13 Hearing:

SB 10 Renewable Energy Portfolio Standard – Eligible Sources – Alterations (Reclaim Renewable Energy Act of 2025). SB 10 is cross-filed in the House as HB 220. If enacted, this bill would eliminate waste-to-energy and refuse derived fuel as renewable portfolio standard (RPS) eligible resources, however poultry litter-to-energy and thermal energy from a biomass system would remain as eligible RPS resources. We note that this bill is sponsored by the Senate President. This bill was introduced in the 2024 Regular Session as SB 146. If enacted, this bill would take effect October 1, 2025.

SB 37 Electric Companies – Regional Transmission Organizations – Report (Utility Transparency and Accountability Act). SB 37 is cross-filed as HB 121. If enacted, this bill would require an electric distribution company (EDC) and any affiliate of an EDC, excluding municipal electric utilities, to submit an annual report to the Maryland Public Service Commission (PSC) detailing votes cast at PJM Interconnection, LLC (PJM) meetings. We note that this bill was introduced in the 2024 Regular Session as SB 682, passed the Senate and was referred to the House Economic Matters Committee where there was no action taken. If enacted, this bill would take effect on October 1, 2025.

SB 116 Data Center Impact Analysis and Report. SB 116 is cross-filed as HB 270. If enacted, this bill would require state agencies to conduct an analysis and report on data center development impacts in the State including.

Impacts on air and water quality
Impacts on the ability to meet bay restoration, energy and environmental goals
Technologies to mitigate environmental impacts
Energy requirements
Impact on current electricity forecasted demand and supply
Economic and fiscal impacts

The Department of Legislative Services would be required to file the report on or before September 1, 2026. If enacted, this bill would take effect on July 1, 2025.

SB 149 Responding to Emergency Needs From Extreme Weather (RENEW) Act of 2025. SB 149 is cross-filed as HB 128. If enacted, this bill would establish the Climate Change Adaptation and Mitigation (CCAM) Program and CCAM Fund administered by the Maryland Department of the Environment (MDE). The CCAM program would require payments from fossil fuel businesses based on the amount of greenhouse gas (GHG) emissions released between March 1994 and December of 2023 and the assessed cost to the State from those GHG emissions as determined by the State Treasurer. CCAM funds would pay for or incent CCAM infrastructure projects, including the installation of heat pumps and clean energy infrastructure. We note that this bill was introduced in the 2024 Regular Session as SB 958, but did not have any action taken after its one hearing . If enacted, this bill would take effect on October 1, 2025.

SB 256 Environment – Building Energy Performance Standards – Compliance and Reporting. SB 256 is cross-filed as HB 49. If enacted, this bill would establish an alternative compliance fee for building owners who fail to meet energy use intensity targets under the Building Energy Performance Standards (BEPS) Program, pursuant to the Climate Solutions Now Act of 2022. The Maryland Department of the Environment (MDE) must deposit alternative compliance fees into the Strategic Energy Investment Fund (SEIF), which the Maryland Energy Administration (MEA) administers. SEIF funds programs that decrease energy demand and increase energy supply to promote affordable, reliable, and clean energy. The bill also establishes an annual filing fee to cover the administrative costs of MDE for administering the BEPS Program. The Climate Solutions Now Act requires building owners to report to MDE emissions and energy data on an annual basis. We note that the Education, Energy and the Environment Committee Chair sponsored this Departmental bill. If enacted, this bill would take effect on October 1, 2025.

SB 316 Abundant Affordable Clean Energy – Procurement and Development (AACE Act). SB 316 was cross-filed in the Senate as HB 398. This bill, among other things would establish state energy storage programs, zero emission credits, solar incentive programs, offshore wind transmission studies, and a renewable energy procurement program. We summarize the main topics of the bill below. If enacted, this bill would:

Establish a state distribution system connected energy storage goal of 150 MW and requires electric distribution companies (EDCs) to develop and implement plans to procure energy storage capacity (SC) in proportion to the State goal, based on the EDC’s service load. The Maryland Public Service Commission (PSC) would be required to evaluate and approve or approve with modifications EDC storage procurement plans. EDC storage plans would be required to include a combination of EDC owned and third party owned SC with no more than 30% of SC owned by a third party. All storage capacity would be required to be operational by August 1, 2028. The bill also expands the statutory definition of an energy storage device to include thermo-mechanical technology and devices that connect to the transmission system.

Establish Zero Emissions Credits (ZECs), equal to one MWh of electricity produced from a nuclear reactor located in the State, valued at to ($15/MWh-80% * (Gross Receipts-$25/MWh)) and adjusted for inflation. Nuclear facilities can apply for ZEC’s through the Maryland Public Service Commission (PSC) and are prohibited from receiving ZECs during periods that the facility is receiving zero emission nuclear power production tax credits under § 13105 of the Inflation Reduction Act.

Codify a policy requiring the State to engage in multistate, or regionally coordinated transmission planning in support of 8.5 GW of offshore wind (OSW) development. The Maryland Public Service Commission (PSC) would be required to explore coordinated solutions for transmission via the PJM Interconnection LLC (PJM) long-term transmission planning process and an alternative voluntary agreement. The PSC would also be required to conduct cost-benefit analysis on three different scenarios (i) interconnection to PJM on a radial basis, (ii) a coordinated solution, connecting directly to large load centers (iii) a coordinated solution, that does not connect directly to large load centers.

Establish an escrow account (account) for the disposition of alternative compliance payments (ACPs) made by electricity suppliers that fail to comply with the renewable portfolio standard (RPS). The Maryland Energy Administration (MEA) would administer the account and ensure that funds are distributed to electric distribution companies (EDCs) and either refunded or credited to customers based on their electricity consumption. We note that, RPS ACPs are currently deposited in into the Strategic Energy Investment Fund (SEIF), administered by the Maryland Energy Administration (MEA). SEIF funds programs that decrease energy demand and increase energy supply to promote affordable, reliable, and clean energy

Establish two solar incentive programs that the PSC will administer.

Small Solar Incentive Program, required to incentivize the development of at least 3 GW of capacity, from community solar or net metered solar systems, placed in service on or after July 1, 2027, that are less than 5 MW each. The PSC would approve solar generating systems to participate in this program, allowing them to produce SREC-IIs. The PSC would be required to establish an administratively determined SREC II incentive value, fixed for a period of 15 years, every three years and an annual capacity block allocation for (i) BTM Residential (ii) BTM Nonresidential (iii) aggregated net metering (iv) community solar. The PSC would be mandated to develop an application process and begin accepting applications by January 1, 2028
Utility-Scale SREC II Program, required to incentivize development of at least 3 GW of capacity from solar systems larger than 5 MW by 2035. The PSC approves solar generating systems to participate in this program, allowing them to produce SREC-IIs.

Establish a 1,600 MW front of meter transmission energy storage goal and require the PSC to issue an 800 MW procurement on or before January 1, 2026, and a second 800 MW procurement on or before January 1, 2027. Selected projects must participate in the PJM wholesale markets, including the capacity market.

Require the PSC to establish a program to procure SREC-IIs and REC-IIs from small hydroelectric (less than 30 MW) and land-based wind systems located in the State or that “have the ability to address the resource adequacy needs of the State.” Program bids must include a pricing schedule, limited to 30 years, broken out by (i) energy (ii) capacity (iii) ancillary services (iv) environmental attributes. The PSC would also be responsible for establishing an annual EDC SREC-II and REC-II “purchasers obligation” and an escrow account. Purchasers obligations are based on EDC sales data reported by PJM. The bill authorizes EDCs to establish a non-bypassable surcharge paid by all customers to recover SREC-II and REC-II purchase obligation costs from the escrow account. SREC-II and REC-II generators must sell all (i) energy (ii) capacity (iii) ancillary services into the PJM market and deposit all revenue into the escrow account, which is distributed to EDCs and either refunded or credited to customers based on their electricity consumption.

Authorize state agencies to issue competitive sealed bids higher than their designated small procurement delegations in response to legislative requests, especially those with deadlines, and to address climate change and environmental issues promptly. The following State offices would be authorized to act under this provision (i) PSC (ii) Office of Peoples Council (iii) MEA (iv) Maryland Department of the Environment (v) Department of Natural Resources.

Require electricity suppliers that procure renewable energy credits (RECs) for the purpose of complying with the RPS to procure RECs in the following order (i) Offshore Wind (OSW) RECs (ORECs), REC-IIs, SREC-IIs, (ii) certified SRECs, and (iii) RECs other than ORECs, REC-IIs, SREC-IIs, and certified SRECs. We note that certified SRECS are solar RECs generated by a facility that is certified by the PSC.

Require the comptroller to distribute 75% of the franchise tax, and sales and use tax revenues derived from electricity sales to data centers operational on or after January 1, 2026, to the escrow account created for the disposition of alternative compliance payments (ACPs) made by electricity suppliers that fail to comply with the renewable portfolio standard (RPS). We note that escrow account funds are distributed to electric distribution companies (EDCs) and either refunded or credited to customers based on their electricity consumption

If enacted this bill would take effect on June 1, 2025.

SB 332 Task Force to Study the Premature Retirement of Electricity Generation Facilities. If enacted, this bill would establish a Taskforce to study the premature retirement of electricity generation facilities. The bill would specify Taskforce members from specific organizations and identify the Chair of the Maryland Public Service Commission as the Chair of the Taskforce. The Taskforce report would be due to the Governor and the General Assembly on or before January 1, 2026, and must include the following

Assess cost savings for customers from retiring electricity generation facilities.
Evaluate the impact of early retirement of these facilities on reliable energy supply.
Examine environmental impacts, including habitat disruption, wildlife impact, watershed stress, and ecological harm.
Consider nationwide consequences of electricity shortages if a Maryland facility retires early.
Analyze economic challenges faced by electricity generating companies and potential solutions to keep them operating.
Facilitate collaboration among stakeholders like utilities, environmental groups, energy consumers, and industry representatives.
Conduct infrastructure transition analysis to ensure developments meet the needs of electricity generating companies.

Additionally, the Task Force must make recommendations to:

Address challenges and improve decision-making regarding early retirement of facilities.
Provide energy reliability solutions that balance economic considerations with cleaner energy goals.

If enacted, this bill would take effect on July 1, 2025.

February 18 Hearing:

SB 913 Department of Agriculture – Public Electric Vehicle Supply Equipment – Registration, Regulation, and Oversight. SB 913 is cross-filed in the House as HB 1039. If enacted, this bill would require:

The owner of a public EV charging station (EVSE) to register with the Maryland Department of Agriculture (MDA) by January 1, 2026, and display a Certificate of Registration (good for one year) issued by MDA on the EVSE.
The owner of a public EVSE to notify MDA if it is sold, transferred or moves to a new location.
MDA to establish a program to test the weight and measure of public EVSE to ensure they conform to standards established by the National Institute of Standards and Technology Handbook 44.
Maryland Public Service Commission (PSC), in collaboration with MDA to establish public EVSE reporting and reliability standards, including a public EVSE uptime rating of at least 97%.

If enacted, this bill would take effect on July 1, 2025.

February 20 hearing:

SB 753 Offshore Wind Turbines and Accessory Installations – Aircraft Detection Lighting Systems. If enacted, this bill would require the installation of FAA-approved aircraft detection lighting systems on offshore wind turbines, offshore wind accessory installations, and offshore wind transmission projects. If enacted, this bill would take effect on October 1, 2025.

SB 480 Department of General Services – Clean Energy Procurement Program – Establishment. SB 480 is cross-filed in the House as HB 1417. If enacted, this bill would require the Maryland Department of General Services (DGS) to establish a Green Purchasing Committee and collaborate with the University of Maryland (UMD), and the Maryland Clean Energy Center (MCEC) to procure biogas for the State-owned fleet and buildings. The Bill would also require UMD to complete a (i) carbon lifecycle analysis, and (ii) analyze the environmental and cost benefits of biogas. If enacted, this bill would take effect on October 1, 2025.

February 27 hearing:

SB 479 Building Energy Performance Standards – Public Safety, Emergency, and Public Utility Buildings – Exclusion. SB 479 is cross-filed in the House as HB 1414. If enacted, this bill would exempt federal, state and local government public buildings designed for the purpose of (i) public safety, (ii) emergency shelters, and (iii) public utility buildings from the definition of “Covered Buildings” under the State’s Building Energy Performance Standard (BEPS) program, pursuant to the Climate Solutions Now Act of 2022, which requires that qualifying buildings achieve a 20% reduction in net direct greenhouse gas (GHG) emissions by January 1, 2030 (relative to 2025 levels) and achieve net-zero direct GHG emissions by January 1, 2040. If enacted, this bill would take effect on October 1, 2025.

Stakeholders may register to testify by creating a “My MGA” account. The Senate Education, Energy and the Environment Committee YouTube channel will livestream the hearing.

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Pennsylvania

Gov. Shapiro releases budget proposal, plans to expand tax credits, create statewide electric facility siting board, move forward PRESS and PACER

On February 4, 2025, Pennsylvania Governor Josh Shapiro (D) gave his 2025-2026 Budget Address to the General Assembly. In his speech, Gov. Shapiro proposed a “Lightning Plan” containing multiple initiatives related to energy development in the State. We provide an overview of the proposed initiatives:

Pennsylvania Reliable Energy Siting and Electric Transition Board (RESET Board)

Gov. Shapiro proposed the establishment of a Pennsylvania Reliable Energy Siting and Electric Transition Board (RESET Board), which would act as a statewide entity in charge of siting energy projects, a change from the current siting process, which occurs primarily at the local levels.

Pennsylvania Economic Development for a Growing Economy (PA EDGE) Program

Gov. Shapiro proposed multiple tax credits related to renewable energy:

Converting the Local Resource Manufacturing Tax Credit Program to a Reliable Energy Investment Tax Credit, with up to $100 million per year per facility for three years, focusing on bringing new, reliable energy sources onto the grid.
Establishing the Regional Clean Hydrogen Tax Credit Program, which would allow up to seven regionally dispersed qualified taxpayers to claim up to $7 million per year.
Create a tax credit of u up to $15 million per year for a taxpayer who makes a $250 million capital investment and creates 400 jobs at a facility that produces sustainable aviation fuel (SAF).

Act 129 Reform:

Gov. Shapiro proposed reforms to Pennsylvania Act 129, the law that provides rebates and incentives for the purchase of new energy efficient appliance purchases. The proposal would update the energy efficiency standards for the first time since 2008.

Pennsylvania Climate Emissions Reduction Act (PACER)

As discussed in PJM Flash 24-0, if implemented, PACER would establish a Pennsylvania-specific cap-and-invest program for power sector greenhouse gas emissions. Any revenue generated through the program would be passed on to ratepayers via electric bill rebates, used to support a year-round Low Income Home Energy Assistance Program (LIHEAP), and invested in clean energy projects in communities that have previously hosted coal, oil, or gas infrastructure. PACER would result in Pennsylvania’s withdrawal from the Regional Greenhouse Gas Initiative (RGGI), in which the Administration of former Governor Tom Wolf (D) had directed Pennsylvania to participate, through regulatory action in November 2021. As discussed in PJM Flash 23-0, on November 1, 2023, the Pennsylvania Commonwealth Court, an appellate level court, blocked Pennsylvania’s participation in RGGI, calling it an “invalid tax.” Gov. Shapiro’s Administration has appealed that decision to the Pennsylvania Supreme Court. Depending on the Pennsylvania Supreme Court’s ruling, Pennsylvania could be forced to withdraw from RGGI regardless of PACER’s implementation.

Pennsylvania Reliable Energy Sustainability Standard (PRESS)

As discussed in PJM Flash 24-0, PRESS would effectively amend Pennsylvania’s Alternative Energy Portfolio Standards (AEPS) to require that Pennsylvania get 50% of its electricity “from a diverse range of energy resources by 2035,” including 35% from renewable energy resources (e.g., solar), 10% from “sustainable sources” like large hydropower and battery storage, and 5% from “ultra-low emission forms of natural gas and other alternative fuels.” The AEPS is currently capped at 8% of Tier 1 resources (solar, wind, hydro, geothermal, biomass, fuel cells) and 10% of Tier 2 resources (waste coal, solid waste, distributed generation systems, etc.) for retail electricity sales, less any quarterly adjustments. PRESS would also add new eligible technologies, including nuclear, “next generation technologies” like nuclear fusion, and “clean forms of natural gas.”

PPL releases average AEC cost from eighth AEC procurement , average Tier 1 AEC price of $36.73

On January 28, 2025, PPL Electric Utilities (PPL) released its Alternative Energy Credit (AEC) Solicitation 8 Results. On January 29, the Pennsylvania Public Utilities Commission (PUC) issued a Letter noting PPL’s announcement. PPL sought 29,200 Solar Photovoltaic AECs, 446,200 Tier 1 AECs, and 584,000 Tier II AECs. The average prices at which PPL acquired the AECs are listed in the table below:

The results from the seventh AEC procurement were discussed in PJM Flash 24-35. From the seventh to the eighth procurement, the PV and Tier 1 AEC prices decreased slightly, while the Tier 2 AEC price increased slightly.

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Virginia

Virginia Legislative Updates: House and Senate pass flurry of energy legislation; all bills not passed from chamber of origin by Feb. 4 dead

As last discussed in PJM Flash 25-5, on January 8, 2025, the Virginia General Assembly began its 2025 Session. Virginia’s legislative session runs through February 22, making it one of the shortest state legislative sessions. Committees which often hear bills relevant to renewable energy meet at the following times:

House of Delegates:

Labor and Commerce: Meets Tuesdays and Thursdays, 30 minutes after the adjournment of the House
Counties, Cities and Towns: Meets Fridays, 9:00am

Senate:

Commerce and Labor: Meets Mondays, 15 mins after the adjournment of the Senate.
Local Government: Meets Mondays, 8:30am.
Agriculture, Conservation, and Natural Resources: Meets Tuesdays, 15 minutes after adjournment of the Senate

Between January 30 and February 12, the Virginia General Assembly acted on several bills related to renewable energy. We note that February 4 was “crossover day” for the Virginia General Assembly, the last day for the Senate and House of Delegates to consider legislation before each chamber sends the bills that it passed to the other. Accordingly, all bills that were not passed by their chamber of origin by February 4 are dead. We summarize recent actions for each bill below, sorted by legislative chamber and bill status.

House Labor and Commerce Committee:

Reported Favorably:

SB 853: Prevailing wage rate; apprenticeship requirements, RPS-eligible source work, penalties: As discussed in PJM Flash 25-5, on January 24, the Senate passed SB 853 in a 20-18 vote, sending the bill to the House. On February 6, the House L&C Committee reported HB 853 by a 11-10 vote, along partisan lines. If enacted, this bill would require utilities and utility contractors to ensure payment at the prevailing wage rate set by the Virginia Department of Labor and Industry for any worker hired to perform construction, maintenance, or repair work for certain RPS-eligible generators. The bill would require each utility to (i) ensure that 15% of the total labor hours of such work is performed by qualified apprentices and (ii) employ at least one qualified apprentice if four or more individuals are employed to perform such work. Noncomplying utilities would be required to make penalty payments to the Commissioner of Labor and Industry.

Dead:

HB 2528: Electric utilities; customer energy choice; customer return to service; subscription cap and queue: On January 30, the L&C Committee voted to table HB 2528 in a 16-6 vote, with members of both parties supporting the motion. If enacted, this bill would have removed certain restrictions on the ability of individual retail electricity customers to purchase electricity matched 100 percent by RECs from any licensed supplier.

House Floor:

Passed the House Floor:

HB2744: Electric utilities; energy efficient upgrades; report: On February 4, the House passed HB 2744 by a 67-31 vote. If enacted, the bill would require Dominion Energy (Dominion) and the Appalachian Power Company (APCo) (together, the utilities) to implement energy efficiency upgrades for low-income households, with the goal of reducing heating-related living costs. By December 31, 2030, the utilities would be required to make reasonable efforts to deliver prescriptive efficiency measures to at least 30% of qualifying households or, for smaller utilities, to 8,400 households, whichever is less. The bill also requires the utilities to submit annual reports regarding the provisions of the bill starting on January 1, 2026. After passing on the House floor, the bill was referred to the Senate Committee on Commerce and Labor.
HB 2635: VA Brownfield & Coal Mine Renewable Energy Grant Fund; increases kilowatt of nameplate capacity: On February 4, the House passed HB 2635 by a unanimous vote. If enacted, HB 2635 would amend the Virginia Brownfield and Coal Mine Renewable Energy Grant Fund and Program to enhance financial incentives for renewable energy development on brownfields and previously coal-mined lands. The bill would increase grant amounts to $500 per kilowatt of nameplate capacity for projects on former coal mining sites and from $100 to $200 per kilowatt for projects on brownfields. The maximum annual allocation for the program would be capped at $35 million, with $20 million reserved for coal mine projects—though unallocated funds could be redirected to brownfield projects. After passing on the House floor, the bill was referred to the Senate Committee on Finance and Appropriations.
SB 1338: Carbon-free energy or clean energy; fusion energy; definitions: On January 27, the Senate passed SB 1338 by a 30-0 vote, sending the bill to the House. On February 11, the House passed SB1338 by a 94-0 vote, sending the bill to the Governor’s desk. If enacted, this bill would add fusion energy, as defined in the bill, to the list of generation sources that qualify as carbon-free energy or clean energy.

Senate Commerce and Labor Committee:

Advanced from Committee

HB 1934 Electric utilities; Generation of electricity from renewable and zero carbon sources: On February 4, the House passed HB 1934 by a 65-33 vote. On February 10, the Senate Commerce and Labor (C&L) Committee reported HB 1934 by a 15-0 vote and rereferred it to Committee on Finance and Appropriations. If enacted, HB 1934 would require that, for RPS standard compliance, if low-income qualifying projects (as defined in existing law) are unavailable, a designated percentage of required projects must instead come from those located on or adjacent to public elementary or secondary schools, provided such projects are available.
HB 2509: Virginia Clean Energy Innovation Board established; report: On February 4, the House passed HB 2509 by a 52-46 vote. On February 10, the Senate C&L Committee rereported the bill favorably, by a 9-6 vote, and referred it to the Senate Committee on Finance and Appropriations. If enacted, HB 2509 would establish the Virginia Clean Energy Innovation Bank, a division within the State’s Department of Energy, to accelerate the deployment of clean energy projects through strategic financial mechanisms. The Bank would administer the Virginia Clean Energy Innovation Fund, which would provide grants, loans, credit enhancements, and other financing tools to support projects that reduce greenhouse gas emissions, promote renewable energy, improve energy efficiency, expand energy storage, and foster electrification and water conservation initiatives. The bill would also mandate the creation of an Advisory Board to guide the Bank’s strategic planning and investment strategies, ensuring transparency and accountability through annual reporting to the Governor and General Assembly.
HB 2136: Office of the Public Utility Ombudsman: On February 4, the House passed HB 2136 by 56-43 vote. On February 10, Senate C&L Committee rereported the bill favorably by a 9-6 vote, and referred it to the Senate Committee on Finance and Appropriations. If enacted, HB 2136 would establish the Office of the Public Utility Ombudsman within the Virginia State Corporation Commission (SCC) to advocate for and protect the interests of residential customers of public utilities, including those served by non-jurisdictional or limited jurisdiction utilities. The Ombudsman’s responsibilities would include receiving and resolving complaints, assisting customers in understanding their rights and responsibilities, and providing support to those facing service disruptions due to the dissolution of utility or enforcement actions by the SCC. The Office would also maintain data on inquiries and complaint resolutions, ensure accessibility to its services, and guarantee timely responses to customer concerns.
HB2113 Solar Interconnection Grant Fund and Program: On February 4, the House passed HB 2113 by a 68-30 vote. On February 10, the Senate C&L Committee rereported the bill favorably by a 14-0 vote and referred it to the Senate Committee on Finance and Appropriations. If enacted, HB 2113 would establish the Solar Interconnection Grant Fund and Program for the purpose of awarding grants on a competitive basis to public bodies to offset costs associated with the interconnection of solar facilities. The Program would be administered by the Division of Renewable Energy and Energy Efficiency (REEE) within the Virginia Department of Energy (VA DOE). The bill would require that priority be given to solar facilities located on previously developed project sites and would require the REEE to establish and publish guidelines and criteria for the awarding of grants and general requirements of the Program.
HB2537 Energy storage requirements; Department of Energy, et al., to develop model ordinances and reports: On February 4, the House passed HB 2537 by a 54-44 vote. On February 10, the Senate C&L Committee rereported the bill favorably by a 9-6 vote and referred it to the Senate Committee on Finance and Appropriations. If enacted, HB 2537 would increase the targets for energy storage capacity that APCo and Dominion are required to construct, acquire, or procure and extend the time frame by which such capacity must be met. Under the bill, APCo would be required to petition the SCC for approval to construct, acquire, or procure at least 780 MW of short-duration energy storage capacity by 2040 and 520 MW of long-duration energy storage capacity by 2045, while Dominion would be required to construct, acquire, or procure at least 5,220 MW of short-duration energy storage capacity and 3,480 MW of long-duration energy storage capacity by 2045. The bill would also direct the VA DOE and the Department of Environmental Quality (DEQ) to develop model ordinances for energy storage projects and convene a work group to submit recommendations by December 1, 2025. Additionally, the SCC would be required to initiate a proceeding to assess the viability of long-duration energy storage technology, with a final order due by March 1, 2030.
HB1791 Electric Vehicle Rural Infrastructure Program and Fund created: On February 4, the House passed HB 1791 by a 56-41 vote. On February 10, the Senate C&L Committee rereported the bill favorably by a 9-5 vote and referred it to the Senate Committee on Finance and Appropriations. If enacted, the bill would create the EV Rural Infrastructure Program and Fund to support private developers with non-utility costs for installing public electric vehicle charging stations in (i) “distressed localities,” (ii) “on eligible public lands”, or (iii) “within one mile of boundary of eligible public land” in Virginia. The bill would allow grants covering up to 70% of non-utility costs, with at least 70% of the funds directed toward projects in distressed localities. The program would be administered by VA DOE, which would establish guidelines for grant applications, including requirements for uptime standards, maintenance plans for at least five years, and preferences for projects near public amenities. Additionally, the bill would create the EV Rural Infrastructure Fund to finance these grants, with the program set to expire on July 1, 2030. The C&L Committee recommended amending the bill to replace the term “Distressed locality” with “Rural and underserved locality”. A “Rural and underserved locality” refers to a county with a population density under 160 people per square mile or an independent city with higher-than-average unemployment and poverty rates.

Dead:

SB 1077 Electric utilities; regulation, development of renewable energy facilities: On February 3, the Senate C&L Committee voted to pass by HB 1077 indefinitely, in a 9-6 vote, with Democrats supporting the motion to pass by. If enacted, the bill would have repealed provisions (i) requiring the State Air Pollution Control Board (APCB) to adopt regulations to reduce carbon dioxide emissions from electricity generating units and authorizing the APCB to establish an auction program for energy allowances; (ii) prohibiting the SCC from approving any new utility-owned generation facilities that emit carbon dioxide as a by-product of energy generation, in certain circumstances; (iii) declaring that statutory allowances for renewable energy are in the public interest; and (iv) relating to the development of solar and wind generation and energy storage capacity, development of offshore wind capacity, and generation of electricity from renewable and zero-carbon sources. The bill would designate planning and development activities for new nuclear generation facilities as “in the public interest.”

Senate floor:

Passed:

SB1316 Renewable energy portfolio standard eligible sources; geothermal resources: On February 4, the Senate passed SB 1316 by a 40-0 vote. If enacted, the bill would amend Virginia’s RPS to include geothermal electric generating resources as eligible sources. The bill defines geothermal electric generating resources and geothermal heating and cooling systems, outlining the criteria for their inclusion in the RPS program. The bill would allow energy generated from these geothermal sources to qualify for RECs, which utilities can use to meet their RPS requirements. Additionally, the bill would set guidelines for verifying the energy output from geothermal systems and integrate these resources into Virginia’s broader renewable energy goals. After passing on the Senate floor, the bill was referred to the House L&C Committee.
SB1047: Demand response programs; Dept. of Energy to evaluate & assess benefits, and recommendations: On February 4, the Senate passed SB 1047 by a 21-17 vote. If enacted, the bill would direct VA DOE, in consultation with the SCC, to evaluate and assess the benefits, impacts, best practices, and implementation recommendations for demand response programs in Virginia. The bill would require assessments to examine the existing utilization of demand response programs, current and projected participation rates, and potential program criteria to meet regional reliability standards, decrease energy consumption during grid emergencies, minimize local air pollution from fossil fuel use, and ensure cost-effectiveness. The bill would also stipulate that the VA DOE submit its findings to the Senate Committee on Commerce and Labor and the House Committee on Labor and Commerce by November 1, 2025. After passing on the Senate floor, the bill was referred to the House L&C Committee.
SB1058: Phase I and II Utilities; SCC shall establish a distribution cost sharing program: On February 4, the Senate passed SB 1058 by a 21-18 vote. If enacted, SB 1058 would direct SCC to establish a distribution cost-sharing program for Dominion and APCo to fund distribution system upgrades required for interconnecting participating projects (any solar facility with an AC nameplate rating between 50 kW and 2 MW) by July 1, 2026. The bill would further require the SCC to ensure that each utility files any necessary tariffs, agreements, or forms for program implementation by December 1, 2026. After passing on the Senate floor, the bill was referred to the House L&C Committee.
SB1192 Electric utilities; generation of electricity from renewable and zero carbon sources: On February 4, the Senate passed SB1192 by a 40-0 vote. SB 1934 is the Senate companion bill to HB1934 (described above). The bill would require that, for RPS standard compliance, if low-income qualifying projects (as defined in existing law) are unavailable, a designated percentage of required projects must instead come from those located on or adjacent to public elementary or secondary schools, provided such projects are available. After passing the Senate, the bill was referred to the House L&C Committee.
SB960: Electric utilities; data center cost allocation: On February 4, the Senate passed SB960 in a 26-13 vote. If enacted, SB960 would direct the SCC to initiate proceedings to determine if the current allocation of costs among different customer classifications of electric utilities requires non-data center customers to unreasonably subsidize the costs of data centers. If the SCC determines that the current allocation of costs results in unreasonable subsidies, the SCC would be directed to promulgate such rules as necessary to eliminate or minimize such unreasonable subsidies to the maximum possible extent by January 1, 2026. After passing the Senate, the bill was referred to House L&C Committee.
SB893 Renewable energy portfolio standard program; geothermal heating and cooling systems, report: On February 4, the Senate passed SB893 by a 21-19 vote. If enacted, this bill would require Dominion and APCo to procure and retire certain percentages of RECs from geothermal heating and cooling systems, beginning with the 2026 RPS compliance year and thereafter. The bill would amend the method by which RECs from geothermal heating and cooling systems are calculated and direct the Commission on Electric Utility Regulation (CEUR) to prepare and deliver a report evaluating the procurement and retirement of RECs from geothermal heating and cooling systems, by November 1, 2027. The bill would also direct the Real Estate Appraiser Board to promulgate regulations requiring the development of a continuing education curriculum and required training for all licensees that includes how to properly determine the increase in value of real estate created by reductions in building energy costs associated with solar, geothermal, and solar water heating investments. After passing the Senate, SB893 was referred to the House L&C Committee.

Dead:

SB899: High electric demand facility; locality may include in its zoning ordinance water use estimate: On January 30, the Senate voted to reject SB 899 by a vote of 13-26. If enacted, HB 899 would have authorized a locality to include in its zoning ordinance provisions for (i) requiring proposed data center developments to submit water use estimates and (ii) considering water use when making rezoning and special use permit decisions related to data center development.
SB1190: Energy Facility Review Board & Virginia Clean Energy Technical Assistance Center; established: On February 3, the Senate voted to reject SB 1190 by a vote of 19-20. Subsequently, the Senate passed by SB 1190 on February 3, 4, and 6. Having not passed by the Senate on February 6, the bill failed. We note that this bill originated as the solar siting concept published by the Virginia CEUR, discussed in PJM Flash 24-49. If enacted, SB 1190 would have established the Virginia Energy Facility Review Board as a political subdivision for the purposes of conducting critical interconnection reviews, conducting analysis and study policy options, reviewing regional energy plans, local comprehensive plans, and local solar and storage ordinances and to facilitate the responsible siting of critical interconnection projects in Virginia. The bill would have also established the Virginia Clean Energy Technical Assistance Center, consisting of public institutions of higher education, to serve as an interdisciplinary study, research, and information resource and to provide technical assistance to state agencies, planning district commissions, localities, the Review Board, other public bodies, and private entities in matters related to critical interconnection projects.

Hearing Examiner recommends approval of 500 kV Fentress-Yadkin Transmission Line

On January 30, 2025, in Case No. PUR-2024-00105, Viriginia State Corporation Commission (SCC) Hearing Examiner Staff issued a Report (Examiner Report) recommending that the SCC approve the Application for Approval and Certification of Electric Transmission Facilities submitted by Virginia Electric and Power Company dba Dominion Energy Virginia (Dominion) for the Yadkin-Fentress Electric Transmission Line Project (discussed in PJM Flash 24-25). The Yadkin-Fentress transmission project would consist of the removal of an existing 500 kV line that is approaching the end of its service life and the construction of two new 500 kV transmission lines within the same right of way. The new lines would be built on monopole structures (instead of the lattice structure of the existing line).

The Examiner Report’s recommendations are summarized below by topic:

Need/Economic Development/Cost

The Examiner Reports noted that the project is needed to replace aging infrastructure, support transmission system reliability, and alleviate constraints on energy delivery from the Coastal Virginia Offshore Wind (CVOW) project. Demand-side management programs will not eliminate this need and thus the Staff recommends approving the project. Given the “need” for the project, the Examiner Report also found that the cost of $202.2 million is reasonable.

Right of Way

Examiner Report recommended that SCC approve the proposed route as it effectively uses existing Right of Way (ROW), minimizing impacts on the environment and residential properties. The Examiner found that the project design also accommodates easement constraints on a section of the transmission line by proposing alternate construction plans that maintain the easement restrictions. in specific areas. The Examiner further recommended that the project be allowed to continue negotiations with landowners throughout 2025 without needing to change its in-service date.

Environmental, Scenic, Historic, and Other Impacts

The Examiner Report found that the project minimizes adverse impacts on scenic, historic, and environmental resources and that any potential impacts on wetlands, species, and cultural sites were assessed, with mitigation strategies in place. Thus, the Examiner recommended that SCC approve the Certificate application provided that Dominion:

Obtains all necessary environmental permits.
Complies with uncontested Virginia Department of Environmental Quality( DEQ) recommendations.
Coordinates with relevant agencies (e.g., Department of Historic Resources( DHR) for historic sites).

Public Health and Safety

The Examiner Report found that the project does not pose any significant risk to public health and safety, and thus should be approved by SCC.

Environmental Justice

The Examiner Report found that the project does not disproportionately impact environmental justice communities and Dominion engaged with affected populations appropriately, and, thus, does not recommend any additional measures in this regard.

Flexibility for Constraint Design Segment

As noted earlier, the Examiner Report clarifies that the Examiner supports Dominion’s request for flexibility in negotiating with landowners through 2025 and would allow it if does not impact the project’s in-service date.

Recommendations Not Supported

The Examiner recommended not enforcing certain DEQ recommendations due to redundancy or unnecessary constraints, including:

Seasonal restrictions for tree clearing to protect songbirds and rattlesnakes.
Invasive species management plans (covered by existing protocols).
Additional evaluations of closed petroleum sites.

Virginia DEQ approves permit-by-rule for 91 MW Carver Solar facility

As discussed in PJM Special Flash 24-48.1, on November 22, 2024, Carver Solar I, LLC, filed an Application (RE0000305) for a Permit-By-Rule (PBR) seeking a permit to construct a proposed solar facility in Isle of Wight County, VA. In Virginia, a PBR is an alternative to a siting certificate and is available for qualifying projects with a capacity of less than 150 MW. Carver Solar I is a proposed 91 MW_AC solar facility being developed by Hanwha QCells.

On January 31, 2025, the Department of Environmental Quality (DEQ) issued an Order granting a PBR to Carver Solar. A full list of small renewable energy PBR projects is available for download here.

Other Virginia News of Note

Dominion files quarterly report on CVOW construction progress, announces 9% increase in project budget: On February 3, 2025, in Virginia State Corporation Commission (SCC) Case No. PUR-2024-00206, Dominion Energy (Dominion) submitted its Quarterly Progress Report for its Coastal Virginia Offshore Wind (CVOW) project. According to the Progress Report, CVOW is approximately 50% complete and Dominion still expects to complete the project by the end of 2026. Dominion has increased CVOW’s budget from $9.8 billion to $10.7 billion. Dominion attributes the budget increase to higher onshore interconnection costs and network upgrade costs. Approximately $700 million of the budget increase can be recovered from Dominion’s customers, translating to a $0.43 increase to the average customer’s monthly bill over the Project’s lifetime.

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Ohio

House Energy Committee hears sponsor’s testimony on bill to repeal parts of HB6, bars utilities from owning generation, and reinstates energy efficiency

On February 5, 2025, the Ohio House Energy Committee held a hearing at which it heard testimony from the sponsor of HB 15 – Amend competitive retail electric service law, Rep. Roy Klopfenstein (R). We note this bill is over 100 pages long, and a comprehensive analysis is provided by the Ohio Legislative Service Commission here.

As last discussed in PJM Special Flash 25-4.2, if enacted, this bill would:

Bar Ohio electric distribution utilities (EDUs) from owning or operating electric generation facilities.
Reinstate the requirement that utilities must implement energy efficiency programs for residential and commercial customers
Remove subsidies for the Ohio Valley Electric Corporation coal plants and the Davis-Besse and Perry nuclear plants, and eliminate the Ohio Air Quality Development Authority solar program.
Remove language that complicated municipal renewable aggregation programs
Restore annual renewable energy compliance review
Remove language from HB 6 that created loopholes for annual REC compliance
Prevent electric distribution utilities from using energy storage in wholesale markets
Enact several requirements for retail electric suppliers, such as customer disclosure requirements, and raise the bond requirements for retail suppliers to $250,000, or 10% of gross receipts, whichever is greater, and order the Public Utilities Commission of Ohio (PUCO) to create regulations, and the EDUs to offer, consolidated billing.
Prohibit utilities from offering any Competitive Retail Electric Service (CRES) other than its standard service offer (SSO)
Repeal the Electric Security Plan (ESP) enabling statute ( in various parts of R.S. 4928) and specifies that the standard service offer from EDUs must be a market-rate offer
Specify that the replacement of a major energy facilities with another like facility also requires review by the Ohio Siting Board
Exempts electric generation equipment from local property taxes, and increases the personal property tax assessment rate on transmission and distribution infrastructure from 85% to 89%.

Rep. Roy Klopfenstein (R), the vice-Chair of the House Energy Committee, introduced the bill as aligned with the priorities of House Energy Committee Chair Adam Holmes (R) to ensure a reliable, low-cost electric system. Rep. Klopfenstein argued that revisions to the energy policy of the State are necessary to meet the growing load in the State and the region, largely due to data centers. The Chair of the PUCO, Jenifer French, also spoke at the hearing, and provided an overview of the PUCO’s role in the State and explained that reliability and affordability are important concerns for the PUCO, and the PUCO is concerned with the retirement of dispatchable baseload generation in PJM.

During the hearing, Chair Holmes noted that the Committee would invite stakeholders with expertise to testify at a later date.

PUCO seeking comments on proposed revision to interconnection standards, due Mar. 7 and Mar. 28

On February 5, 2025, in Case 24-1039-EL-ORD, the Public Utilities Commission of Ohio (PUCO) issued an Order requesting comments regarding Ohio’s electric interconnection services and standards. Comments are due by March 7, 2025, and reply comments are due by March 28, 2025.

As last discussed in PJM Flash 24-25, on November 6, 2024, PUCO initiated a proceeding, in Case 24-1039-EL-ORD, to review and potentially revise Ohio Administrative Code Chapter 4901:1-22, which governs interconnection standards for electric services in the State. In an Entry Order, PUCO explained that in a December 2021, Finding and Order (in Case 18-884-EL-ORD), PUCO amended interconnection standards for electric services, reflecting stakeholder input in that proceeding. As part of this update, the PUCO established a Distributed Energy Resource (DER) Stakeholder Group to further discuss and develop potential rule changes.

AEP files notice of start of construction on transmission tie-in projects for Pleasant Prairie Solar facility

On January 30, 2025, in Ohio Public Utilities Commission (PUCO) Docket No. 25-0030-EL-BNR, American Electric Power Ohio (AEP) filed a Notice informing PUCO that construction had begun on the transmission tie-in project for the Pleasant Prairie Solar facility. The tie-in project entails a 345 kV, 0.1-mile transmission line that will tie into an existing AEP 345 kV transmission line.

The Pleasant Prairie Solar project (the project) is a 250 MW_AC solar facility being developed by Invenergy in Franklin County, OH. The project first submitted an application in Docket No. 20-1679-EL-BGN in February 2021 seeking a Certificate of Environmental Compliance and Public Need. In October 2022 a Stipulation and Recommendation was filed by the project signed by PUCO Staff, and local townships which recommended PUCO approve the project. PUCO issued an Order in October 2022 approving the Stipulation and granting the project a CECPN. According to the project website, construction was planned to start in 2022 and was expected to be completed in 2023. However, the Notice does not report an expected completion date for the project, and no notice of construction start has been filed in the Docket.

Other Ohio News of Note

Construction starts on Border Basin solar tie-in projects: As last discussed in PJM Flash 24-49, on September 3, 2024 in Public Utilities Commission of Ohio (PUCO) Case 24-0706-EL-BNR and Case 24-0707-EL-BLN, AEP Ohio Transmission Company, Inc. (AEP) filed Applications seeking a Certificate of Environmental Compatibility and Public Need (CECPN) for construction of a transmission line and substation to support the 120 MW Border Basin solar project. On January 29, 2025, in Case 24-0706-EL-BNR, AEP filed a Notification of Start of Construction informing PUCO that construction on the Ebersol-Fostoria Central #2 138 kV Cut-In and Rocky Ford-Border Basin 138 kV Tie Line and Rocky Ford 138kV Station projects would begin on February 3.

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Illinois

IPA releases Indexed REC RFP schedule; Public workshop Apr. 30, Bids due Aug. 1

On February 5, 2025, the Illinois Power Agency (IPA) released the Schedule for its Summer 2025 Indexed REC RFP. As discussed in PJM Flash 24-18, in accordance with its 2024 Final Long-Term Renewable Resources Procurement Plan, the IPA is seeking to procure up to 2,700,000 RECs from wind projects over 5 MW and hydropower projects, 666,666 RECs from solar projects over 5 MW, and 74,000 RECs from solar projects on brownfields. The IPA noted that these category-specific targets are subject to change. The IPA plans to issue the RFP on May 28, with complete bids due August 1.

The planned solicitation schedule is shown in the table below:

Stakeholders comment in first REAP workshop, suggest addressing reliability issues in next report

As discussed in PJM Flash 24-24, on May 30, 2024, in Docket 22-0749, the Illinois Commerce Commission (ICC) issued a Final Order approving with modifications ICC Staff’s March 5, 2024, Proposed Order to develop a Renewable Energy Access Plan (REAP)(see website). Pursuant to 220 ILCS 5/8-512, the ICC created a REAP to establish renewable energy access plan zones, create a plan to build the requisite transmission to deliver renewable energy from these zones, encourage renewable energy development, consider proposals to improve regional and interregional transmission planning, and make policy recommendations based on that analysis to help the State reach 100% clean energy by 2050 as required by Climate and Equitable Jobs Act (CEJA). Every other year, beginning in 2025, the ICC must evaluate the effectiveness of the REAP and consider potential improvements.

On January 31, 2025, the ICC held its first REAP workshop and released the slide deck presentation from the workshop. Prior to the workshop, the ICC requested comments on the future direction for the next REAP. The following stakeholders submitted comments:

Clean Grid (CGA)
The Coalition to Request Equitable Allocation of Costs Together and Electricity Consumers Resource Council (REACT/ELCON)
Commonwealth Edison Company (Com Ed)
Illinois Farm Bureau (IFB)
LS Power
Magellan Wind
NRG Companies (NRG)
Quantum Energy

We summarize the comments below.

REAP Zones: CGA supported REAP zones that include consideration of energy storage systems; it argued that these resources can support increases in the size and dispatchable capacity of renewable resources, as well as maximize the use of existing transmission resources. CGA also supported consideration of proximity and other location-based variables to refine future REAP zones.

Interaction with other Illinois Requirements: CGA recommended that the REAP consider the Illinois RPS and the application of CEJA’s emissions limits to power generation assets. LS Power suggested the REAP working group collaborate with other ICC groups to fulfill the goals of the CEJA.

New Issues to Address in REAP: CGA recommended that the ICC consider incorporating at least two new analyses in the REAP (i) an analysis of the interconnection queues for both grid- and distributed-scale clean energy resources, and (ii) an analysis of projected load growth within Illinois, Midcontinent Independent System Operator (MISO), and PJM; this was also supported by the IFB. LS Power, NRG, and REACT/ELCON argued that the REAP should address reliability issues. LS Power suggested that the Plan address the “premature closing” of natural gas peaker plants and detail a forward-looking plan for electric transmission infrastructure. NRG suggested the working group address the possible reform of the self-direct RPS program, analyze rate design and time-of-use default rates, expand the definition of “brownfields” for Illinois Power Agency (IPA) procurements, and advance EV adoption and infrastructure. REACT/ELCON also supported the prioritization of evaluating transmission options.

Land Use: The IFB stated that managing land use should be a priority in future REAPs, asserting that it directly impacts agricultural production and creates concern for farmers. The IFB also suggested that the working group discuss a model ordinance for renewable energy development.

Tracking Progress: CGA and ELCON/REACT recommended the REAP include a listing of select metrics that would be reported and assessed in the process, including current and projected emissions, energy mix, and reliability. LS Power suggested the use of a benefit-cost analysis, including modifying the mandated plant closure schedule and the inclusion of non-wires alternatives. LS Power also recommended the development of a scorecard to rank potential pathways to achieve the State’s clean energy goals.

General Comments: Com Ed supported the goals of the REAP, and highlighted the role that stakeholder workshops play in facilitating interested parties’ understanding of the REAP’s scope and limitations. Quantum Energy drew attention to its TotalView Energy Platform, which it asserted can help the ICC develop a long-term transmission strategy. CGA encouraged the ICC to adopt an expansive approach to policy recommendations in the REAP. Magellan Wind argued that the REAP should address the role of offshore wind in Illinois energy policy, and consult with other state agencies on offshore wind.

ComEd issues residential TOU pricing pilot annual evaluation report, notes that both EV and non-EV customers saved money by enrolling in TOU rate program

On January 31, 2025, in Illinois Commerce Commission (ICC) Docket 18-1725, the Commonwealth Edison Company (ComEd) submitted its fourth annual evaluation report on the residential time-of-use (TOU) pilot program.

For context, ComEd deployed its residential TOU Pricing Pilot in June 2020. The stated intent of the four-year pilot was to encourage participants to shift electricity usage to non-peak periods by sending participants pricing signals to encourage reduced usage during the hours with the highest prices and, typically, highest usage. Under this program, ComEd ratepayers could opt into a TOU program with three pricing periods: off-peak (10pm to 6am), peak (6am to 2pm and 7pm to 10 pm), and super peak (2pm to 7pm). The primary objective of the pilot was to investigate if a fixed-price TOU supply offering would encourage customers to use less energy when wholesale real-time energy market prices are highest. ComEd submitted annual reports to the ICC for review; this fourth report, covering the period of October 2023 through May 2024, is ComEd’s final report on this pilot program.

According to the most recent evaluation report, pilot program participants’ demand reduction during the final non-summer Super Peak Period was 0.09kW (8.6%) overall, 0.22 kW (16.3%) for EV owners, and 0.02 kW (2.3%) for non-EV owners (ComEd noted this 2.3% value was not statistically significant). ComEd’s analysis demonstrated that during this fourth pilot phase, all customers saved money by enrolling the TOU program (compared to if they were enrolled in the default fixed-price offering). ComEd also found that, during the most recent evaluation period, customers responded to the pilot rates similarly on weekdays and on weekends during the non-summer season, but the magnitude of off-peak load increases and super peak and evening peak load reductions were smaller during the weekends. Moreover, ComEd noted that pilot customers used more kWh on a daily basis compared to control group customers, even with statistically significant load reductions during the Super Peak Period of the final non-summer season Evaluation Period.

IPA announces large customer self-direct RPS application window opens, applications due March 14

As discussed in PJM Flash 25-3, on October 31, 2024, the Illinois Power Agency (IPA) began collecting cost data on projects being developed in 2025 to improve REC price modeling for the Illinois Shines and Illinois Solar for All programs. Various stakeholders submitted comments, which we summarized in PJM Flash 24-51. Most stakeholders argued that data collection requirements were too burdensome.

On December 19, the IPA announced that it had released a response to stakeholder comments. In its response, the IPA specified that it will “only collect aggregated data through annual surveys and will not add required project cost fields to Part II applications for the Illinois Shines and Illinois Solar for All programs.” On January 15, 2025, the IPA released its proposed 2025-2026 RPS Compliance Delivery Year program size, recommending it be set at 4.5 million RECs (1 million RECs from participating projects and 3.5 million RECs from new program applicants).

On January 30, 2025, the IPA announced it has released the Program Application Form for the 2025-2026 Program Year, and officially set the program size at 4.5 million RECs. The IPA anticipates issuing the proposed bill credit rate for stakeholder feedback in mid-February. Program applications will be accepted until March 14 at 5:00 pm CT.

IPA announces some federal SFA funding received; amount unspecified

On February 4, 2025, the Illinois Power Agency (IPA) announced that it has received a portion of the federal funding awarded through the U.S. Environmental Protection Agency (EPA) Solar for All (SFA) program. This funding will expand the Illinois Solar for All (ILSFA) Community Solar sub-program budget for the current 2024-2025 Program Year. The IPA did not announce a specific amount that it received. As discussed in PJM Flash 24-16, in April 2024, the EPA announced a $156,120,000 SFA award for Illinois.

Other Illinois News of Note

Marquis Energy plans carbon capture project, raising concerns about aquifer pollution: According to Capitol News Illinois, Marquis Energy is planning to develop a carbon capture and sequestration project at its ethanol plant near Hennepin, IL. If developed, the carbon capture project would bury carbon emissions from the ethanol plant, allowing increased ethanol production. Opponents raised concerns about potential aquifer pollution and soil disruption from new pipeline construction.
Vistra extends operations of Baldwin coal plant from 2025 to 2027; adds 68 MW utility scale solar and 2 MW storage system: On December 17, 2024, Vistra announced that it will continue operating its 1,185 MW Baldwin coal plant until 2027, extending its previously planned 2025 retirement to address reliability concerns in the Midcontinent Independent System Operator (MISO) market. Vistra also added a 68 MW utility-scale solar facility and a 2 MW/8 MWh energy storage system to the Baldwin site. These projects began generating power in December 2024.

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Michigan

PSC approves with modifications Staff’s proposed framework for utilities’ transportation electrification plan filings

On March 15, 2024, in Case No. U-21492, the Michigan Public Service Commission (MPSC) issued an Order which, among other provisions, directed MPSC Staff to develop and file a proposed transportation electrification plan (TEP) process, to minimally include filling requirements for rate-regulated utilities’ TEPs, expectations for public engagement, and a docket schedule. MPSC Staff filed these materials on July 2. As discussed in PJM Flash 24-33, interested parties subsequently filed comments on the proposal.

On January 23, 2025, MPSC issued a press release announcing that it had issued an Order approving, with modifications, Staff’s proposed process. The MPSC also addressed specific suggestions and concerns raised by stakeholders in their comments, including:

Softening a requirement that TEPs must include benefit-cost analyses (BCAs) to allow utilities to submit either BCAs or scenario planning analyses; the MPSC noted that it is in the process of developing an open-source BCA tool, which it expects to complete in 2026, and that it may subsequently revise this provision
Adopting a recommendation that “strategy to optimize [EV] charging load” should be listed as an objective of the TEPs
Striking a requirement that TEPs must include information on “how the rate regulated electric utility plans to equitably expand EV adoption,” noting that this “may be outside the purview of a rate-regulated utility;” though a provision that utilities must list “any programs currently in place to assist equitable adoption of EV charging infrastructure” remains

The Order also notes several comments from MPSC Staff in response to stakeholders’ comments on the topic of rates. Staff opined that rates (i) should be evaluated in contested cases, (ii) should be based on “costs to serve,” and (iii) are not designed with the intent to alter customer’s behavior or energy load (though if a rate does ultimately influence customer behavior, that is a “reasonable outcome”). Staff also contended that time-of-use rates have “lessened the need for rates based on end use” (i.e., those that are technology-specific, such as dedicated heat pump rates).

On January 24, 2025, Staff submitted their Amended Filing Requirements reflecting the modifications outlined in the Order. Unless otherwise directed by the MPSC, utilities must file updated TEPs every other year.

PSC finalizes LSEs’ respective shares of statewide energy storage target, adopts methodology consistent with Staff Straw Proposal

As last discussed in PJM Flash 24-32, Section 101 of Public Act 235 of 2023 (PA 235 of 2023) established a statewide energy storage target of 2,500 MW_AC by 2030. On May 1, 2024, in Case U-21571, Michigan Public Service Commission (MPSC) Staff filed a Statewide Energy Storage Target Calculation Staff Straw Proposal (Straw Proposal) outlining the proposed methodology to calculate utilities’ and alternative electric suppliers’ (i.e., load-serving entities or LSEs) proportional shares of the statewide energy storage target. On January 23, 2025, the MPSC issued a press release announcing that it had issued an Order approving, with modifications, the calculation methodology outlined in the Straw Proposal.

In the Order, the MPSC established the following calculation, with peak load contribution (PLC) values to be sourced from utilities’ capacity demonstration filings:

푆푡표푟푎푔푒 푇푎푟푔푒푡_LSE represents an LSE’s respective proportional share of the statewide minimum energy storage target.
푆푡표푟푎푔푒 푇푎푟푔푒푡_{푠푡푎푡푒} is the statewide energy storage target (i.e., 2500 MW_AC)
Peak 퐴푣푔_LSEis the average of the utility’s previous five years of annual in-state peak load contributions (based on the utility’s summer peak load).
Peak 퐴mso-margi푔_{푠푡푎푡푒} is the five-year average of the sum of all LSEs summer capacity obligations

Additionally, in the Order, the MPSC:

Determined that the term “capacity obligation” will be used to identify LSEs’ individual contribution to in-state retail electric peak load

As discussed in PJM Flash 24-32, the Straw Proposal instead employed the term “peak load contribution” (PLC), which some stakeholders contended may cause confusion; Energy Michigan noted that the term PLC, as proposed, was “not the same as actual contributions to the Michigan peak” in the context of capacity demonstration.

Established that, while the calculation will be performed annually, once an LSE has filed its storage procurement plan or contract approval request, and its plan has been approved, its compliance target is set, and is subject to future adjustments only under certain circumstances, including a 10% change from the previous annual calculation in the LSE’s five-year average peak
Consistent with the Straw Proposal, established that “eligible storage systems” must be “located within the local resource zone or the locational deliverability area;” stakeholders had been divided on this issue, with some supporting this framework, and others advocating for a more restrictive in-state requirement
In response to a concern raised by ABATE that rate-regulated electric providers could classify their PA 235 of 2023 compliance costs as delivery service costs rather than power supply costs, causing Retail Open Access customers to pay their compliance costs twice; the MPSC noted that it will defer judgment on the classification to a contested case proceeding.

As depicted in the table below, the MPSC provided a sample of the results of this calculation methodology based on data from the years 2020 to 2024. Staff will perform the first actual annual calculation 30 days after the completion of the 2025 capacity demonstration filings.

PSC releases 2025 meeting schedule, next meeting February 27

On January 23, 2025, the Michigan Public Service Commission (MPSC) released its 2025 Meeting Schedule, as shown in the table below.

All meetings, unless otherwise noted, will take place at the MPSC offices at 7109 West Saginaw, Lansing, Michigan, 48917. A livestream and recordings of the meetings can be accessed at the PSC website.

Other Michigan News of Note

Climatologist warns Michigan will miss net-zero goal: According to Michigan Capital Confidential, in his analysis climatologist John R. Christy found that Michigan will not achieve its goal of having net-zero emissions by 2050. Christy asserts that Michigan consumes too much power to rely solely on wind and solar. To meet its goals, Christy asserts Michigan would need to completely switch to EVs and add about 10 times more nuclear power than it currently has.
Michigan PSC Report finds electric choice program remained fully subscribed in 2024: On February 1, 2025, the Michigan Public Service Commission released a report on electric competition. The Report found that every electric provider in Michigan remained at the 10% electric choice participation cap in 2024. However, in 2024, electric choice program participation decreased by 25 customers to 5,514 customers and demand decreased by 611 MW to 2197 MW. As of December 2024, about 5,900 customers were in the queue to participate in the program.
EGLE transitions internship program from unpaid to paid: On January 28, 2025, the Michigan Department of Environment, Great Lakes, and Energy (EGLE) announced that it had invested over $170,000 to transition its summer internship program from unpaid to paid. The Program allows students to work with EGLE staff on projects that match the students’ interests.
EGLE releases awarded communities plans for Renewable Ready Communities Awards: On January 30, 2025, the Michigan Department of Environment, Great Lakes, and Energy (EGLE) released an article on the positive impacts the Renewables Ready Communities Awards had on awarded communities. The Awards aim to incentivize local communities to host new utility-scale renewable energy projects. EGLE determines award size based on the size of the project communities agree to host. Communities that host utility-scale projects can receive awards of up to $5000 per MW of project size for community improvements. Awarded communities include:

Coldwater Township plans to use the three awards totaling $991,250 it received by approving the 150 MW Cold Creek Solar Project to improve roads, purchase accessible playground equipment, and expand office space
Ecorse plans to usethe $1 million award it received by approving the Redstart Energy Storage Project to improve youth enrichment efforts
Evergreen Township plans to use the $330,000 award it received by approving the 175 MW Fish Creek Solar Project to improve roads, the town hall, and the fire barn
Belknap Township plans to use the $152,500 award it received by approving the Little Trout Solar Project to improve roads, replace equipment in the town hall, and upgrade disaster preparedness plans
Trenton plans to use the $1.1 million award it received by approving the 220 MW Trenton Channel Energy Center to improve roads and enhance downtown placemaking opportunities

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District of Columbia

In investigation of Pepco Integrated Distribution System Planning, DCPSC extends comment deadline to Mar. 14; Reply comments now due Apr. 14

As discussed in PJM Flash 24-49, on November 27, 2024, the District of Columbia (DC) Public Service Commission (PSC) issued a Notice of Inquiry opening Formal Case 1182. In this proceeding, the PSC plans to investigate the Integrated Distribution System Planning (IDSP) of the Potomac Electric Power Company (Pepco), the electric distribution company (EDC) serving DC. The PSC initially requested public comment on the Notice of Inquiry by January 31, 2025, with reply comments due February 28. On January 31, the PSC issued an Order extending the comment deadline to March 17, 2025, and the reply comment deadline to April 14, 2025. Comments may be submitted though the PSC website here.

DC Mayor signs bill amending Building Energy Performance Standards

On January 15, 2025, District of Columbia (DC) Mayor Muriel Bowser (D) signed into law Act A25-0701 – Building Energy Performance Standards (BEPS) Amendment Act of 2024. BEPS requires building owners to meet energy or emissions-based performance target, to facilitate achievement of DC’s energy and climate goals of the Sustainable DC plan (e.g., reduce greenhouse gas emissions and energy consumption by 50% by 2032).

Among other provisions, the Act amends the Green Building Act of 2006 and Clean Energy DC Omnibus Act of 2018 to modify various BEPS reporting, verification, and compliance cycles and deadlines; require the Department of Energy and Environment (DOEE) to submit a report on the efficacy of third-party verification to the Council of the District of Columbia no later than April 1, 2025; and incorporate into the Standards recommendations from the BEPS Task Force.

Committee on Transportation and the Environment issues Council Period 25 Activity Report, includes budget and legislative priorities in vehicle and building electrification

On February 3, 2025, the District of Columbia (DC) Committee on Transportation and the Environment (CTE) published the, CTE Council Period 25 Activity Report (Report) on its Legislative Information Management System (LIMS) website. The Report lists five themes for its legislative, oversight, and budget priorities:

Improving traffic safety.
Transforming public spaces into vibrant civic, recreational, and commercial hubs.
Building a robust and accessible multimodal transportation network.
Fostering the innovation and use of emerging transportation-related technologies.
Mitigating the impacts of climate change and improving human health through healthy homes and buildings.

Among others, the Report summarized three key bills related to electrification:

Council Bill 250106: The Comprehensive EV Infrastructure Access, Readiness, and Sustainability Amendment Act of 2024, if enacted, would expand access to community EV charging infrastructure in the D.C. by amending existing transportation and green building laws. It would require permit holders to share charging data with the District Department of Transportation (DDOT) and the Department of Energy and Environment (DOEE) and would mandate the development of a publicly accessible EV Infrastructure Deployment and Management Plan to assess and improve DC’s EV charging capacity, with a goal of ensuring at least 5% of charging ports for DC-registered vehicles by 2027.

The bill would introduce new permitting requirements for commercial and multi-unit residential buildings with three or more parking spaces and single-family homes, ensuring they are EV-installed or EV-ready. It also establishes a “right-to-charge” for condo owners, co-op members, homeowners in associations, and tenants while allowing for reasonable safety-based restrictions. Additionally, the legislation would mandate the installation of fast-charging ports at high-volume retail service stations that sell over one million gallons of gasoline per year if newly installed or improved by at least 50% of their value. Finally, the bill would launch a public education campaign to increase awareness of EV charging options across the city.

Council Bill 250119: The Healthy Homes and Residential Electrification Amendment Act of 2023 would establish the Breathe Easy Program within the DOEE to provide residential electrification retrofits for low-income households in DC, at no cost to residents. The program may also support moderate-income households, offering subsidies on a sliding scale determined by DOEE. Additionally, the program includes training for contractors involved in electrification retrofits. DOEE would be required to complete 30,000 retrofits for low-income households, with incremental benchmarks in 2027, 2032, and 2037 to ensure steady progress over time.

Council Bill 250801: Discussed elsewhere in this Flash Update, the Building Energy Performance Standards Amendment Act of 2024 would reduce administrative burdens within the Building Energy Performance Standards (BEPS) Program by adjusting compliance timelines and streamlining processes. The bill would delay the start of the second and third BEPS cycles, postpone benchmark reporting for buildings 10,000 square feet or more by one year, and provide a full-cycle exemption for vacant buildings and those in financial distress. It would also move the benchmarking and reporting deadline from April 1 to May 1 to simplify compliance. The bill would reduce the frequency of mandatory third-party verification from six to three years and require DOEE to submit a compliance report on third-party verification. Lastly, it would allow building owners to pass non-compliance costs to commercial tenants, depending on lease terms.

Other District of Columbia News of Note

Pepco issues semi-annual transportation electrification report for 2024 Q3 and Q4: On February 3, 2025, in District of Columbia (DC) Public Service Commission (PSC) Docket FC 1130, Potomac Electric Power Company (Pepco) filed its Semi-Annual Report on the Implementation of the Transportation Electrification Program (TEP). Pepco reports that 128 residential customers are now enrolled in its whole-home time-of-use rate. Additionally, Pepco’s public Level 2 and direct current fast charger (DCFC) offerings are fully subscribed, though a plan to support make-ready infrastructure for twelve chargers for taxi/rideshare services has been scrapped; the associated funds have been reallocated to support the public charging program.
DC Mayor signs bill approving $4.6 million in funding for microgrid project: On January 31, 2025, Mayor Muriel Bowser (D) signed into law Act A25-0713. As discussed PJM Flash 24-52, the law authorizes a multiyear contract of up to $4.66 million with Ameresco, Inc. for the development of a microgrid for St. Elizabeth’s East campus and for the energy generated by the microgrid for a 15-year period.

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Delaware

PSC approves regulations to comply with laws increasing size of eligible net metering facilities for farms and allowing farms to carry over kWh credits, retroactively eliminates cashout of kWh credits

On January 30, 2024, in Case REG 65, the Delaware Public Service Commission (PSC) issued an Order making revisions to the State’s net metering rules. The Order brings the net metering rules in compliance with several legislative changes, specifically:

Chapter 355 of 2022 (formerly Senate Bill 298)
Chapter 7 of 2023 (formerly Senate Bill 54)
Chapter 125 of 2023 (formerly Senate Bill 111)

The Order provides that:

Farm customers may now net meter with systems that are up to 150 kW (presumably, though not explicitly, in AC), whereas previously the maximum capacity for farms was 100 kW
Utilities may now enter into power supply agreements with farm customers and farm customers can carry over excess kWh credits from year to year
Effective January 1, 2024, the excess kWh credit for all customers is valued at the sum of the volumetric elements of a customer’s bill, minus the societal benefits charges, which are defined as Green Energy Fund, the Low-Income Fund, and the cost of RPS compliance
Customer can no longer cash out the value of excess kWh credits, effective May 31, 2023.

We note that several of the effective dates in the new rules are in the past and that these dates are set by the bills the new rules are implementing. As last discussed in PJM Flash 24-45, the PSC’s January 30 Order followed a previous Order proposing the regulations for public comment.

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North Carolina

NCUC Staff recommends that NCUC approve with exceptions the electric cooperatives’ CEPS Compliance 2023 Reports and 2024 Plans

As discussed in PJM Flash 24-35, on August 22 and August 26, 2024, in North Carolina Utility Commission (NCUC) Docket E-100 Sub 199, the Tennessee Valley Authority (TVA), EnergyUnited Electric Membership Corporation, North Carolina Electric Membership Corporation, and the Town of Waynesville each submitted 2023 Clean Energy Portfolio Standard (CEPS) Compliance Reports and 2024 CEPS Compliance Plans. Under G.S. § 62-133.8 (i.e., the enabling statute for CEPS), publicly-owned electric utilities in North Carolina are required to supply the equivalent of 10% of the previous year’s retail electricity sales through renewable power generation, energy efficiency measures, hydroelectric facilities, and/or demand reduction. Out of the 10% requirement, .02% must be met with solar energy resources, .02% must be met with swine waste-to-energy resources, and 900,000 MWh statewide must be met with poultry waste resources.

On February 3, 2025, NCUC Staff filed Reply Comments on the 2023 CEPS Compliance Reports and the 2024 CEPS Compliance. The Comments were submitted pursuant to the NCUC’s October 2024 Order Establishing Dates for Comments on CEPS Compliance Plans and Reports.

In its Comments, Staff recommended that the NCUC:

Approve the 2023 CEPS Compliance Reports for all Electric Membership Corporations/Municipal Suppliers (EMC/Muni Suppliers)
Find that all EMC/Muni Suppliers have submitted Compliance Plans that satisfy the requirements of the CEPS
Find that all EMC/Muni Suppliers (except the Town of Waynesville) should be able to meet their planned CEPS obligations without exceeding their cost caps, except for the swine and poultry waste set-asides, which the EMCs/Muni Suppliers have had difficulty meeting

DEQ holding Public Engagement Sessions to collect feedback on implementing Climate Pollution Reduction Grant’s Comprehensive Climate Action Plan, Kickoff meeting Feb. 25

On February 5, 2025, the North Carolina Department of Environmental Quality (DEQ) announced that it is holding a series of public engagement sessions to provide information on DEQs initiative to reduce greenhouse gas emissions as part of the federal Climate Pollution Reduction Grant’s (CPRG) Comprehensive Climate Action Plan (CCAP) programs. The announcement noted that North Carolina was awarded $3 million from the CPRG program and is actively developing CCAP. The announcement also noted that North Carolina developed and submitted a Priority Climate Action Plan in 2024. Additional information on the CPRG is available on the DEQ’s website.

During the public engagement sessions, the DEQ will solicit feedback on how to include existing community climate strategies in the CCAP. The CCAP team will use the feedback to shape its direction, priorities, and future projects. DEQ will hold public sessions on the following dates:

Public Engagement Session #1, February 25, 2025 at 6:00 pm: Virtual CCAP Kick-off, register here
Public Engagement Session #2, February 27, 2025, at 6:00 pm: In-Person Meeting at Lumbee River Electric Membership Corporation – 6090 NC HWY 711, Pembroke, NC
Public Engagement Session #3, February 27, 2025, at 5:00 pm: In-Person Meeting at Cumberland County North Regional Public Library – 855 Mcarthur Rd, Fayetteville, NC
Public Engagement Session #3, February 27, 2025, at 6:00 pm: In-Person Meeting at Western Piedmont Community College – 1001 Burkemont Ave, Morganton, NC

Public comments can be submitted to cprg@deq.nc.gov with “CPRG Comment” in the subject line.

Other North Carolina News of Note

North Carolina Clean Energy Technology Center analyzes the impact of the CFAT Grant: On January 28, 2025, the North Carolina Clean Energy Technology Center (NCCETC) released an analysis of the Clean Fuel Advanced Technology (CFAT) grant. The CFAT grant has awarded more than $9.6 million to 120 projects that aimed to reduce transportation-related emissions. NCCETC found that idle reduction systems and EV-related infrastructure were the most-funded technologies. CFAT projects resulted in estimated reductions of over 500,000 kg of pollutants per year.

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Kentucky

Lost City Renewables LLC files Notice of Intent to file an Application for a Certificate of Construction for transmission line to interconnect its proposed 250 MW solar plant

On February 3, 2025, in Kentucky Public Service Commission (KY PSC)Docket for Case 2025-00030, Lost City Renewables LLC filed a Notice of Intent (NOI) to file for a Certificate of Construction by July 1, 2025 for a 161kV Nonregulated Electric Transmission Line. The transmission line is up to 10.8 miles in length and located in Muhlenberg and Logan counties, KY. The line will interconnect Lost City’s proposed 250 MW solar facility into TVA’s transmission system.

On February 5, 2025, the KY PSC issued a No Deficiency letter stating that the NOI is administratively complete.

Starfire files Application for Certificate of Construction for 210 MW solar project

On February 4, 2025, in Kentucky Public Service Commission (PSC) Docket 2024-00255, STMO Bn, LLC (Starfire) filed an Application seeking approval for a Certificate of Construction from the Board on Electric Generation and Transmission Siting (Siting Board) to construct a solar facility.

The Starfire Solar Project is a proposed 210 MW_AC solar facility under development by BrightNight in the counties of Breathitt, Knott, and Perry, KY.

Starfire also submitted a Site Assessment Report, which contains a Site Plan, Property Value Impact Analysis Report, Legal Boundaries, Acoustic Assessment, Visual Simulations, Glare Hazard Analysis, and a Traffic Assessment.

Other Kentucky News of Note

Kentucky’s second NEVI-funded EV charging station now operational: On February 5, 2025, Kentucky Governor Andy Beshear (D) announced that the State’s second National Electric Vehicle Infrastructure (NEVI)-funded direct current fast charging station is now operational. The station, which received $537,000 in NEVI funds through the State’s EV Charging Program, is located at a Circle K in Berea, KY.

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Indiana

Indiana Michigan Petitions IURC to adjust recovery costs of wind PPAs and other renewable purchases

On January 31, 2025, in Indiana Utility Regulatory Commission (IURC) Docket No. 38702-FAC 94, the Indiana Michigan Power Company (I&M) filed a Petition in seeking approval for the continued cost recovery of the following:

The costs of excess distributed generation (DG) purchases
The costs of wind power purchases
The energy-related costs of demand response programs
Other non-clean energy expenses (cogeneration and hedging purchases)

In the Petition, I&M noted that the continued cost recovery of the DG purchases is sought pursuant to the IURC Order dated January 26, 2022 (in Docket No. 45506), and that the cost recovery for the wind purchases is sought pursuant to Orders dated November 28, 2007 (in Docket No. 43328), January 6, 2010 (in Docket No. 43750, ), September 21, 2011 (in Docket No. 44034), and November 25, 2013 (in Docket No. 44362). The Petition seeks approval for a six-month period between May 2025 and October 2025 and included an estimate of energy purchases for that period, shown in the table below (recreated, the full table is available in the Petition).

Energy Sources (MWh)	Total (May 2025 – Oct. 2025)	Estimated Six Month Average
Fossil Generation	1,321,593	220,266
Nuclear Generation	8,506,632	1,417,772
Hydro Generation	44,207	7,368
Solar Generation	39,835	6,639
AEG	1,321,593	220,266
OVEC	283,630	47,272
Wind Purchases	486,687	81,115
Other System Purchases	1,431,512	238,585
COGEN/DG	9,942	1,657
Less:
Energy To Off-System Sales	735,836	122,639
Energy Losses and Company Use	443,572	73,929

I&M proposed the following procedural schedule for consideration of its Petition:

March 7, 2025 – OUCC/Intervenors prefile cases-in-chief
March 21, 2025 – I&M rebuttal
Week of March 31 through April 3 – Evidentiary hearing

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Tennessee

TVA seeks public input on the Clinch River Nuclear Site Advanced Technology Park Unit 1, Comments due March 18

As last discussed in PJM Flash 25-5, on November 21, 2024, the Tennessee Nuclear Advisory Committee (TNEAC) published its Final Report, which found that deploying a small modular reactor (SMR) at the Clinch River Nuclear Site would provide numerous economic and environmental benefits. TNEAC recommended that the State support and coordinate with the Tennessee Valley Authority (TVA) to support an SMR at the Clinch River Nuclear site. Subsequently, on January 23, 2025, TVA issued a press release announcing that it will work with Bechtel, Sargent & Lundy, and GE Hitachi through a technology collaboration agreement to support initial planning and evaluation for the first SMR at TVA’s Clinch River site, and to develop the standard design for the BWRX-300 (the SMR under consideration for deployment at the Clinch River site).

On January 31, TVA issued a request for comments to gather public comment on the Clinch River Site’s Draft Supplemental Environmental Impact Statement (SEIS). The Draft SEIS, which supplements the Programmatic Environmental Impact Statement (PIES), addresses the potential environmental effects associated with site preparation, construction, operation, and decommissioning of one small modular reactor (SMR).

TVA invited the public to learn and ask questions about the Draft SEIS during a public meeting scheduled for 5:30 pm – 7:30 p.m. ET on Thursday, February 27, at the East Tennessee Economic Council, 1201 Oak Ridge Turnpike, Oak Ridge, TN 37830. In addition, TVA scheduled a virtual meeting for 5:30 pm on Tuesday, February 25. Meeting information is available at tva.com/nepa. Comments can be submitted online here. Comments are due March 18, 2025.

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Regional and National

President Trump issues Executive Orders imposing tariffs on imports from Canada, Mexico, and China; Delays tariffs on imports from Canada and Mexico until Mar. 4, pending negotiations; Uncertain impact on energy markets

On February 1, 2025, President Donald Trump (R) issued a series of Executive Orders imposing new and incremental tariffs on imports from Canada, Mexico, and China, citing insufficient efforts by these governments to curb drug trafficking into the U.S. (see related fact sheet). The tariffs were initially set to take effect on February 4. However, while the tariff increase on Chinese imports has been implemented, President Trump issued further Executive Orders on February 3 delaying the tariffs on Canadian and Mexican imports until March 4, providing time for further consideration and negotiation. Additionally, according to several news sources, on February 9, President Trump announced forthcoming 25% tariffs on all steel and aluminum imports, though this has yet to be implemented via Executive Order.

The initial Executive Orders imposed:

A 25% tariff on all imports from Canada, except “energy resources,” which are subject to a 10% tariff
A 25% tariff on all imports from Mexico
A 10% tariff on all imports from China

For Canadian imports, energy resources are defined per a prior Executive Order on “Declaring a National Energy Emergency” (discussed in Flash 25-3) as “crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water, and critical minerals.” Critically, it remains unclear whether this definition includes electricity, particularly electricity from certain sources (e.g., solar PV appears to be excluded and could be subject to the full 25% tariff). Both ISO-NE and NYISO have issued statements noting that they are seeking clarification from the Trump Administration.

At the time of publication, the fate of the Canadian and Mexican tariffs remains uncertain. Both governments have threatened retaliatory measures, and as discussed in Flash 24-51, Ontario Premier Doug Ford previously warned he would halt energy exports to the U.S. if the tariff on Canadian imports were implemented. While this outcome seems unlikely—partly due to opposition from other Canadian officials—it remains a possibility.

Should the tariffs take effect, they would adversely impact the U.S. clean energy supply chain, with varied effects depending on a project’s reliance on Canadian or Mexican imports and the terms of its offtake contract (i.e., how tariff risks are allocated). Additionally, the tariff on Canadian imports could drive up energy prices, particularly in the Northeast and other regions along the Northern border; however, Canadian imports are rarely a marginal resource, so any impact is likely to be small. The tariff on Chinese goods will also have an adverse impact on the U.S. clean energy supply chain, particularly for raw materials and battery storage.

Two Judges grant temporary restraining orders against OMB funding freeze, coalition of state file for preliminary injunction and enforcement of temporary restraining orders

During the last two weeks of January 2025, President Donald Trump (R) and the Office of Management and Budget (OMB) sought to halt several federal funding programs. In response, multiple legal challenges were filed seeking a restraining order on the funding freeze. The timeline of these events is summarized below.

January 20, 2025: President Trump issued the Unleashing American Energy Executive Order which directed federal agencies to pause the disbursement of funds appropriated through Public Law 117-169 – Inflation Reduction Act of 2022 (IRA) and Public Law No. 117-58 Bipartisan Infrastructure Law (IIJA), discussed in NE Flash 25-3.
January 21, 2025: The OMB issued Memorandum M-25-11, which stated that the disbursement pause “only applies to funds supporting programs, projects, or activities that may be implicated by the policy established in Section 2 of the order. Section 2 contains broad statements of policy.
January 27, 2025: The OMB issued Memorandum M-25-13, which directed all federal agencies to temporarily pause nearly all “activities related to obligation or disbursement of all Federal financial assistance, and other relevant agency activities” implicated by President Trump’s recent EO’s, discussed in NE Flash 25-4.1.
January 28, 2025: A coalition of non-profit groups filed a Complaint with the U.S. District Court for the District of Columbia, against the OMB and its acting director Matthew Vaeth seeking a temporary restraining order of the Memorandum M-25-13.
January 28, 2025: A coalition of 22 Democratic state attorneys general and the District of Columbia filed a Complaint with the U.S. District Court of Rhode Island seeking a temporary restraining order of Memorandum M-25-13. Later in the day U.S. District Judge Loren L. AliKhan issued an administrative stay, halting the implementation of the OMB Memorandum M-25-13 until February 3, 2025, pending further legal review, discussed in NE Flash 25-4.
January 29, 2025: The OMB issued a Memorandum M-25-14, which rescinds the earlier memorandum (i.e., Memorandum M-25-13) ostensibly restoring funding obligations and disbursements. However, in various press conferences and social media posts, the White House noted the recent EOs remain in effect and that agencies must immediately pause the disbursement of “Green New Deal” funds.
January 29, 2025: U.S. District Judge John McConnell hears arguments on the coalition of states complaint (hearing recording available here)
January 30, 2025: U.S. District Judge John McConnell issued a temporary restraining order (TRO) against the OMB and Memorandum M-25-13, re
February 3, 2025: U.S. District Judge Loren L. AliKhan hears arguments on the non-profits coalition complaint
February 3, 2025: U.S. District Judge Loren L. AliKhan issued a TRO against the OMB and Memorandum M-25-13

The two temporary restraining orders require that the Defendants (which includes the OMB, and the Trump administration) “[shall] not pause, freeze, impede, block, cancel, or terminate… awards and obligations to provide federal financial assistance to the States,” and “from implementing, giving effect to, or reinstating under a different name the directives in OMB Memorandum M-25-13 with respect to the disbursement of Federal funds.” In addition, the courts found the OMB’s rescission of Memorandum M-25-13 to be “in name only” given the reaction to the Trump Administration and the weight of the EO’s.

The TROs stay in effect until further hearings are held for a permanent injunctions. It is unclear if the Trump administration or the U.S. Department of Justice, will appeal the TROs. For the coalitions of non-profits case, all parties were required to file proposed procedural schedules for preliminary injunction hearings by February 7, 2025.

Despite this multiple news outlets have reported that during a February 6, 2025, hearing, the Coalition of states claimed they could still not access certain federal funds, in violation of the Court orders. One representative from the New York Attorney General office was quoted saying “[w]e’ve had communications from the Defendants indicating that they believe there are certain funds not subject to the TRO, including the billions of dollars of infrastructure legislation and the Inflation Reduction Act.” While U.S. District Judge John McConnell was reportedly open to taking additional steps to enforce the TRO, it is unclear what any enforcement measures would be.

On February 7, 2025, the coalition of states filed two motions: a Motion for Preliminary Injunction and a Motion for enforcement of the TRO. In the Motion for Preliminary injunction, the Plaintiffs present four main arguments, listed below:

Violation of Separation of Powers: The Plaintiffs argue that the executive branch’s unilateral decision to withhold funds appropriated by Congress infringes upon the constitutional separation of powers. They contend that this action violates the Presentment Clause, which outlines the legislative process, and the Appropriations Clause, which grants Congress the exclusive power over federal spending. By withholding funds, the executive branch is effectively overriding Congress’s budgetary decisions, disrupting the balance of power established by the Constitution.
Exceeding Executive Authority: The Motion asserts that the Administration’s funding freeze surpasses its legal authority, contravening the Congressional Budget and Impoundment Control Act of 1974. This Act restricts the executive branch from unilaterally withholding or delaying funds that Congress has appropriated, ensuring that the executive cannot impound funds without congressional approval. The Plaintiffs argue that the funding freeze constitutes an unlawful impoundment of funds, as it lacks the necessary legislative consent.
Lack of Clear Guidelines: The Plaintiffs claim that the funding freeze imposes new conditions on federal funds without providing clear guidance, violating the Spending Clause of the U.S. Constitution. The Spending Clause requires that any conditions on federal grants to states must be unambiguous, allowing states to make informed decisions about accepting the funds. The absence of clear guidelines leaves states uncertain about compliance requirements, hindering their ability to plan and manage federally funded programs effectively.
Violation of Administrative Procedures Act: The Motion contends that the implementation of the funding freeze violates the Public Law 404 – Administrative Procedure Act (APA). The APA requires federal agencies follow established procedures when enacting policies, including providing notice, soliciting public comments, and offering reasoned explanations for their actions. The Plaintiffs argue that the funding freeze was implemented without adhering to these procedural requirements, rendering it arbitrary, capricious, and not in accordance with the law.

In support of the motions, the Coalition of states filed following:

January 20 Memorandum by Acting Secretary of Energy
Exhibit B (Email correspondence)
Exhibit C (Email correspondence)
Affidavit of Maya Bea (University of Washington)
Affidavit of Laura Roche (Illinois Environmental Protection Agency)
Affidavit of Travis Boeskool (Michigan Department of Environment, Great Lakes, and Energy)
Affidavit of Adrienne Kreipke (New Jersey Department of Environmental Protection)
Affidavit of Veronique Oomen (New Jersey Board of Public Utilities)
Affidavit of Pam Poisson (NYSERDA)
Affidavit of Paul Pinsky (Maryland Energy Administration
Affidavit of Michael Pieciak (State Treasurer of Vermont)
Affidavit of Sarah Curran (Maine Governor’s Office of Policy Innovation and the Future)
Affidavit of Dan Burgess (Maine Governor’s Energy Office)
Affidavit of Elizabeth Mahony (Massachusetts Department of Energy Resources)
Affidavit of David Mohler (Massachusetts Department of Transportation
Affidavit of Bonnie Heipel (Massachusetts Department of Environmental Protection)
Affidavit of Katie Dykes (Connecticut Department of Energy and Environmental Protection)
Affidavit of Chris Kearns (Rhode Island Office of Energy Resources)

These documents provide testimony and other evidence of funding still being withheld or frozen, showing the Trump administration is not complying with the TROs.

Senate confirms Doug Burgum as Secretary of Interior, Lee Zeldin as administrator of EPA, Chris Wright as DOE secretary; Burgum issues Orders implementing President’s Executive Orders

In the last week of January and the first week of February, the U.S. Senate has confirmed candidates nominated by President Donald Trump (R) to various cabinet positions. Notably, the Senate confirmed the following nominees that affect have some form of oversight of renewable energy:

Doug Burgum was confirmed as Secretary of the Interior by a bipartisan vote of 80-17
Lee Zeldin was confirmed as Director of the U.S. Environmental Protection Agency by a largely, partisan vote of 56-42
Chris Wright was confirmed as the Secretary of Energy by a bipartisan vote of 59-38

All three have, in various ways, pledged to enact President Trump’s agenda of “American energy dominance” though reducing regulations an increasing domestic energy supply. Notably Interior Secretary Burgum issued a slate of Secretary’s Orders. The Secretary’s Orders include:

Order 3417 – Addressing the National Energy Emergency – directs the U.S. Department of the Interior to identify emergency and all other authorities to facilitate the development of energy and natural resources and associated infrastructure and develop plans to use those authorities for review by the Secretary by February 17.
Order 3418 – Unleashing American Energy – Directs the DOI to implement President Trump’s recission of several President Joe Biden’s Executive Orders and take actions to increase the extraction of oil and gas and critical mineral resources. The Order also directs a review of “processes, policies, and programs for issuing grants, loans, contracts, or any other financial disbursements of all appropriated funds from the Inflation Reduction Act of 2022 (Public Law 117-169) and the Infrastructure Investment and Jobs Act (Public Law 117-58).”
Order 3419 – Delivering Emergency Price Relief for American Families and Defeating the Cost-of-Living Crisis – Orders the DOI to review all programs and regulations that may raise costs, and explicitly directs that the review “focus on coercive ‘climate’ policies that increase the cost of food or energy.”
Order 3420 – Announcing President Trump’s Revocation of Former Outer Continental Shelf Withdrawals – rescinds all Biden administration withdrawals of Outer Continental Shelf areas from oil and gas leasing.
Order 3421 – Achieving Prosperity through Deregulation – Orders the DOI to identify at least 10 existing regulations to eliminate for each new regulation and completely offset the costs of the incremental costs of new regulations with these 10 other regulation eliminations.
Order 3422 – Unleashing Alaska’s Extraordinary Resource Potential – reinstates a 2017 DOI policy under Pres. Trump’s first term to allow oil and gas drilling in the Arctic National Wildlife Refuge

We note the Secretary’s Orders are framed as implementing President Trump’s Executive Orders, notably Unleashing American Energy, that, among other things, declared that it was “[t]erminating the Green New Deal,” and another Executive Order that paused all offshore wind leasing and permitting. Accordingly, in the context of Trump administration efforts to pause renewable energy programs, we interpret the Secretary’s reference to expanding domestic energy as unlikely to be a reference to facilitating the expansion of renewable energy capacity deployment.

President Trump issues executive Order requiring for any new agency rule, ten existing rules required to be repealed

On January 31, 2025, President Trump issued an Executive Order (EO) titled “Unleashing Prosperity Through Deregulation” which, as noted in a Press Release, aims to reduce federal spending resulting from federal regulation. The EO directs all agencies to identify ten existing regulations to be repealed when any new regulation is introduced, and to ensure that the total incremental costs of all regulation activity (both new regulations and repealing regulations) is “significantly less than zero.” This metric is not quantified in the EO but notes will be determined by the Director of the Office of Management and Budget (OMB). In addition, the Director of OMB is granted the authority to exempt “any other specific regulation or category of regulations… that impose minimal costs or burdens on the private sector” or that are requested to be exempted by the Administration.

Several agencies that regulate clean energy are impacted by this EO, including FERC, the U.S. Department of Energy, the U.S. Environmental Protection Agency, and the U.S. Department of the Interior. It is unclear how each agency will respond, or what specific regulations may be affected. That said, at minimum we anticipate that agencies will be far more restrained in adopting new rules or regulations, doing so only when they deem it absolutely necessary.

FERC approves MISO interconnection queue proposal to establish a per-queue-cycle cap at 50% of non-coincident summer peak load

On January 30, 2025, in Docket 25-507, FERC issued an Order approving the Midcontinent System Operator, Inc (MISO) proposal — filed on November 21, 2024 — to modify its generator interconnection study process to implement an interconnection queue cap and exemptions to that cap. Specifically, MISO proposed to implement a limit on the total MWs that would be studied in each regions interconnection cycle. Under MISO’s now-approved plan, the queue cap will be set at 50% of the non-coincident summer peak load value for each study region (where the non-coincident summer peak value is modeled from MISO’s Transmission Expansion Plan model). MISO explained that it would post the MW value for each study cycle on its website at least ten business days prior to the application deadline for a given study cycle and that it would also post an associated whitepaper to inform stakeholders of how it developed and set the queue cap.

Additionally, under MISO’s approved plan, interconnection queue cap exemptions will exist when (i) a larger power plant replaces a retiring generating facility, (ii) a generator converts from Energy Resource Interconnection Service to Network Resource Interconnection Service, and (iii) for generating facilities with a provisional generator interconnection agreement.

In its Order, FERC noted that it found MISO’s proposed approach to provide a reasonable and fair methodology for the grid operator to manage a an unprecedented amount of capacity in the interconnection queue that was making it difficult to understand and model system impacts of interconnection queue applications. MISO’s interconnection queue cap is scheduled to take effect when MISO opens its next queue cycle in the fall of 2025. Lastly, MISO plans to review the queue cap with stakeholders after completing three interconnection queue study cycles.

Other Regional and National News of Note

FirstEnergy hires Finance and Regulatory Vice Presidents for West Virginia, Maryland, and Ohio: On February 4, 2025, FirstEnergy announced that it has hired two Finance and Regulatory Vice Presidents for West Virginia, Maryland, and Ohio. First Energy hired Arsalan Azarsa, former Regional Director of Finance and Accounting at Vicinity Energy, as Finance and Regulatory Vice President for West Virginia and Maryland. First Energy also hired Kevin Keller, former Director of Financial Forecasting at American Electric Power, as Finance and Regulatory Vice President for Ohio. Both will be responsible for developing and implementing the financial strategy for their respective states.
Chevron partners with GE Vernova to join market for data center co-located generation: On January 28, 2025, Chevron announced its plans to create natural gas-based power plants next to data centers. Chevron is partnering with GE Vernova to build “power foundries” co-located with data centers on an accelerated timeline. The plants will be designed to avoid having generated electricity flow through the existing transmission grid to limit the risk of raising electricity costs. Chevron also plans to design the plants with flexibility to integrate carbon capture and storage technologies and renewable energy. Chevron expects to have the first plants to deliver up to 4 GW and be operational by the end of 2027.
Treasury withdraws from Network of Central Banks and Supervisors for Greening the Financial System: On January 30, 2025, the U.S. Department of the Treasury (Treasury) announced it had withdrew from the Network of Central Banks and Supervisors for Greening the Financial System (NGFS). The NGFS was created for willing members of the financial system to help meet the goals of the 2016 Paris Agreement, to which the U.S. is no longer a signatory(as discussed in Flash 25-4). Treasury explains that the withdrawal is one part of implementing President Trump’s Putting America First in International Environmental Agreements and Unleashing American Energy Executive Orders.
U.S. Department of Labor approves guidelines for solar apprenticeship programs: On January 30, 2025, the Interstate Renewable Energy Council announced it had received approval from the U.S. Department of Labor (DOL) for the National Guidelines for Apprenticeship Standards for the solar industry. The Standards provide a template for companies, educational institutions, associations, and labor unions to create apprenticeship programs that comply with federal regulations. The new guidelines apply to the DOL-recognized Construction Craft Laborer apprenticeship occupation.
Wood Mackenzie releases report on EV demand post Trump executive orders, find adoption could drop to 23% by 2030: On January 28, 2025, Wood Mackenzie released a report on the impact of President Trump’s recent Executive Order on the EV and battery industries. The Report found that recent policy announcements, specifically the Unleashing American Energy Executive Order, could lower EV adoption from 32% to 23% by 2030. The Report also found that constricting the eligibility for the Internal Revenue Code § 30D tax credit could reduce demand for EV batteries and energy storage batteries.
Wood Mackenzie releases outlook of wind and solar development following President Trump’s Executive Orders: On January 31, 2025, Wood Mackenzie released and opinion piece on the outlook of wind and solar development following President Trump’s Executive Orders (EO). The opinion explains that although wind development has been the primary target of President Trump’s EOs, solar development could be impacted as well. Wood Mackenzie suggests that the biggest risk to solar development is the loss of the production and investment tax credits, which could be reduced or removed to pay for the renewal of tax cuts.
Wood Mackenzie releases report on energy storage trends in 2025: On January 30, 2025, Wood Mackenzie released a report on energy storage trends in 2025. The Report summarizes key themes in the battery storage market in 2025. The Report found the following trends:

Emerging markets will be on the rise
Increased protectionism will intensify cost and supply chain risk across regions
Technology developments will provide downward cost pressure
Storage demand growth will be supported by large loads
Renewable growth and thermal generation retirements will continue to drive long duration storage investments

Tesla reports residential storage grew to 31.4 GW in 2024, expects deployments to increase 50% in 2025: On January 29, 2025, Tesla released its earnings presentation for Q4 2024. Tesla reported that its Megapack and Powerwall battery storage deployments increased from 14.7 GWh in 2023 to 31.4 GWh in 2024. Tesla expects deployments to increase by 50% in 2025.
LevelTen releases 2024 Q4 Report, finds PPA prices increased by 3.3% in Q4 and yearly increase of 13%: In January 2025,LevelTen released a Report on its PPA Price Index for Q4 2024. The Report found that PPA prices for both wind and solar increased 3.3% in Q4 and 13% year-over-year. The Report cites uncertainty over tariffs and tax credits as the reason for the increase. LevelTen anticipates that prices will continue to rise but says it is too early to predict the impact of policies from the Trump administration on future PPA prices.
Case dismissed against oil companies for deceiving customers about climate impacts: On January 23, 2025, the Supreme Court of the State of New York (the Court) issued a Decision and Order on Motions dismissing New York City’s lawsuit against ExxonMobil, Shell, BP, and the American Petroleum Institute for alleged consumer deception regarding the climate impact of fossil fuels. In the Decision, the Court ruled that the connection between fossil fuels and climate change is widely known, undermining the City’s argument that consumers were misled. Additionally, the Court found that the City failed to sufficiently plead that the defendants’ alleged greenwashing campaigns were made in connection with the sale of fossil fuel products in New York City, as required under the City’s Consumer Protection Laws. The Court also ruled that claims related to statements made before April 22, 2018, were time-barred.
DSIRE releases 2024 review of U.S. advanced nuclear landscape: On January 28, 2025, the North Carolina Clean Energy Center published a report titled: 2024 in Review: Navigating the Advanced Nuclear Landscape. The Report highlighted state and federal advancements in advanced nuclear deployment in 2024. In New England, Massachusetts Governor Maura Healey signed S.B. 2967, making Massachusetts the first state to add fusion energy to its RPS Class I renewable energy generating sources (as last discussed in NE Flash 24-42). Additionally, New Hampshire enacted H.B. 1465, mandating ongoing studies into nuclear energy development, including advanced nuclear technologies (as discussed in NE Flash 24-5). New York enacted legislation to promote advanced nuclear technologies, including small modular reactors, by streamlining regulatory processes and providing financial incentives. Within the PJM Interconnection region, several member states initiated studies to assess the feasibility of integrating advanced nuclear reactors into their energy portfolios, aiming to enhance grid reliability and meet decarbonization goals.
NECA holds Jan. 24 “Hot Topics in 2025 New England Public Policy” webinar: On January 24, 2025, Northeast Energy and Commerce Association (NECA)’s Legislative Committee held a webinar discussing key energy and environmental policy issues shaping New England’s 2025 legislative sessions. Panelists highlighted energy affordability as a major regional concern. New Hampshire’s new Republican leadership is prioritizing budget cuts while reviewing net metering and renewable policies. Massachusetts and Rhode Island are focused on defending offshore wind from federal opposition. In Maine, policymakers anticipate the region’s first Longer-Term Transmission Planning solicitation to expand renewable energy integration.
Acadia Center publishes Report on benefits of energy efficiency programs: On January 27, 2025, EcoRI the Acadia Center announced that the Acadia Center had completed a Report on the benefits of energy efficiency programs in New England from 2012 to 2023. The Report found that these programs collectively delivered over $55 billion in lifetime benefits, yielding more than $3.40 for every $1 invested. They also supported over 160,000 energy efficiency jobs and reduced CO₂ emissions at levels equivalent to removing nearly 33 million gasoline-powered cars from the road for one year. Additionally, the programs improved public health by reducing fossil fuel combustion and enhancing grid reliability. A breakdown of economic benefits by each state is available here.
EIA releases 2025 forecast of electricity prices, predicts modest increases in wholesale and retail prices: On January 27, 2025, the Energy Information Administration (EIA) released its January Short-Term Energy Outlook, forecasting a 7% increase in wholesale power prices across most U.S. regions in 2025, driven by a 24% rise in natural gas costs. Prices in ISO‑NE are projected to rise 16% to an average of $55 per MWh. In NYISO, wholesale electricity prices are expected to reach $46 per MWh, reflecting regional transmission constraints and natural gas price volatility. Similarly, PJM prices are forecasted to average $45 per MWh, with increases driven by higher fuel costs and capacity market dynamics. In contrast, the Northwest may see more stable prices due to increased hydropower and solar generation. Despite rising wholesale costs, retail electricity prices for residential customers are expected to increase only 2%, averaging 16.8 cents per kWh, with inflation-adjusted rates remaining relatively unchanged from 2024.
ACT to hold webinar on President Trump’s Executive Orders on Feb 11: During the week of January 27, 2025, the Alliance for Climate Transition (ACT) announced that it has scheduled a webinar on the implications of recent Executive Orders (EOs) reversing federal climate policies to be held on February 11, 2025, at 9:30 am. Additional detail on the EOs available in NE Flash 25-3. The webinar will provide insights into how these policy shifts may impact federal climate funding and regulatory landscapes. Registration is available here.

Shell pauses involvement in Atlantic Shores offshore wind project

During the week of January 27, 2025, Shell informed multiple news outlets that it will be “pausing” its involvement with the Atlantic Shores Offshore Wind project. On January 30, 2025, Shell released its 2024 Fourth Quarter Financial Report, in which it listed a $1.085 billion impairment charge in the fourth quarter, of which $996 million relates to Shell’s decision to “pause” its involvement in Atlantic Shores. Shell’s Chief Financial Officer (CFO) stated that “[w]e just don’t see that it fits both our capabilities nor the returns that we would like, so we took the decision to effectively write that off and pause our involvement.” EDF Renewables has not commented on this development. Atlantic Shores released a statement saying it intends to continue progressing with the project.

As discussed elsewhere in this flash, after the announcement from Shell, New Jersey Governor Phil Murphy’s administration issued a statement announcing that New Jersey will not make an award in its latest round of offshore wind solicitations (NJ 4^th solicitation), in which Atlantic Shores was the sole bidder.

As discussed in Flash 24-40, Atlantic Shores Offshore Wind, LLC (Atlantic Shores), is a 50/50 joint venture between subsidiaries of EDF Renewables and Shell New Energies. Atlantic Shores South is proposed to generate approximately 2,800 MW of offshore wind energy off the coast of New Jersey in lease area OCS-A 0499. The projects plan to interconnect at either the Cardiff Substation (Atlantic City Electric transmission zone) and/or the Larrabee Substation (Jersey Central Power & Light transmission zone). Project 1 and Project 2 will be electrically distinct from one another, with separate export cables and routes.

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SEA PJM Flash 25-6: Issued: February 12, 2025

Top Stories

Headlines

2025 PJM Footprint Legislative Tracking Spreadsheet Update

RTO PJM

PJM Market Implementation Committee discusses IMM proposal for DR availability window

PJM submits Hybrids Phase III Proposal with enhancements to current market rules; Comments due Feb. 19

Stakeholders submit responses to PJM’s answer in RRI proceeding, PJM files subsequent response to stakeholder comments

PJM presents wind and solar dispatch proposal

PJM files CIR Transfer Reforms with FERC, proposing new Replacement Generation Interconnection Process; Comments due Feb. 21

IMM issues Report Parts D, E, and F reviewing PJM’s capacity auction results for commitment year 2025/2026

PJM Market Implementation Committee to discuss implementing offer cap for long lead scheduled resources

PJM files motion to withdraw Welcome Solar ISA notice of cancellation as project not in breach of any milestone

PJM Board responds to letters received on Capacity Market Must Offer Exemption proposal

Other RTO PJM News of Note

New Jersey

Rate Counsel files comments opposing Attentive Energy’s motion to stay on financial payments, recommend funds placed in escrow

Stakeholders submit comments on dual-use solar energy pilot program

Stakeholders submit comments following NJBPU technical session on PJM’s Order 2222 compliance approach

Silver Run Electric posts quarterly update for New Jersey Clean Energy Corridor project designed to provide interconnection points for offshore wind

Maryland

Maryland legislative leaders file bills on electricity supply and grid reliability, would require procurement for new nuclear and gas generation, establish solar and storage siting processes, and require integrated planning

Stakeholders comment on draft energy storage regulations, proposing refinements but generally supporting overall direction

Senate Education, Energy and the Environment and House Economic Matters Committees to meet Feb. 20 and Feb. 21 to consider Gov. Moore energy bills

House Environment and Transportation Committee to meet Feb. 20, and Feb. 26 to consider EV and Building Performance Standard Bills

House Economic Matters to meet Feb. 20 and Mar. 6 to consider several energy bills related to eligible RPS sources, data centers, DG siting and solar studies

Senate Education, Energy, and the Environment Committee to meet Feb. 13, Feb. 18, Feb. 20, and Feb. 27 to consider bills related to RPS alterations, EV regulation, OSW installation requirements, and building energy performance standards

Pennsylvania

Gov. Shapiro releases budget proposal, plans to expand tax credits, create statewide electric facility siting board, move forward PRESS and PACER

PPL releases average AEC cost from eighth AEC procurement , average Tier 1 AEC price of $36.73

Virginia

Virginia Legislative Updates: House and Senate pass flurry of energy legislation; all bills not passed from chamber of origin by Feb. 4 dead

Hearing Examiner recommends approval of 500 kV Fentress-Yadkin Transmission Line

Virginia DEQ approves permit-by-rule for 91 MW Carver Solar facility

Other Virginia News of Note

Ohio

House Energy Committee hears sponsor’s testimony on bill to repeal parts of HB6, bars utilities from owning generation, and reinstates energy efficiency

PUCO seeking comments on proposed revision to interconnection standards, due Mar. 7 and Mar. 28

AEP files notice of start of construction on transmission tie-in projects for Pleasant Prairie Solar facility

Other Ohio News of Note

Illinois

IPA releases Indexed REC RFP schedule; Public workshop Apr. 30, Bids due Aug. 1

Stakeholders comment in first REAP workshop, suggest addressing reliability issues in next report

ComEd issues residential TOU pricing pilot annual evaluation report, notes that both EV and non-EV customers saved money by enrolling in TOU rate program

IPA announces large customer self-direct RPS application window opens, applications due March 14

IPA announces some federal SFA funding received; amount unspecified

Other Illinois News of Note

Michigan

PSC approves with modifications Staff’s proposed framework for utilities’ transportation electrification plan filings

PSC finalizes LSEs’ respective shares of statewide energy storage target, adopts methodology consistent with Staff Straw Proposal

PSC releases 2025 meeting schedule, next meeting February 27

Other Michigan News of Note

District of Columbia

In investigation of Pepco Integrated Distribution System Planning, DCPSC extends comment deadline to Mar. 14; Reply comments now due Apr. 14

DC Mayor signs bill amending Building Energy Performance Standards

Committee on Transportation and the Environment issues Council Period 25 Activity Report, includes budget and legislative priorities in vehicle and building electrification

Other District of Columbia News of Note

Delaware

PSC approves regulations to comply with laws increasing size of eligible net metering facilities for farms and allowing farms to carry over kWh credits, retroactively eliminates cashout of kWh credits

North Carolina

NCUC Staff recommends that NCUC approve with exceptions the electric cooperatives’ CEPS Compliance 2023 Reports and 2024 Plans

DEQ holding Public Engagement Sessions to collect feedback on implementing Climate Pollution Reduction Grant’s Comprehensive Climate Action Plan, Kickoff meeting Feb. 25

Other North Carolina News of Note

Kentucky

Lost City Renewables LLC files Notice of Intent to file an Application for a Certificate of Construction for transmission line to interconnect its proposed 250 MW solar plant

Starfire files Application for Certificate of Construction for 210 MW solar project

Other Kentucky News of Note

Indiana

Indiana Michigan Petitions IURC to adjust recovery costs of wind PPAs and other renewable purchases

Tennessee

TVA seeks public input on the Clinch River Nuclear Site Advanced Technology Park Unit 1, Comments due March 18

Regional and National

President Trump issues Executive Orders imposing tariffs on imports from Canada, Mexico, and China; Delays tariffs on imports from Canada and Mexico until Mar. 4, pending negotiations; Uncertain impact on energy markets

Two Judges grant temporary restraining orders against OMB funding freeze, coalition of state file for preliminary injunction and enforcement of temporary restraining orders

Senate confirms Doug Burgum as Secretary of Interior, Lee Zeldin as administrator of EPA, Chris Wright as DOE secretary; Burgum issues Orders implementing President’s Executive Orders

President Trump issues executive Order requiring for any new agency rule, ten existing rules required to be repealed

FERC approves MISO interconnection queue proposal to establish a per-queue-cycle cap at 50% of non-coincident summer peak load

Other Regional and National News of Note

Shell pauses involvement in Atlantic Shores offshore wind project