SEA Storage 26-4: Issued: January 26, 2026

Read this flash online 

2025 Legislative Tracking Spreadsheet Update 

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

Back to Headlines 

ISO New England 

NEPOOL RC considers capacity auction reforms, refines seasonal tie benefits modeling 

On January 22, 2026, at the NEPOOL Reliability Committee (RC) meeting (see agenda), ISO-NE presented updates to its seasonal tie benefits (STB) modeling under the capacity auction reforms (CAR) seasonal/accreditation (CAR-SA) initiative. As last discussed in NE Flash 25-50, the CAR initiative encompasses ISO-NE’s efforts to develop reforms that, if adopted, would (i) transition the current forward-annual market construct to a prompt-seasonal construct and (ii) introduce resource capacity accreditation (RCA) reforms. ISO-NE proposed the following changes to its STB modeling: 

• Updated sensitivities: Following stakeholder comments provided at the December RC meeting (discussed in NE Flash 25-50), ISO-NE updated several modeling inputs and assumptions, including load, resource modeling, the ordering of Emergency Operating Procedures (EOPs), and the summer loss-of-load expectation (LOLE) target. Notably, ISO‑NE revised the summer LOLE target from 0.05 days/season to 0.1 days/season. The table below summarizes the estimated impact of each change.  

• Enhanced tie benefits allocation methodology: ISO-NE proposed to revise how it allocates total tie benefits across individual ties by using weighted averages instead of simple averages. Under the proposed approach, ISO-NE would weigh each interconnection scenario based on the likelihood of that scenario occurring, rather than treating all scenarios as equally likely. This change would not affect the total STB values, which would remain 1,795 MW in summer and 555 MW in winter.

• Revised frequency of tie benefits studies: ISO-NE proposed to calculate STB every three years, rather than annually

Next Steps 

Looking ahead, ISO-NE plans to continue to work on CAR-SA accreditation and market design through the beginning of Q2 2026. After that point, ISO-NE will finalize its proposals by identifying necessary tariff changes. The next Markets Committee and Reliability Committee sessions are scheduled for February 10 and February 12, respectively. 

NEPOOL TC votes to approve Order 2023 conforming changes pertaining to equivalent Capacity Network Resource Capability 

On January 21, 2026, ISO-NE provided an updated presentation to the NEPOOL Transmission Committee (TC) (see agenda) summarizing its proposal to formalize the concept of equivalent Capacity Network Resource Capability (CNRC) and address how equivalent CNRC is established, managed, and reduced. As last discussed in NE Flash 25-51, CNRC would become a standardized measure of deliverability for resources not subject to ISO‑NE Interconnection Procedures (e.g., Distributed Energy Capacity Resources and Active Demand Capacity Resources). This measure would ensure that all capacity resources, whether transmission- or distribution-connected, are subject to consistent deliverability accounting.

However, as discussed in NE Flash 23-31, FERC Order No. 2023 (Order 2023) required all independent system operators (ISOs) and regional transmission organizations (RTOs) to adopt generator interconnection process reforms aimed at addressing interconnection queue backlogs, and as part of its compliance, ISO-NE shifted deliverability assessments to its interconnection process. As a result, ISO‑NE needs new, conforming tariff provisions to determine equivalent CNRCs for capacity resources not subject to its Interconnection procedures. 

In this presentation, ISO-NE outlined minor adjustments to its previously presented proposal. These changes were largely ministerial in nature and involved ensuring different tariff sections are internally consistent with regard to their treatment of CNRC. Moreover, ISO-NE proposed an effective date to implement its CNRC-related tariff changes of May, 2026, following a FERC filing in March 2026. The updated (redlined) tariff sections are accessible as follows:

• 2026-01-21 TC A02 Order No. 2023 Related Changes – Section II.48.3 Redlines
• 2026-01-21 TC A02 Order No. 2023 Related Changes – Section II.48.4 Redlines
• 2026-01-21 TC A02 Order No. 2023 Related Changes – Section II.48.5 Redlines

Following the presentation, the TC voted to approve ISO-NE’s proposal. Looking ahead, the NEPOOL Participants Committee is scheduled to vote on the proposed tariff revisions at its meeting on February 5. 

NEPOOL TC considers Asset Condition Reviewer framework 

On January 21, 2026, at the NEPOOL Transmission Committee (TC) meeting (see agenda), ISO-NE provided a presentation concerning its Asset Condition Reviewer Key Project. 

Background 

As discussed in NE Flash 24-43, in February 2023, the New England States Committee on Electricity (NESCOE) sent an initial memorandum to the New England Transmission Owners (NETOs) recommending enhancements to the asset condition project process to address ballooning costs and a lack of transparency. In a July 2023 follow-up memo, NESCOE attached more specific recommendations. In August 2023, the NETOs sent a reply committing to process enhancements, which include Asset Condition Project Presentation Guidelines, an Asset Condition Database, and an Asset Condition Process Guide. As discussed in NE Flash 25-18, the asset condition process in New England is also under scrutiny as part of a broader Complaint proceeding before FERC targeting “local” transmission planning tariffs. 

As discussed in NE Flash 25-36, with stakeholder support, ISO-NE has agreed to take on the role of an “Asset Condition Reviewer,” an independent “non-decisional technical expert and advisor” to the NETOs, the states, and other stakeholders for proposed asset condition projects. As discussed in NE-Flash 25-43, in October 2025, ISO-NE provided an update to the Planning Advisory Committee (PAC) and solicited feedback on key topic areas.

Presentation 

In its presentation, ISO-NE summarized stakeholder feedback, noting unified support of transparent, early-stage reviews that provide actionable outputs and include alternatives and “right-sizing” analysis, but differing opinions on governance. ISO-NE also noted that creating the role would require changes to its Tariff and to the Transmission Operating Agreement (TOA) and proposed publishing an Asset Condition Reviewer Planning Guide. 

Looking ahead, ISO-NE noted that it expects to establish the role effective January 2027. ISO-NE will continue stakeholder discussions on this topic at each monthly TC meeting leading up to voting on the proposal at the June 24, 2026, TC meeting and the August 6 Participants Committee meeting. 

Back to Headlines

Massachusetts

In proceeding on exemption of the Town of Tewksbury zoning by-laws to allow the construction of 125 MW BESS; Joint Intervenors file a Motion for Partial Summary Decision; Town requests extension to file testimony by Feb. 6

As discussed in previous flash updates (NE Flash 25-48, NE Flash 25-15), the Hillman Energy Center, LLC (Hillman), a subsidiary of East Point Energy, is seeking an exemption from the Town of Tewksbury’s zoning bylaws (Bylaws) for its proposed 125 MW 4-hour duration Battery Energy Storage System (BESS) of the same name.

On January 13^th, 2026, the Joint Intervenors (adjacent landowners) filed a Motion for Partial Summary Decision, arguing that the Massachusetts Energy Facilities Siting Board (EFSB), which is overseeing the exemption request, lacks the authority to grant an exemption to Section 5.6 of the Bylaws, which governs any development within the Town’s groundwater protection district. The Joint Intervenors argue that because the proposed project site is within an approved wellhead protection area, as set forth by the Massachusetts Department of Environmental Protection (DEP), under Section 5.6 of the Bylaws a review of the planned facility and any required groundwater protection measures is not only set forth by the Town of Tewksbury, but is required by state and federal law. 

The Joint Intervenors request that EFSB issue a Partial Summary Decision acknowledging the EFSB’s lack of authority over Section 5.6 of the Bylaws. We note that this would not prevent EFSB from granting Hillman an exemption from other zoning requirements laid out in the Bylaws. 

Back to Headlines 

Connecticut 

PURA opens NWS Process Cycle 2 docket; Motions to intervene due Feb. 6 

On January 23, 2026, the Connecticut Public Utilities Regulatory Authority (PURA) opened Docket 26-08-08 to serve as the administrative record for PURA’s second annual Non-Wires Solutions (NWS) Process Cycle for electric distribution companies (EDCs) in Connecticut, i.e., Eversource Energy and United Illuminating Company. The proceeding will review the EDCs’ February 2026 data and identify distribution system needs, determine which traditional wires-based grid upgrades may be deferred or avoided through competitive NWS solicitations, and evaluate compliance with the approved NWS process and design documents. Stakeholders seeking participant status must file a Motion to Intervene by February 6. 

PURA issues Draft DG program successor study; comments due Feb. 4 

On January 21, 2026, in Docket No. 25-02-14, the Connecticut Public Utilities Regulatory Authority (PURA) issued a Draft Legislative Report recommending successor renewable energy programs. If adopted as drafted, the Report would recommend that the Connecticut General Assembly pass legislation in the 2026 Session to enable successor programs, noting that the current tariff programs are scheduled to sunset in 2027. PURA recommended transitioning Connecticut’s Nonresidential Renewable Energy Solutions (NRES) and Shared Clean Energy Facilities (SCEF) programs from competitive solicitation to a standard offer format. PURA would also recommend that the legislature reinstate PURA’s authority to establish programs for front-of-meter (FTM) distributed energy storage. 

PURA requested that stakeholders submit written comments on the Draft Report by February 4, at 4:00 pm. 

We will provide a more detailed summary of the recommendations in an upcoming Flash Update. 

Back to Headlines 

Maine 

EUT Committee to hold Jan. 29 work sessions on utility RTO participation, portable solar and BESS, community solar; public hearing on concept draft Feb. 2 

On January 23, 2026, the Maine Legislature’s Joint Committee on Energy, Utilities, and Technology (EUT Committee) scheduled work sessions and a public hearing on January 29 and February 2, respectively. We summarize the activities below: 

Jan 29 Work Sessions (11:00 am, 1:00 pm) 

• LD 2038 – An Act to Require Maine Transmission and Distribution Utility Participation in a Regional Transmission Organization: If enacted, this Bill would require transmission and distribution utilities to participate in an RTO, exempting consumer-owned utilities and Northern Maine utilities served by  the Northern Maine Independent System Administrator (NMISA). The Bill’s preamble notes that utilities that voluntarily join an RTO may receive a FERC-authorized bonus return on equity on transmission assets, and that this adder can increase transmission charges paid by Maine ratepayers. 
• LD 1730 – An Act to Make Small, Portable, Plug-in Solar Generation Devices Accessible for All Maine Residents to Address the Energy Affordability Crisis. We note that the Bill was a concept draft carried over from the 2025 legislative session. As amended, the Bill would establish a statutory framework allowing retail electricity customers to install and operate one or more plug-in PV or plug-in battery systems to offset on-site electricity consumption, with combined inverter output capped at 1,200 watts AC. The systems would not be eligible to participate in the net energy billing (NEB) program. The Bill would also exempt such systems from utility notification and interconnection requirements. Lastly, the Bill would require that a property with four or more residential units that begin construction after December 1, 2026, include at least one outdoor individual branch circuit per unit. We note that this bill was carried over from the 2025 legislative session as a concept draft. 
• LD 1966 – An Act to Improve Access to Community Solar Programs in the State. Last discussed in NE Flash 25-45. If enacted as amended, this Bill would require utilities to disclose all administrative charges on customer bills and authorize refunds to customers or ratepayers for overcollections in administrative charges. The Bill would allow new front-of-the-meter (FTM) resources to participate in NEB if the facility is either owned by its offtaker or by a cooperative organization. The Bill would also require the Electric Ratepayer Advisory Council to recommend methods to support low- and moderate-income access to community solar, require utilities to offer consolidated billing in net crediting format for distributed generation by January 1, 2028, and require utilities to disclose all public policy charges on customer bills. 

Feb 2, Public Hearing (1:00 pm)

• LD 307 – An Act Regarding Energy, Utilities and Technology: Introduced as a concept draft. We will provide coverage when it is available.

EUT work sessions and public hearings will be held in Room 211, Cross Office Building. 

FERC approves Versant Wholesale Distribution Access Tariff 

On January 16, 2026, in Docket No. ER26-528, FERC issued an Order accepting the revised Wholesale Distribution Access Tariff (WDAT) submitted by Versant Power (Versant). The revised WDAT went into effect January 17, as requested. 

As last discussed in NE Flash 25-48, on November 17, 2025, Versant submitted a revised WDAT after FERC rejected its initial filing. In its earlier Order, FERC found that Versant’s original tariff impermissibly included transmission service charges applicable to distribution-connected electric storage systems (ESS), rendering the tariff inconsistent with Order No. 841, which requires that storage resources participating in wholesale markets not be assessed transmission charges when dispatched by an Regional Transmission Operator or Independent System Operator. 

FERC found that Versant’s revised tariff cures these deficiencies. The approved Rate Schedule applies to electric storage facilities interconnected to Versant’s Bangor Hydro District distribution system when those facilities are charging for later sale into the ISO-NE wholesale energy or ancillary services markets. The Rate Schedule includes a Customer Charge, Distribution Energy Charge, and Distribution Demand Charge, and reflects the same customer and distribution charges approved by the Maine Public Utilities Commission in Versant’s retail tariffs. 

No protests or interventions were filed in response to the November 17, 2025, filing. 

Back to Headlines 

New Hampshire 

House STE and Senate ENR Committees to hold hearings on multiple renewable energy bills, Feb. 2 through Feb. 10 

Recently, multiple New Hampshire House of Representatives and Senate Committees have scheduled public hearings on renewable energy bills for February 2 through February 10, 2026. We summarize the activities, by date, below: 

Feb. 2 House Science, Technology, and Energy (STE) Public Hearing (9:00 am – 10:29 am) 

At the hearing, the House STE Committee will discuss HB 1775 – relative to utility ownership of natural gas and nuclear power generation facilities.

Feb. 2 House STE Public Hearing (1:00 pm – 4:30 pm) 

At the hearing, the House STE Committee will discuss HB 1742 – relative to the protection of customer-generators from inadvertent enrollment in third-party electricity supply programs. 

Feb 3 House STE Public Hearing (10:00 am – 2:59 pm) 

At the hearing, the House STE Committee will discuss: 

• HB 1028 – relative to the definition of renewable generation facility. 
• HB 1290 – relative to customer energy storage. 

Feb 3 House STE Executive Session (3:00 pm – 4:30 pm) 

At the Executive Session, the House STE Committee may act on the following bills: 

• HB 1721 – relative to limiting new system enrollment and adjusting compliance payments under the renewable portfolio standard program. 
• HB 1739 – relative to energy infrastructure, economic development, and workforce training for large-scale data facilities. 

Feb. 10 Senate Energy and Natural Resources (ENR) Public Hearing (9:00 am – 12:00 pm) 

At the hearing, the Senate ENR Committee will discuss SB 597 – relative to utility rate increases to inflation-adjusted thresholds and performance incentive metrics for utilities. 

We will summarize these bills in upcoming coverage of the hearing. 

House STE Committee to hold public hearings on Bills allowing BESS net metering participation and reliable energy sources, Jan. 29 

During the week of January 19, 2026, the New Hampshire House of Representatives’ Committee on Science, Technology and Energy (STE Committee) scheduled a public hearing to be held on January 29, 2026, from 9:30 am to 3:30 pm to consider the following Bills related to clean energy: 

• HB 1718 – relative to authorizing energy storage in connection with net metering. Scheduled for discussion at 2:00 pm. 
• HB 1455 – relative to the criteria for reliable energy sources. Scheduled for discussion at 3:00 pm. 

The hearing will be held in the Granite Place Building, Room 158. We will summarize these Bills in upcoming coverage of the hearing.

Grid Modernization Advisory Group to meet Feb. 3

The New Hampshire Department of Energy’s Grid Modernization Advisory Group (GMAG) has scheduled a public meeting for February 3, 2026 at 10:00 am. According to the posted agenda, the meeting will review GMAG’s 2025 Report (discussed in NE Flash 26-3) and develop follow-up actions based on the Report’s findings. The Report highlighted transactive energy, improved price signals, and expanded access to temporal pricing as key tools to enable greater integration of renewables while maintaining grid reliability. The Report emphasized the role of both short- and long-duration energy storage in balancing renewable generation and addressing reliability challenges. 

Back to Headlines 

New York 

CCSA study finds 20 GW by 2035 distributed solar and 3.7 GW storage target will result in $1 billion of annual energy savings 

On January 14, 2026, the Coalition for Community Solar Access (CCSA) announced the release of a report, titled Sunlight and Storage into Savings. The Report was prepared for CCSA by Synapse Energy Economics (Synapse). In the Report, Synapse found that reaching increased solar and storage deployment targets would reduce annual residential electric costs by $87 per year for upstate customers and $46 per year for downstate customers, totaling $1 billion per year in avoided energy costs. Synapse also found that the policy change would result in $947 million per year in avoided greenhouse gas (GHG) costs by 2035. Synapse modeled its results by comparing the following two scenarios: 

CCSA noted that Synapse’s policy case is partially based on S6570: The Accelerate Solar for Affordable Power (ASAP) Act, if enacted, the S6570 would set a goal to deploy 20 GW of distributed solar by 2035. The Bill would also: 

• Direct electric distribution companies (EDCs) to publicly report interconnection costs for distributed generation (DG) facilities 
• Allow DG facilities to self-perform certain interconnections and distribution system upgrades 
• Direct the New York Public Service Commission (PSC) to consider proposals to limit interconnection cost overruns 
• Direct EDCs to file flexible interconnection proposals with the PSC 
• Create a “distribution system investment program” with the goal of proactively planning distribution system upgrades that facilitate the interconnection of DG 

We note that S6570 would not increase storage deployment targets as contemplated in the Synapse study. 

NYISO responds to stakeholder requests, discusses modifications to its Order 2023 pro forma interconnection agreement process 

On January 20, 2026, at the joint NYISO Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group (ESPWG) meeting (see agenda), NYISO provided an updated presentation on proposed enhancements to the cluster study process and responded to stakeholder-requested modifications to its pro forma interconnection and construction agreements. 

As last discussed in NY Flash 26-2, NYISO is in the process of conducting the transition cluster study, its first interconnection cluster study pursuant FERC Order No. 2023 (Order 2023). As discussed in NY Flash 23-31, Order 2023 required independent system operators (ISOs) and regional transmission organizations (RTOs) to transition to a first-ready, first-served cluster study process and implement certain changes to the large-scale facility interconnection process intended to increase the speed and certainty of the process. 

In its presentation on proposed cluster study enhancements, NYISO responded to stakeholder feedback on the proposed enhancements (discussed in NY Flash 26-2), indicating which stakeholder suggestions it plans to address, and which it will not consider at this time. The key reforms NYISO plans to address in 2026 are:

• Providing a pathway for conditional Phase 1 entry for physically infeasible projects
• Increasing training for Interconnection Customers
• Harmonizing Phase 1 cost estimate methodology among Transmission Owners
• Increasing consistency between Phase 1 Study reports and cost estimate assumptions, including increasing the consistency of study report formats
• Communicating and documenting mandatory vs. optional data inputs and clarifying interconnection request information requirements
• Making Interconnection Request forms available prior to the Application Window opening

In its presentation on its pro forma interconnection and construction agreements, NYISO highlighted stakeholder feedback it received and provided bulleted responses. NYISO: 

• Maintained that the current tariff-required interconnection agreement tendering and negotiating timelines (in which NYISO must tender the interconnection and construction agreements as soon as practicable, and that affected parties negotiate such agreements within six months, subject to parties’ agreement to extend this period) remains a reasonable approach. 
• Did not support a tariff-prescribed 30-day timeframe for tendering agreements, arguing that the increasing and uncertain volume of agreements that need to be tendered and the uncertainty about the number of projects that will have agreements makes this impractical 
• Explained that delays in the interconnection negotiation process are generally the result of post-study project modifications and the high volume of projects negotiating agreements 

Looking ahead, NYISO noted that it plans to bring proposed revisions to its pro forma interconnection agreement to a future TPAS meeting in February and will seek NYISO Board of Managers approval in April or May 2026. We note that the next TPAS meeting is scheduled for February 3. 

NYISO presents preliminary base case results for 2025-2044 System & Resource Outlook 

On January 20, 2026, at the Electric System Planning Working Group (ESPWG) meeting (see agenda), NYISO presented an update to its 2025-2044 System & Resource Outlook (SRO). As last discussed in NY Flash 25-51, the SRO is a biennial (once every two years) report summarizing the recent and ongoing assessments, evaluations, and plans of the Comprehensive System Planning Process, including a 20-year projection of NYISO’s demand, generation, and transmission. The 2025-2044 SRO will include three policy reference cases: the Base case, Contract case, and Policy case. 

At the meeting, NYISO presented preliminary results for the Base case. The Base Case uses the 2025 NYISO Gold Book Baseline demand forecast and aligns generation and transmission assumptions with NYISO’s most recent reliability study (discussed in NY Flash 25-48) to run production cost modeling. See the preliminary results below:

NYISO provided the following summary of results (listed verbatim): 

• Trends for key metrics such as generation, net imports, and locational based marginal pricing (LBMP), are primarily driven by load growth in New York 
• Generation in downstate zones and imports from neighboring systems primarily serve the increased load through the study period  

• Notably, New York Control Area (NYCA) load zones F, G, and J experience increased generation 

• Increased load growth in New York and neighboring systems, evolving load patterns, and reduced reserve margins result in reduced net interchange and increased reliance on internal NYCA generation 

NYISO expects to provide preliminary results for all cases in Q1 2026 and release the Draft and Final SRO Reports in Q2 2026. 

NYISO initiates project to explore automatic resale of surplus UCAP 

On January 21, 2026, at the joint meeting (see agenda) of the Installed Capacity (ICAP) Working Group (ICAPWG), Market Issues Working Group (MIWG), and Price Responsive Load Working Group (PRLWG), NYISO provided a presentation on proposed tariff revisions to enable the automatic resale of surplus Unforced Capacity (UCAP). 

Under the current market structure, NYISO cannot resell surplus UCAP without an affirmative action from Market Participants (MPs), which results in unsold surplus UCAP. This generates excess UCAP charges to load that, in turn, may create higher market-clearing prices. NYISO proposed tariff revisions that would automatically create Zero Dollar Offers (ZDOs) in an ICAP Spot Market Auction to resell any surplus UCAP that exists after the deadline for UCAP certification. NYISO plans to present tariff revisions at a February ICAPWG meeting, with Business Issues Committee and Markets Committee votes expected in Q1-Q2 2026.

NY-BEST publishes whitepaper, calls for immediate relief regarding storage interconnection restrictions implemented by ConEd

On January 13, 2026, the New York Battery and Energy Storage Technology Consortium (NY-BEST) submitted a Call for Immediate Relief alongside a whitepaper in response to New York State Department of Public Service (DPS) Petition In the Matter of Energy Storage Deployment Program (Case Number 18-E-0130). 

The Call for Immediate Relief asks for the lifting of newly imposed restrictions on distributed energy storage interconnections and discusses the impacts on development. 

The Whitepaper, titled Unlocking Distributed Energy Storage to Address Reliability Needs in New York City, asserted that this is a reliability gap in New York, claimed that current processes are failing to resolve the reliability gap, and suggested ways to better incentivize and structure distributed battery energy storage participation. The Whitepaper concluded that energy storage is proven as the best path forward to address New York City’s reliability concerns, and therefore, taking three steps, listed verbatim, will enable energy storage: 

1. Immediately initiate a six- to twelve-month stakeholder-based, holistic process to reform interconnection and market rules, in line with Core Principles described in the Whitepaper 
2. Ensure utilities are appropriately incentivized to implement interconnection and market reform designed to ensure cost-effective outcomes for ratepayers 
3. In coordination with the new Reliability proceeding, reform utility grid planning rules to ensure energy storage is recognized as a flexible, controllable reliability resource, unlocking its ability to defer or eliminate costly infrastructure investments while supporting the State’s electricity reliability needs 

On January 14, 2026, Consolidated Edison of New York (ConEd) submitted a Notice on Standardized Interconnection Requirements for Energy Storage, which discusses the impact of Battery Energy Storage System (BESS) development in New York City on the ConEd system. The ConEd Notice suggested that the magnitude of increase in BESS projects creates new dynamics that threaten system reliability (such as concentrated overnight load), which is the cause the new interconnection restrictions. 

Back to Headlines 

PJM RTO 

PJM publishes 2026 load forecast report; Near-term load growth slightly tempered relative to 2025 forecast 

On January 14, 2026, PJM Interconnection, LLC (PJM) issued a press release announcing the publication of its 2026 Long-Term Load Forecast Report. Subsequently, on January 23, PJM provided a Presentation reviewing the Report to the Load Analysis Subcommittee (see agenda). We note that the PJM Resource Adequacy Planning Department issues an updated load forecast annually; we summarized the 2025 Long-Term Load Forecast Report in PJM Flash 25-5, and we previously briefly mentioned the 2026 Long-Term Load Forecast Report in our coverage of PJM’s large load integration plan in PJM Flash 26-3. 

The Report includes a 20-year forecast of peak loads, net energy, distributed solar generation, plug-in EVs load, and battery storage capacity for each PJM zone, locational deliverability area (LDA) and the total RTO. Compared to the 2025 load forecast, the 2026 forecast anticipates lower peak demand through 2032 due to updates to PJM’s EV and economic forecasts, as well as revised modeling of data centers and other large loads. The following graphic displays PJM’s forecast summer and winter peak loads through 2046: 

The 2025 forecast predicted an annual load growth rate of 2% over a 20-year horizon, whereas the 2026 forecast predicts an annual load growth rate of 2.4% over 20 years. Interestingly, this increase is driven by higher load expectations entirely after 2032, as the near-term load growth forecast (before 2032) was reduced in this year’s forecast. The softened near-term load growth assumptions are the result of tempered EV, large load, and economic growth assumptions. PJM’s figures indicate that it’s behind-the-meter (BTM) solar forecast—which acts as a load reducer—was not substantially revised between the 2025 and 2026 load forecast reports. 

We note that PJM provided the data tables associated with its 2026 load forecast report on the load forecast development process website. 

PJM submits proposed Tariff revisions to comply with certain directives in FERC Co-Location Order; Comments due Feb. 10 

On January 20, 2026, in FERC Docket No. ER26-1088, PJM Interconnection, LLC (PJM) submitted proposed Tariff revisions to comply with certain directives in FERC’s December 18, 2025 Order (the Co-Location Order) in Docket No. EL25-49, the show-cause proceeding on co-locating large loads (e.g., data centers) at generating facilities in the PJM footprint. 

We summarized the Co-Location Order in PJM Flash 25-51. As it relates to this filing, the Order directed PJM to, within 30 days, submit proposed Tariff revisions that: 

• Allow Interconnection Customers seeking to use a new generation facility to serve a Co-Located Load to request “only the minimum level of interconnection service it deems necessary to effectuate its Co-Location Arrangement,” which may be below the generator’s maximum output 
• Clarify Interconnection Customers seeking to use a new generating facility to serve a Co-Located Load may use existing procedures to accelerate a new service request if they satisfy the Tariff criteria (i.e., no cost allocation for Network Upgrades and no further studies required) 
• Clarify Interconnection Customers seeking a Co-Location Arrangement have the same opportunity to use Provisional Interconnection Service and Surplus Interconnection Service as other new Interconnection Customers 

PJM noted that the proposed Tariff revisions were developed to comply with the above directives and requested an effective date as of the date FERC accepts the filing. According to FERC’s Combined Notice of Filings, the deadline for stakeholder comment is February 10, 2026. 

Relatedly, by February 16, PJM must submit: 

• Another filing to comply with other directives in the Co-Location Order (e.g., revisions to limit the ability of behind-the-meter (BTM) generation participants to net their usage for the purpose of transmission service charges) 
• An initial brief on two new transmission services (i.e., Firm Contract Demand and Non-Firm Contract Demand) 

In appeal of FERC Order rejecting Complaint of PJM Petition to revert 2024/2025 capacity auction results, DC Circuit vacates and remands 

On January 13, 2026, in Docket No. 24-1353 (Maryland Office of People’s Counsel, et al. v. FERC), the U.S. Court of Appeals for the District of Columbia (DC) Circuit issued an Opinion vacating FERC’s July 2024 Order (in Docket No. EL24-104), rejecting the Complaint submitted by the PJM Load Parties. 

The PJM Load Parties include American Municipal Power, Inc., Delaware Division of the Public Advocate, Delaware Energy Users Group, Delaware Municipal Electric Corporation, Delaware Public Service Commission, Maryland Office of People’s Counsel, Maryland Public Service Commission, and Old Dominion Electric Cooperative. 

The Complaint challenged the PJM Interconnection, LLC (PJM) Petition for Declaratory Order, which requested that FERC confirm that PJM should revert the 2024/2025 Base Residual Auction (BRA) results and direct PJM to re-run its 2024/2025 Third Incremental Auction. As last discussed in PJM Flash 24-23, PJM made the filing in response to a U.S. Court of Appeals for the Third Circuit Opinion deeming a mid-auction change to a parameter—that caused “artificially” inflated cleared prices in the Delmarva Power South locational deliverability area—a violation of the “filed rate doctrine,” a legal principle that prohibits retroactive ratemaking. Consistent with FERC’s rejection of the Complaint, FERC granted the Petition. 

In its Opinion, the DC Circuit noted that the Third Circuit’s ruling was based on FERC’s legal authority under Federal Power Act (FPA) Section 205, not Section 206, which was the basis of the Complaint. Accordingly, the DC Circuit remanded the case, finding that FERC failed to consider whether its authority under FPA Section 206 could permit the mid-auction correction. We note that FERC may still reject the Petition in an order on remand. 

Market Implementation Committee reviews proposals to improve DR performance, focus on appropriate non-performance penalty for Non-PAI events 

On January 20, 2026, at the Market Implementation Committee (MIC) meeting (see agenda), PJM Interconnection, LLC (PJM), Voltus, and Monitoring Analytics, PJM’s Independent Market Monitor (IMM), provided presentations on proposed solutions to improve Load Management and Price Responsive Demand (PRD), together Demand Response (DR), resource performance. 

As noted in the related Problem/Opportunity Statement and Issue Charge, the weighted average performance for Load Management during the Summer 2025 season was just 67%, well below the 103% “test results” for the 2024/2025 Delivery Year. As such, PJM is assessing whether the current “incentives and penalties [are] insufficient to ensure performance.” 

In its Presentation, PJM proposed to establish a non-performance penalty rate for Non-Performance Assessment Interval (PAI) events that is equal to 50% of the penalty rate for PAI events, effective beginning for the 2028/2029 Delivery Year. PAI events trigger during system emergency conditions. Non-PAI events are similar but are triggered during less severe emergency conditions; while PJM can (and does) dispatch DR resources during Non-PAI events, those resources are not subject to non-performance penalties. 

Voltus proposed to calculate a penalty rate for Non-PAI events that essentially uses the formula for calculating the penalty rate for PAI events but with differentiated parameters, including a discount factor that reflects the “relative ‘criticality’” of Non-PAI events. Representative penalty rates are shown in the table below . 

Voltus also proposed to provide for an overperformance bonus during Non-PAI events. 

The IMM proposed to (i) establish a penalty rate for Non-PAI events equal to the penalty rate for PAI events and (ii) in the event of nonperformance, withhold daily capacity payments in the amount of the shortfall “from the time of the last successful performance, or test, to the next successful performance.” The IMM also proposed to adopt capacity accreditation for DR resources. 

Back to Headlines 

New Jersey 

On first day in office, Gov. Sherrill issues Executive Orders: issuing residential retail electric rebates, expediting renewable energy programs and procurements, streamlining permitting, and exploring reforms for nuclear power and EDCs 

On January 20, 2026, New Jersey Governor Mikie Sherrill (D) issued a series of Executive Orders (EOs) on energy issues. The EOs were issued on the first day of her term, and followed a campaign during which energy topics, particularly energy affordability, were a major focus. One of the hallmarks of the Sherrill campaign’s energy policy proposals was a plan to “freeze utility costs for families” for one year, as last discussed in PJM Flash 25-48. Also while on the campaign trail, Gov. Sherrill also proposed to increase in-state generation in response to historically high Base Residual Auction (BRA) results, and overall criticism of PJM Interconnection, LLC (PJM) (last discussed inPJM Flash 25-51). 

We summarize the EOs below. 

Executive Order No. 1: 

• Orders the New Jersey Board of Public Utilities (BPU) to issue Residential Universal Bill Credits (RUBCs) to offset rate increases for residential customers by July 1, 2026. RUBCs were previously utilized by the BPU in August of 2025 
• Requires the BPU, the New Jersey Department of Environmental Protection (DEP), and the New Jersey Economic Development Authority to confer on using Regional Greenhouse Gas Initiative (RGGI) revenue for ratepayer relief, and issue a public statement within 30 days of the EO on plans for ratepayer relief in the 2026-2028 RGGI Strategic Funding Plan, and whether to amend that plan 
• Requires the BPU to review the system benefits charges (SBCs) on electric bills and the budget for the Clean Energy Program 
• Orders the BPU to issue a “true-up budget” for the Clean Energy Program by May 1, 2026 
• Directs the BPU to “consider pursuing a pause, abeyance, or modification of” any proceeding in which an electric distribution company (EDC) is seeking approval for rate increases or cost recovery, to the extent permitted by law 

Orders the BPU to, within 180 days of the EO (July 19, 2026), issue a study on potential modernization of the EDC business model, including expansion of performance-based ratemaking,  

Executive Order No. 2:

• Directs the BPU to, within 45 days of the EO (March 6, 2026), issue a solicitation for solar and solar plus storage resources, and, within 270 days of the EO (October 17, 2026), issue project awards.
• Directs the BPU to implement recently-enacted law P.L.2025, c.135. As last discussed in PJM Flash 25-38, the BPU already announced its intent to implement this Law, which directed the BPU to increase the New Jersey Community Solar Energy Program (CSEP) annual procurement target from 150 MW per year to an aggregate target of 3,000 MW by 2029.
• Orders the BPU to utilize the Garden State Energy Storage Program for transmission-connected battery energy storage systems (BESS) to, within 45 days of the EO (March 6, 2026), initiate a Tranche 2 solicitation for the Transmission Fixed Incentive and, within 90 days of the EO (April 20, 2026), launch Phase 2 of the program for the distributed segments of the program. Phase 2 shall include a tranche of capacity for EDCs to “develop to support interconnection of distributed energy resources and grid stability.” It is unclear from this language whether the EDCs will develop the resources directly, develop interconnection capacity, or both.
• Requires the BPU to, within 180 days of the EO (July 19, 2026), develop a virtual power plant program , with a goal of reducing system peak from aggregated behind the meter resources.
• Directs all “relevant state entities” and, only with respect to natural gas facilities, DEP to:

• Identify what rules are involved in the permitting of energy generation or “grid stabilization” projects that, if waived, would expedite the permitting process without endangering public health, safety or environmental protection. The Governor will then consider issuing an order permitting the waiver of said relevant rules
• “Prospectively and liberally” waive rules identified to the extent possible

• Requires the BPU, within 14 days of the EO (February 3, 2026), to direct EDCs to submit memoranda/filings within 30 days after the DPU order (at latest March 5, 2026), addressing interconnection and hosting capacity issues, including:

• The status of compliance with renewable interconnection rules
• Opportunities to modify or waive interconnection regulations to improve the speed of interconnection
• How EDCs should improve hosting capacity maps and ensure clean energy projects can consistently interconnect to 34.5 kV distribution lines
• Identification of constrained circuits that should be upgraded to support and accelerate distributed energy resource (DER) interconnections

• Orders the BPU, within 45 days (March 6, 2026), to develop policies/proposals/RFIs/reports on interconnection of “large load” customers, including tracking duplicative interconnection requests across utility territories to reduce “ghost load”.
• Directs the BPU to consider notifying DEP that extending the June 1, 2027 compliance deadline for new emissions requirements for covered generating units is necessary for transmission/distribution reliability.
• Establishes an interagency Nuclear Power Task Force to coordinate a strategy for the development of new nuclear generation facilities in New Jersey, including coordination with the federal government and other states as needed.

Executive Order No. 5

• Establishes a Cross-Agency Permitting Team (under the Strategic Initiatives & Economic Opportunity Office within the Office of the Chief Operating Officer). Directs the Cross-Agency Permitting Team to reduce delays, costs, and improve transparency/accountability by (to the extent consistent with law):

• Collecting permitting time data across Executive Branch departments and agencies, identifying bottlenecks, and coordinating efficiency fixes
• Developing standardized permitting frameworks, timelines, and best practices across agencies
• Creating and managing a Permitting Dashboard
• Evaluating permitting costs and identifying reforms that could improve affordability
• Identifying and proposing legislative changes to permit processes

• Requires every Executive Branch department and agency, within 90 days (April 20, 2026), to submit a Permit Catalog to the Cross-Agency Permitting Team covering all permits it issues
• Directs the Cross-Agency Permitting Team to develop presumptive permitting “shot clocks” (however, these shot clocks would not be enforceable)
• Creates a Regulatory Simplification Team (under the Operational Performance Office within the Office of the Chief Operating Officer) to develop proposals and implement reforms to state regulatory structures to reduce project delays and cost.

Back to Headlines

Maryland

Stakeholders submit comments following public hearing on energy storage procurement design, expressing concerns regarding consumer protection and cost recovery

As discussed in PJM Special Flash 26-2.1, in Case No. 9715, the Maryland Public Service Commission (PSC) invited stakeholders to submit written comments by January 16, 2026. The comments  provide feedback that will help shape  the direction of the energy storage initiative (Case No. 9715), which is meant to establish a competitive energy storage procurement program with annual deployment targets. The following stakeholders filed comments: 

• Baltimore Gas and Electric Company (BGE) 
• Edison Electric Institute (EEI) 
• Honeywell International Inc. (Honeywell) 
• Maryland Energy Administration (MEA) 
• Office of People’s Counsel (OPC) 
• Office of Staff Counsel (OSC) 
• Potomac Electric Power Company and Delmarva Power & Light Company (PHI) 
• Solar Energy Industries Association and Chesapeake Solar and Storage Association (SEIA and CHESSA) 

We summarize comments by topic area, as follows:

• Cost Recovery and Affordability: BGE and PHI argued that regulatory asset treatment is necessary to manage near-term bill impacts and allow timely deployment of storage projects. PHI acknowledged that total nominal costs may be higher over time but maintained that spreading cost recovery avoids intense bill pressure in the early years of operation and preserves usefulness of future PSC review in a base rate case. PHI and BGE raised concerns about ensuring comparable rate treatment between utility-owned and third-party storage proposals. BGE asserted that without assurance of recovery for operations, maintenance, and depreciation expenses associated with the storage programs, it cannot proceed with implementation. In support of regulatory asset treatment, EEI emphasized that regulatory asset treatment does not pre-approve costs and allows for subsequent prudency review, while providing a stable framework for achieving statutory storage targets. By contrast, OPC argued that regulatory asset treatment would delay bill impacts and increase total customer costs by financing project costs that would otherwise be recovered as incurred. OPC asserted that the utilities’ affordability arguments amount to bill smoothing rather than true cost reduction and are inconsistent with longstanding PSC practice under PURPA, where contract and administrative costs are treated as expenses rather than rate-based assets. MEA supported OPC’s position, and noted that allowing utilities to earn a full return on operations and maintenance expenses would weaken incentives for cost discipline and shift operational risk from shareholders to ratepayers.
• Utility Ownership Versus Competitive Procurement: BGE noted that its portfolio approach, which includes utility-owned storage, customer-sited programs, and third-party procurement aligns with the Next Generation Energy Act and supports diverse ownership structures. BGE argued that utility ownership can provide distribution system benefits while competitive solicitations and indexed credits can encourage third-party participation. Honeywell supported BGE’s approach and indicated its intent to participate under BGE’s proposed programs. OPC expressed concern that utility ownership, particularly where assets also participate in PJM Interconnection, LLC (PJM) markets, could shift market and performance risks to ratepayers. OPC urged the PSC to require a clear showing of unique customer benefits and safeguards to protect ratepayers. SEIA and CHESSA also raised concerns about exclusive utility ownership, particularly for customer-sited programs. They argued that monopoly access to rate-based revenue streams and customer data could disadvantage independent providers and increase costs over time. SEIA and CHESSA recommended competitive ownership models in which utilities provide screening, planning, and coordination while independent power providers own and operate storage assets where they function as supply-side resources.
• Procurement Design and the Role of Tariffs: Stakeholders diverged on whether near-term procurement should rely on competitive solicitations or tariff-based mechanisms. SEIA and CHESSA reiterated their preference for a grid-services tariff that provides a transparent price signal reflecting the full value stack of storage. They pointed to New York’s Value of Distributed Energy Resources (VDER) tariff as a potential model and stated that a tariff could reduce administrative complexity and accelerate deployment. OPC and MEA cautioned against adopting a standard-offer tariff in the near term; OPC stated that the utilities’ benefit-cost analyses are not sufficiently aligned to serve as the foundation for tariff pricing, and further argued that uncertainty around PJM load forecasting and capacity valuation could prevent tariff-based programs from delivering promised benefits to customers. MEA similarly warned that premature tariff adoption could decouple storage deployment from system need, expose ratepayers to undue financial risk, and lock in compensation levels before valuation frameworks are sufficiently developed. MEA supported a sequencing approach in which competitive, needs-driven procurements inform later tariff-based participation.
• PJM Market Participation and Capacity Value: BGE noted that its proposals rely on tangible, known value streams and that participation in PJM markets under FERC Order 2222 provides a clearer path to capacity value than alternatives dependent on changes to PJM load forecasting. SEIA and CHESSA disputed the view that direct market participation is the only viable path to achieving capacity value. They argued that distribution-connected storage can reduce utilities’ capacity obligations by modifying load during PJM coincident peaks and urged the PSC to work with PJM to recognize these reductions more quickly through explicit load forecast adjustments, acknowledging that mechanisms to accomplish this are still under development.

OSC filed comments following the in-person hearing held on January 7, 2026. OSC emphasized the importance of facilitating timely deployment of energy storage resources while protecting utility ratepayers from unjustified risks via cost caps, performance requirements, and enforceable remedies for non-performance, consistent with PSC Orders No. 91705 and 91812. OSC further asserted that PSC Order No. 91705 requires both bill impact analyses and program-specific equity assessments to be conducted. OSC noted that regulatory asset treatment would be granted on a limited and conditional basis to avoid an increase in customer costs. OSC supported recovery mechanisms such as situational surcharges with reconciliation for variable contract costs and narrowly tailored, time-limited deferrals. OSC cautioned against procurement structures that act as substitutes for PJM market participation, which could be perceived as a revenue backstop mechanism for developers, ultimately weakening market discipline and shifting market performance risks to ratepayers. OSC recommended approving BGE’s proposal with conditions to strengthen cost caps, verify non-wires alternative deferrals, and clarify dispatch priorities and treatment of market revenue treatment. OSC recommended approving PHI’s proposal with significant conditions to ensure enforceable performance accountability and enhanced equity analysis and reporting. OSC recommended deferring approval of the Potomac Edison Company’s proposal pending refiling to address compliance with the National Standard Practice Manual, demonstration of actionable grid value, and enforceable cost controls. 

Back to Headlines

Virginia

SCC Schedules May 18 evidentiary hearing on Dominion Energy VPP pilot program

On January 16, 2026, in Docket 2025-00211, the Virginia State Corporation Commission (SCC) issued an Order for Notice and Hearing scheduling a hearing to discuss the Virtual Power Plant (VPP) Pilot and 2025 Demand-Side Management (DSM) portfolio Applications submitted by Dominion Energy, Inc. (Dominion). The telephonic evidentiary hearing is scheduled for May 18, 2026, at 10:00 am. The hearing will be webcast here. Stakeholders interested in providing public comment can do so by filling out this form on or before May 11. 

As last discussed in PJM Flash 25-49, in December 2025, in SCC Docket 2025-00211, Dominion applied to establish a new VPP Pilot, and in Docket 2025-00210, Dominion applied to update its DSM portfolio. On the same day, Dominion filed a Motion to consolidate the two Applications into a single proceeding.

Dominion developed the proposed VPP Pilot pursuant to § 56-585.1:16 of the Code of Virginia, which requires Dominion to evaluate methods to optimize electric demand through VPPs and other technology applications. In the Application, Dominion proposed an 18-month pilot that would launch in Q1 2027, with plans for a permanent VPP program by 2030. In the Pilot, Dominion would aggregate demand-response and DSM programs through a Distributed Energy Resource Management System (DERMS) that enables real-time control of customer-owned technologies via third-party aggregators under a “bring-your-own-device” (BYOD) structure.

Dominion’s updated 2025 DSM portfolio included nine Phase XIV DSM programs, including the VPP pilot, and extend two Phase XI income and age-qualifying programs. Dominion proposed a cost cap of $220.6 million for the 2025 DSM programs, with the ability to exceed this cap by no more than 15%. 

Back to Headlines 

Indiana 

Indiana Legislative updates: Senate passes surplus interconnection service and nuclear permitting bills, House passes affordability bill, House Committee reports and energy zoning bills 

During the week of January 19, 2026,  the Indiana General Assembly took several actions on bills related to clean energy, which we summarize below: 

Passed Senate:

On January 22, 2026, the Indiana Senate passed SB 240: Surplus interconnection service in a 44-1 vote and referred it to the House for consideration. If enacted as amended, this Bill would: 

• Define surplus interconnection service (SIS) as the unused portion of an existing large-generator interconnection service agreement 
• Require electric utilities to file integrated resource plans (IRPs) that include an analysis of SIS for the purpose of considering it as a near-term capacity and energy resource in IRPs filed after December 31, 2029  

• Such plans must identify utility-owned sites with more than 25 MW of potential SIS. 
• Utilities may solicit information from third parties and include any viable third-party SIS opportunities received through that solicitation in the IRP 

As discussed in PJM Flash 26-3, on January 15, the Senate Utilities Committee reported SB 240 with an amendment in a 10-0 vote. 

On same day, the Senate passed SB 258: Nuclear facility permits by a 39-9 vote. If enacted, this Bill would repeal the State permitting framework for nuclear-powered generating facilities and nuclear fuel reprocessing plants. Specifically, it would remove the statutory requirement to obtain a permit from the Department of Environmental Management (DEM) before constructing, operating, or increasing the capacity of a facility and remove the Environmental Rules Board’s authority to adopt permit and operating rules. 

As discussed in PJM Flash 26-3, on January 15, the Senate Utilities Committee voted 7-3 to report SB 240. 

Passed House: 

On January 27, 2026, the Indiana House of Representatives voted 63-30 to pass HB 1002: Electric Utility Affordability. As discussed in PJM Flash 26-3, on January 20, the UET Committee voted 13-0 to report HB 1002 “do pass amend.” HB 1002 is a core piece of House Republican Leadership’s energy policy agenda for 2026. We note that the Bill passed the House with one roll call amendment. If enacted as passed, HB 1002 would: 

• Require utilities regulated by the Indiana Utility Regulatory Commission (IURC) to develop and offer an opt-in “levelized billing plan” to all active residential customer accounts, which would allow customers to pay electricity bills in equal monthly installments. 
• Allow the IURC to recommend that the Governor declare a state energy emergency as a result of economic depression, war, or natural disaster, during which the IURC can take certain actions with respect to electric rates, including rate freezes. 
• Prohibit electric utilities from disconnecting service to low-income residential customers on dates with a heat index of 95 degrees or greater. 
• Require regulated utilities to petition the IURC for approval of any change in its basic rates through a three-year, multi-year rate plan (MYRP), beginning in 2027.  

• The IURC would be required to establish base rates for the first year using backward-looking data, while rates for the second and third rate years would be established using current or forward-looking data incorporating performance incentive mechanisms (PIMs) for customer affordability and service restoration. 
• Allow the IURC to examine or review the reasonableness of the utility’s rates under the MYRP and adjust the base rates or PIMs under the MYRP at any time before the expiration of a MYRP. 

• Require regulated utilities to offer a low-income customer assistance program by July 1, 2026. Require utilities to fund the programs by allocating at least 0.2% of revenues from residential customers, plus any contributions from governmental agencies or programs. 

Advanced from House Committee: 

On January 20, 2026, the Indiana House Utilities, Energy and Telecommunications (UET) Committee held a hearing at which it issued favorable report on HB1333: Land Use and Development. After being reported by the House UET Committee, the Bill was recommitted to the House Ways and Means Committee, which issued a favorable report on January 27. 

If enacted, HB1333 would: 

• Require all development projects, regardless of type, that are sited on agriculturally zoned land with soils in land capability classes IV–VIII to be treated as a permitted use 
• Extend governmental immunity to certain private or nonprofit entities operating under agreements in Indiana’s brownfields program 
• Require certain qualified data center users, as a condition of using a specific transaction award certificate issued after June 30, 2026, to enter into an agreement with the permitting local unit committing to contribute at least 1% of forgone sales tax on exempt qualified data center equipment purchases 
• Redesignate “electric generation facility” as “electric generation or storage facility” for purposes of Indiana’s energy production zone statute and clarify that the term includes utility-scale battery energy storage systems (BESS), including requiring additional BESS-related emergency response and approval documentation in project notices 
• Allow local hearing bodies to require written name/address and to prioritize county residents and certain property interest holders in speaker order and time at certain land-use hearings. 

Back to Headlines 

Regional and National 

Other Regional and National News of Note 

• DOE announces U.S. Slovakia civil nuclear program agreement: On January 16, 2026, the U.S. Department of Energy (DOE) announced the signing of an intergovernmental agreement between the U.S. and Slovakia to expand cooperation on nuclear energy. The Agreement includes plans to develop a new 1.2 GW American-built nuclear plant at the site of the existing Jaslovské Bohunice Nuclear Power Plant. The Agreement aims to strengthen European energy security, support Slovakia’s transition away from Russian-designed reactors, and deepen U.S.-Slovakia strategic ties. 
• DOE announces 2026 Tribal Energy Series, first webinar Feb. 12: The U.S. Department of Energy announced the Office of Indian Energy 2026 Tribal energy webinar series, focusing on three themes—unleashing tribal energy resources, tribal energy program review mini-series, and creating the enabling framework to advance high-value energy projects. The first webinar is scheduled for February 12, 2026, from 3:00pm to 4:00pm, will discuss developing data centers for tribal economic development. Register for the webinar here. 
• DOE launches research facility for used nuclear fuel: On January 14, 2026, the U.S. Department of Energy (DOE) announced the creation of the Center for Used Fuel Research at Idaho National Laboratory (INL). The center will be the national and international hub for applied research on the management of used nuclear fuel (UNL) and will focus on improving the safe storage, transportation, and disposition of UNL. 
• DOE announces launch of uncertainty toolbox: On January 13, 2026, the U.S. Department of Energy (DOE) announced the launch of the Uncertainty Toolbox, an open-source library for uncertainty quantification and calibration for fusion and other research. The Toolbox provides metrics, visualizations, and recalibration methods to evaluate and improve predictive uncertainty in learned models. The Toolbox has become a leading community-maintained resource for uncertainty quantification and calibration across machine learning and physical sciences. 
• NLR releases 2025 Geothermal Market Report: The National Laboratory of the Rockies (NLR) released the 2025 U.S. Geothermal Market Report, highlighting an 8% growth from 2020 in installed capacity to approximately 4,000 Mwe and 26 new PPAs totaling over 1,000 Mwe. The Report also discussed progress in next-generation and enhanced geothermal technologies, declining costs, private investment, heating and cooling applications, and thermal energy networks. 
• EIA releases Short Term Energy Outlook, expects 3% demand growth by 2027, 69 GW of solar capacity additions: On January 13, 2026, the U.S. Energy Information Administration (EIA) released its short-term energy outlook, highlighting an expected 3% growth in electricity consumption and 69 GW of solar capacity additions by 2027. 
• Treasury Dept. holds first meeting to strengthen critical minerals supply chain: On January 12, 2026, in a press release, the U.S. Department of the Treasury held a meeting with finance ministers from major economies to discuss solutions to secure and diversify supply chains for critical minerals. Attendees emphasized the urgency of addressing vulnerabilities caused by concentration and disruption risks, while the U.S. outlined current and planned investments to build more resilient supply chains. 
• NOWRDC to host Technical Symposium on offshore wind research and development, Feb. 9: The National Offshore Wind Research and Development Consortium (NOWRDC) has scheduled its Technical Symposium for February 9 to February 10, 2026. The Symposium will convene industry, researchers, and public-sector leaders who are working to advance offshore wind and marine energy innovation and will be held at the State University of New York (SUNY) Global Center in Midtown, New York City. Register for the Symposium here. 
• Crux Climate publishes blog on interaction between corporate alternative minimum tax and transferable tax credits: On January 16, 2026, Crux Climate published a blog on the interaction between renewable energy tax credits and the Corporate Alternative Minimum Tax (CAMT). The Article noted that energy and manufacturing tax credits can offset up to 75% of a corporation’s net income tax liability and are transferable, creating opportunities to make up tax liability through purchasing credits and to profit from inapplicable credits. 
• Crux Climate publishes blog on using heavy equipment financing to alleviate clean energy project challenges: On January 15, 2026, Crux Climate published a blog on the use of pre-notice-to-proceed (pre-NTP) equipment financing to advance clean energy projects facing capital constraints. Pre-NTP financing enables the purchase of major project components and the securing of tax credits before construction or development financing is available. The Blog identifies pre-NTP financing as a means to establish long-term relationships with lenders, who may be more willing to finance tangible, high-value, transferable assets than early-stage project development. 
• ACT releases article on reforms to leverage solar to address energy affordability: On January 12, 2026, the Alliance for Climate Transition (ACT) released an article advocating for virtual power plants, streamlined solar approval processes, and utility regulatory reforms as tools to address energy affordability concerns. 
• SEIA releases financing guide for residential solar installers: On January 14, 2026, the Solar Energy Industries Association (SEIA) released a factsheet for residential solar and storage installers seeking financing options following the expiration of the Section 25D tax credit at the end of 2025. The factsheet notes that the expiration may simplify certain solar-specific loan structures for customers and highlights third-party ownership as a pathway to access tax equity. 
• WoodMac releases analysis showing payback period shorter with rising retail rates: On January 13, 2026, Wood Mackenzie (WoodMac) released an analysis of how rising retail electricity rates could affect commercial solar project returns. Their model found that increasing average annual retail rate growth from 2% to 6% between 2026 and 2050 would reduce the national average payback period by 33%, with significant variation across states due to differences in baseline rates and available incentives. 
• WoodMac publishes global update to installed energy storage: On January 13, 2026, Wood Mackenzie (WoodMac) published an update on the global energy storage market’s growth in 2025. The article highlighted the installation of 106 GW of new capacity – a 43% year-over-year increase – and noted that utility-scale projects accounted for 82% of installations. According to WoodMac, China accounted for 54% of worldwide installations, the U.S. accounted for 18%, and Australia, Germany, and Saudi Arabia emerged as key growth markets. 
• Brattle releases report on using managed EV charging to double distribution grid hosting capacity: On January 21, 2026, Brattle released a report on the grid reliability and cost savings benefits of active managed EV charging compared to passive management. Brattle found that actively managed charging can double the distribution system’s EV hosting capacity, reduce annual electric system costs by 30%, and defer system upgrades by up to ten years. 
• ACORE announces new leadership appointments: On January 14, 2026, the American Council on Renewable Energy (ACORE) announced the appointment of Pat Reiten, Senior Vice President of Public Policy at Berkshire Hathaway Energy, as Chair of the Board of Directors, as well as the addition of nine new members to the Board. 
• RMI releases article on the state of Utility planning for Q4 2025: On January 15, 2026, Rocky Mountain Institute (RMI) released an article analyzing U.S. electric utility integrated resource plans (IRPs) updated in Q4 2025. RMI found that the 15 utilities that updated their IRPs cut planned wind and solar additions by 2035 in half (from 46 GW to 23 GW), made only minor load forecast changes (+0.6%), and increased projected cumulative emissions through 2035 by 9.4%, citing factors including resource adequacy rule changes in the Midcontinent Independent Systems Operator (MISO) and Southwest Power Pool (SPP) regions, potential wind/solar tax credit phaseout, anticipated Environmental Protection Agency (EPA) greenhouse gas regulation repeal, and state policy changes. 
• EPA publishes final rule of emissions standards for emissions for power plants: According to Utility Dive, on January 13, 2026, he U.S. Environmental Protection Agency (EPA) issued a final rule setting nitrogen oxides (NOx) limit for new gas-fired power plants and other stationary combustion turbines, with standards that are more lenient than the November 2024 proposal. The EPA determined the best system of emissions reduction (BSER) for most new, modified, or reconstructed turbines is continued use of combustion controls, while new large turbines operating at above 45% 12-month capacity factor must use combustion controls plus selective catalytic reduction (SCR). EPA estimated that the rule will reduce NOx by up to 296 tons annually by 2032 and save plant owners $87 million over eight years. 
• North Carolina Clean Energy Center publishes 50 States of Decommissioning of Solar plus Storage: On January 14, 2026, the North Carolina Clean Energy Center released a report reviewing 2025 state policies on solar and solar-plus-storage decommissioning, including planning requirements, financial assurance, and recycling. The report finds growing attention to battery storage decommissioning and notes that more than half of U.S. states took legislative action in 2025 on solar/storage decommissioning and recycling, with recycling mandates expanding and states increasingly requiring financial assurance for storage facilities. 
• PDOE announces eight water power projects selected for Small Business award funding: On January 8, 2025, the U.S. Department of Energy’s Water Power Technologies Office (WPTO) announced $800,000 for eight projects supporting incubator and accelerator programs to help entrepreneurs and small businesses commercialize hydropower and marine energy technologies. Each project will receive $100,000 for six to nine months, and up to four projects may later be selected for up to $1 million each to continue work over three years. 
• The Josiah Barlett Center for Public Policy releases report on addressing energy affordability by replacing renewables with natural gas and nuclear: In January 2026, the Josiah Bartlett Center for Public Policy released “Alternatives to New England’s Affordability Crisis,” claiming that New England could save hundreds of billions of dollars and reduce blackout risk by replacing state-mandated wind and solar buildouts with nuclear and/or natural gas generation. The Report estimated that meeting 2050 energy needs would cost $415.3 billion with nuclear (92% annual greenhouse gas reduction), $106.9 billion with natural gas (24.5% reduction), or $195.8 billion with a nuclear-gas mix (50% reduction), compared with $815 billion under a renewables-mandate scenario cited from the coalition’s prior 2024 analysis. Based on those estimates, the Report concluded that dispatchable generation would better manage costs and reliability than a renewables-heavy buildout in ISO-New England. 
• Clean Energy Group releases microgrid case study from 2014 hurricane: On January 16, 2026, the Clean Energy Group released a case study on the Vieques Microgrid Network, describing how the nonprofit Community Through Colors (CTC) developed a distributed network of solar-plus-battery-storage systems to improve resilience on Vieques, Puerto Rico, where residents faced an 18-month outage after Hurricane Maria and ongoing unreliable service. The Report noted that CTC has supported 15+ solar and storage systems across critical sites, totaling about 225 kW of solar and 355 kWh of lithium-ion storage, typically providing twelve to 72 hours of backup power depending on the site and critical loads. 
• Trio releases global renewables market price briefing presentation: Trio’s Global Renewables Market Price Briefing (Q4 2025) reported that solar PPA prices in the U.S. rose in every region tracked except the Midcontinent Independent Systems Operator (MISO). The biggest quarter-to-quarter jump was in the Southwest Power Pool (SPP), up 10.4% to $66.85/MWh, while the Electric Reliability Council of Texas (ERCOT) rose 4.8% to $50.57/MWh—its largest increase in two years—and Pennsylvania-New Jersey-Maryland Interconnection (PJM) rebounded 1.6% to $80.99 after a slight Q3 decline. Trio’s price snapshot for Q4 2025 shows median solar PPA prices ranging from $42.75/MWh in the Western Electricity Coordinating Council (WECC) to $83.54/MWh in PJM, with ERCOT ($51.14), SPP ($72.13), and MISO ($73.00) in between. 
• Microsoft announces plans to pay for increased electric costs and grid updates in data center communities: On January 13, 2026, Microsoft announced a Community-First artificial intelligence (AI) Infrastructure initiative with a five-point plan for communities hosting Microsoft datacenters. Microsoft said that it will pay for the electricity-related costs its datacenters create to avoid shifting costs to residential ratepayers, reduce datacenter water use and replenish more water than it withdraws, expand local hiring and training pipelines for construction and operations roles, contribute to local tax bases to support public services, and invest in local AI training and nonprofits through community partnerships. 

Back to Headlines

Read this flash online 

Best regards,
The SEA Team


Sustainable Energy Advantage, LLC
John Keene - Senior Director
Tel. 508-665-5870 | jkeene@seadvantage.com
www.seadvantage.com
Connect with SEA!

Eyes & Ears Terms and Conditions

Eyes & Ears Service is provided to the Subscriber for the Subscriber’s internal use only, and may be distributed to employees, officers and directors of Subscriber or Authorized Affiliate who have been made aware of the Limitations on Use under the Subscription Agreement. Subscriber agrees not to distribute materials received under the Eyes & Ears Service, whether by written, oral or electronic means, to any other person, including consultants engaged by Subscriber, except with specific written permission from SEA or as required by applicable law, regulatory proceeding or exchange rule. Subscriber is subject to additional terms and conditions stated in the Subscription Agreement.