The PJM region (which covers over 65 million people across 13 US states and the District of Columbia) is projected to experience among the highest load growth in the United States by 2030, with an estimated 30 GW of new electricity demand hoping to connect to the grid. At the same time, PJM has come under scrutiny for its slow generator interconnection timelines and capacity market clearing prices that have risen tenfold over the past three auctions. As a result, both PJM and policymakers in member states are seeking creative solutions that enable new load and new supply to interconnect to the grid faster and more affordably.

On January 16, 2026, the PJM Board shared a plan to address challenges emerging from the surge of new large electricity customers. Earlier the same day, the Energy Dominance Council and the Governors of 13 PJM states unveiled a statement of principles that included a commitment to “use their authorities to allocate costs to data centers and protect residential customers.” States can take several actions to deliver on this commitment and maximize the benefits of PJM’s plan (see Exhibit 1).

Exhibit 1. A state roadmap to respond to PJM’s Large Load Plan

The PJM plan is the product of the Critical Issue Fast Path for Large Load Additions (CIFP-LLA) stakeholder process that PJM initiated last year. The plan aims to prevent data center demand from driving up electricity costs or causing outages from insufficient power supply, and provides a solution framework that:

1. Revises regional load forecasting practices,
2. Encourages bring-your-own resource options,
3. Introduces a load “connect and manage” approach, and
4. Proposes a new “reliability backstop” capacity auction.

While PJM’s CIFP-LLA decisional letter provides a regional framework for managing rapid large load growth, states will play a critical role in defining the details of how costs are allocated and risks are distributed to individual customers. The letter itself suggests, at a high level, steps states could take.

PJM states have an opportunity to act on the principles they laid out in the White House commitment with steps that complement PJM’s plan and help ensure new data centers do not raise residential bills or undermine state policy objectives. States have several high-impact levers to operationalize PJM’s plan while advancing durable approaches to large load integration. While states can act independently, the scale of the challenges and the realities of regional market participation call for multi-state coordination.

• Coordinate large load forecasting improvements: Clear commitment thresholds, transparency requirements, iterative validation, and incorporation of load flexibility can reduce duplicative requests and uncertainty in load projections. More certain forecasts can lower the risk of unnecessary investments and higher regional market prices that raise ratepayer bills.
• Regionally align large load tariffs (LLTs): Large load tariffs can harness flexibility, enable large loads to fund dedicated resources, and embed ratepayer safeguards. Shared tariff principles focused on minimizing risk could reduce cost shifting and system costs.
• Unlock supply and grid capacity: Permitting reforms, along with policies enabling virtual power plants and advanced transmission technologies, can accelerate new supply and extract more value from existing infrastructure. Collective calls for PJM to further reform generator interconnection can also help increase supply. More grid and generator capacity can increase affordability for ratepayers by lowering transmission costs and market prices.

Aligning load forecasting approaches, determining critical tariff provisions, shaping backstop auction design, activating broader interconnection reform, and investigating cost allocation methods will require sustained, collective engagement. Through proactive regulatory and policy solutions, PJM states can transform large load integration into a vehicle for supporting ratepayer and state interests.

The CIFP-LLA decision suggests a handful of actions states can pursue. These actions are not mandatory, but state inaction carries risks. The sections below summarize the key CIFP-LLA actions where PJM specified a likely state role and offer corresponding guidance on how states can respond.

Following this section you’ll find additional actions that states can take to effectively integrate large loads. These build on and complement potential direct responses to the PJM plan while emphasizing that with focused collaboration, PJM states can accomplish much more together than any one state could acting alone.

Commissions can prepare to robustly review large load forecasts

Recap: To improve the load forecasts that drive billions of dollars in infrastructure investment and shape the capacity market, PJM proposed changes to the annual large load adjustment process. The changes include an opportunity for state commissions to review transmission owners’ large load adjustments before they are finalized in the regional forecast. At the same time, utilities will be submitting new large load additions to PJM. Utilities must report to PJM when they inform state regulators of the additions and the feedback regulators provided.[1]

Next Steps: State utility commissions can prepare for implementation by establishing clear review and validation standards for load forecasts to reduce their uncertainty and the risk of system over- or under-build. When reviewing load forecasts, commissions can pay particular attention to:

• Improving transparency. Commissions can require utilities to provide access to the data and processes needed to meaningfully review PJM submissions. Where confidentiality limits commission oversight of large load agreement data, legislation (e.g., Pennsylvania’s Load Forecast Accountability Act) could be pursued. ESIG’s Forecasting for Large Loads report offers five key metrics to track for use in developing forecasts: project realization, energization date, load realization, load ramping, and load factor.
• Avoiding double counting. Commissions could direct utilities to establish load interconnection rules that require large loads to disclose similar project service requests in the state, and request disclosure for those outside the state across PJM. New legislative authority (e.g., Texas SB 6) may be needed to give commissions access to that information. However, mandated disclosure to the commission could introduce competitively sensitive information that the commission might then need to provide protective treatment for.
• Assessing likelihood. Commissions can reduce forecast uncertainty by requiring utilities to distinguish between speculative, preliminary, and firm load projections, using transparent criteria such as financial commitments or contract milestones to determine those categories (see examples in E3’s Forecasting Large Loads report). LLT safeguards such as minimum demand charges and exit fees could also disincentivize speculative or oversized service requests (e.g., AEP OH’s forecast dropped 17 GW following Schedule DCT). Commissions could require utilities to account for these tariff terms in their forecasting methodology.
• Strengthening validation. Commissions should confirm load forecasts and forecasting methods are updated using best practices, including “back-testing” to improve accuracy (see RMI’s Get a Load of This and ESIG’s Forecasting for Large Loads for technical guidance).
• Accounting for flexibility. Where states enable or require large load flexibility (through generation resources or demand response), commissions could direct utilities to ensure flexible service arrangements are reflected in utility forecasts and planning (a need discussed at VA SCC’s Data Center Load Growth technical conference).

Establish a Bring Your Own New Generation framework for retail electricity service

Recap: PJM encouraged voluntary Bring Your Own New Generation (BYONG) frameworks that enable load-serving entities (LSEs), large loads, and states to contract with incremental generation that offsets their load additions. PJM clarifies that states, not PJM, have authority over how these frameworks are developed and will apply to retail customers, including large loads.[2] PJM is still exploring how BYONG will be reflected in its capacity market and allow for Connect and Manage exemptions.

Next Steps: To create a standardized and transparent retail framework for large loads to BYONG, state commissions could direct LSEs to file a bring- your-own (BYO) tariff or incorporate BYO provisions into a “baseline” LLT. For example, in 2025 the Colorado PUC directed Xcel to file both an LLT and a clean transition tariff that would enable large loads to bring clean resources onto the system (Decision C25-0747). State legislation or executive action could also play a role in urging or requiring a PUC to take this step (e.g., the POWER Act proposal in Illinois).

BYO structures can help shift the cost and performance risk of procuring generation to serve new large loads away from existing customers, and toward large load customers driving the infrastructure need. Key advantages of an LSE facilitating BYONG (on their own or on behalf of large loads) with tariffs instead of special contracts are transparency and consistency. Tariffs are publicly filed and provide predictable ratepayer safeguards across large load electric service agreements that businesses can plan for.

BYO tariffs can allow large loads to procure dedicated system resources (including demand-side resources such as VPPs) that supplement utility planning, while:

• Assigning financial responsibility to participating customers,
• Limiting utility exposure,
• Lowering system costs, and
• Scaling advanced technologies.

Develop non-firm service tariffs

Recap: Under a new “connect and manage” approach, when PJM faces tight grid conditions that might require activation of its emergency procedures, PJM will curtail areas with incremental load not offset by new generation. Because of jurisdictional limits, PJM cannot in practice dictate which customers (i.e., large loads) will be curtailed first. Rather, PJM will notify transmission owners (TOs) and LSEs of the curtailment amount needed, then TOs and/or LSEs will determine which customers are curtailed and how, according to frameworks they implement.[3]

Next Steps: States have authority over the question of which customers LSEs should curtail first once PJM allocates the LSE load reductions. To reduce the overall risk of residential or critical customers being curtailed, states could direct LSEs to establish non-firm service tariffs for large loads to inform curtailment sequence and promote large load flexibility as a system resource (e.g., VA HB284).

Under a non-firm service tariff, large load customers agree to be curtailed to meet defined curtailment obligations beyond emergency conditions. Customers would accept this in exchange for compensation such as expedited interconnection, lower rates, or lower financial security requirements. In short, states could offer “speed to power” for flexibility. If allowed, large load customers may also be willing to invest in off-site virtual power plants or on-site resources to satisfy non-firm service curtailment obligations without disrupting their own operations.

It is currently within state jurisdiction to offer faster interconnection for load flexibility, although this may shift. In a docket (RM26-4-000) regarding large load interconnection jurisdiction, FERC is slated to address whether states will retain authority over customers interconnecting to the transmission system, or transition to FERC oversight. If states wish to mandate all new large loads to take non-firm service, legislation may be needed to strengthen the legal justification for this distinct treatment.

Establish an approach for assigning costs from the Reliability Backstop Procurement

Recap: PJM will develop a proposal for running its Reliability Backstop Procurement (RBP) to address capacity shortfalls demonstrated by the 2027/2028 auction. PJM will allocate costs among its member states for the resulting procurement, but notes LSEs will ultimately determine how the costs are then further distributed to incremental loads within the state, consistent with state law.[4]

Next Steps: States can participate in PJM’s upcoming RBP workshop and related filings to shape how the procurement is designed.

Additionally, states can investigate cost assignment approaches that ensure large loads reducing an LSE’s capacity needs through BYONG or non-firm service receive reductions in their RBP costs.

Pursue permitting reform to support new generation additions

Recap: The CIFP decision establishes a new, separate Expedited Interconnection Track (EIT) for 10 qualifying BYONG projects annually. To qualify, projects must demonstrate “state commitment to expedite consideration of permitting and siting.” In encouraging state efforts to add new supply, PJM specifically suggests generation and transmission siting and permitting reforms.[5]

Next Steps: State leaders can pursue legislative and agency-level reforms to reduce timelines, uncertainty, and risk for energy infrastructure development within their jurisdiction. RMI’s State Permitting Power Tool helps states identify reforms best suited to their context, providing a synthesis of novel permitting reforms from over 36 resources and identifying the challenges they can target. Addressing permitting challenges directly affects how quickly new supply can be developed to offset incremental demand and moderate capacity market prices.

To increase community buy-in for infrastructure deployment, states can promote the use of locally negotiated development agreements aligned with established community benefit frameworks. Through these agreements, developers can reduce discretionary approval uncertainty, clarify local expectations, and lower project permitting risk.

While the CIFP-LLA outlined the above actions for states, states have opportunities beyond those identified to support affordable and reliable access to power. Additional state action could further mitigate some of the challenges PJM’s CIFP-LLA and the joint governors’ and White House letter were designed to address.

Establish consumer affordability programs

While they are pursuing the actions above, states can shield low-income households from increasing costs with consumer affordability programs. Evidence suggests low-income programs can even reduce costs for everyone. Programs include:

• Low-income energy efficiency programs to lower costs through upgrades that reduce energy consumption.
• Ongoing customer assistance including bill credits, discount rates, or percentage of income payment plans to reduce energy burden for low-income customers.
• Arrearage management programs to help low-income customers reduce utility debt.
• Disconnection protections to prevent shutoffs during periods of non-payment.

In some states, large loads have contributed funding to these programs through legislatively required fees (see Minnesota’s HF 16) and negotiated large load tariff settlements (see Indiana Michigan Power Tariff I.P. Settlement Agreement).

Getting more from the grid with VPPs and ATTs

To get more out of existing infrastructure and reduce the need for emergency solutions, state legislation and commission action can increase the use of virtual power plants (VPPs) and advanced transmission technologies (ATTs). These fast and cheap-to-deploy tools can relieve states’ near and long-term capacity needs.

By supporting VPP deployment, states can harness the flexibility potential of existing assets on the grid to meet peak demand quickly (in as little as 6–12 months) and often at lower costs than conventional resources. By coordinating distributed energy resources, VPPs can provide an array of grid services including energy, capacity, resilience, and ancillary services, which can potentially defer costly transmission and distribution upgrades.

PJM states can support VPP deployment by:

• Enabling “retail” or utility-led VPPs through legislation or commission action. This would allow utilities to operate programs themselves or partner with third-party aggregators to provide grid services.
• Advancing wholesale market participation, including by facilitating advanced metering infrastructure (AMI) data sharing to measure market performance and participation. VPPs will be eligible for PJM’s capacity market beginning with the May 2026 auction, with broader energy and ancillary market participation proposed for February 2028.

States can also accelerate the adoption of ATTs to quickly and cheaply unlock additional transmission capacity to interconnect new load and generation. Legislators can pursue ATT-enabling policies including:

• Require state agencies or TOs to study them in planning processes.
• Require TOs to deploy them to reduce congestion.
• Provide cost recovery for ATT expenditures.

Together, VPPs and ATTs offer near-term solutions to expand available capacity and manage load growth while pursuing new generation or major transmission buildout.

The opportunities for collective action across PJM states

When pursuing any of the actions outlined above, there are opportunities for PJM states to make solutions stronger and more durable through coordination. Large load forecasting and tariffs are especially high-impact areas for collective action because they can reduce the regional effects of speculative load and associated capacity needs, such as cost shifting and higher prices. States can also align their PJM engagement to call for reforms that address underlying challenges for large load integration.

Coordinating direct responses to the CIFP-LLA and related actions

Multi-state approaches to load forecasting and tariff design can minimize the risk that speculative large loads pose to the region’s ratepayers and grid.

Collaboration across PJM states to improve their load forecasting rules can reduce stranded asset risk and future capacity market price spikes. Through aligning requirements and review processes to screen out speculative loads, states can bolster the certainty of regional capacity procurement and transmission investment decisions. This can mitigate cost increases for other ratepayers.

Additionally, states can pursue a regionally aligned large load tariffs framework that advances reliability, affordability, and state policies while responding to PJM’s CIFP-LLA reforms. Though provision-level design will vary with state-specific regulatory, economic, and grid contexts, a joint large load tariff strategy could look like each PJM state adopting a three-pronged tariff framework:

• Baseline LLTs that establish a new rate class and core ratepayer safeguards. Safeguards can improve state and regional large load forecasts by discouraging speculative or oversized service requests. A separate rate class can support clear cost assignment to reflect the distinct grid impacts of large loads.
• BYO tariffs or provisions that enable large loads to procure, and fund dedicated system resources to “pay their own way.” This responds to PJM’s call for state BYONG programs and enables use of the new Expedited Interconnection Track.
• Non-firm service tariffs that harness load flexibility (generation and demand response) beyond emergency interruption and reduce system buildout needs. This would reduce the need for residential curtailment under PJM’s new Connect and Manage framework.

Such a framework can enable states to translate PJM’s wholesale-level reforms into desirable and policy-aligned retail-level outcomes. By converging on shared tariff principles, states can both implement safeguards and expand access to BYO and non-firm service options that offer large loads a faster path to interconnection. These structures can (1) minimize regional risks such as higher ratepayer bills, increased utility financial exposure, and curtailment due to grid strain, as well as (2) promote consistent integration and valuation of flexible resources across the region. Beyond mitigating negative outcomes, a comprehensive tariff framework can advance state economic development and decarbonization.

State advocacy for PJM reforms

To increase system supply and address cost-socialization concerns, states can continue to coordinate advocacy for PJM and TOs to pursue reforms for generator interconnection and assess alternative transmission cost allocation approaches. State engagement with PJM staff may be more impactful if synchronized across multiple states.

Request further, deeper generator interconnection reforms: Generator interconnection delays remain one of the largest barriers to adding new supply, which exacerbates the challenges the CIFP-LLA seeks to address. Unlocking new supply is essential to (1) moderate capacity prices over the medium to long term and (2) serve new load additions and avoid “connect and manage” curtailment. An NRDC analysis shows adding just 30% of PJM’s backlogged renewable projects (those that have been in the queue for more than five years) could have lowered PJM’s capacity market clearing price by up to 63%.

The EIT alone is unlikely to ameliorate capacity shortfalls. For example, its 250 MW UCAP threshold effectively disqualifies several quick-to-build resources, such as batteries. Addressing underlying interconnection constraints will require additional action by PJM, such as:

• Accelerating study timelines through workflow and automation enhancements
• Unlocking “energy-only” interconnection via a separate, streamlined process
• Considering ATTs as network upgrades rigorously and throughout the study process
• Removing remaining barriers to surplus interconnection service

Beyond the EIT, no active PJM stakeholder process is focused on these unaddressed interconnection reforms. States can elevate the need for a full interconnection “fix” and help initiate action from PJM, as they have on issues like rising capacity market prices.

Consider revisions to transmission cost allocation: The CIFP-LLA decision does not address the transmission costs associated with connecting large loads. As load growth drives transmission needs, it is imperative that states consider how associated local and regional transmission costs are allocated and impacting different customers (see RMI’s Path to Power series for more on large load transmission needs).. This is important for monitoring energy affordability and aligning with cost causation and beneficiary-pays principles.

For local (supplemental) transmission upgrades built primarily to serve new load additions, states could investigate whether current cost allocation approaches remain appropriate and assess alternatives. Under the existing FERC-approved method, PJM allocates local transmission costs to the TO’s zone and then TOs distribute those costs across LSEs within their zone. State rate design then determines how an LSE’s assigned costs are recovered from its rate classes. This structure can limit a state’s ability to directly assign incremental transmission costs to specific large loads (see PPL’s settlement agreement for a recent example of a state-level approach).

The impact of PJM’s CIFP-LLA plan will be strongly shaped by whether states erect complementary structures and processes at the retail-level for addressing large load integration. By establishing large load tariffs that minimize customer risk, improving load forecasting oversight, and using state authority to unlock new supply and existing grid potential, states can build on and complement PJM’s plan. Through these complementary actions, including coordinated calls for generator interconnection and transmission cost allocation reform, states can go beyond reacting to skyrocketing costs or outages and instead proactively take advantage of large load integration to advance affordability, reliability, and system-wide benefits.

Notes

[1] See PJM CIFP-LLA pp. 2–3 and Appendix B.

[2] See CIFP-LLA pp. 3–4 and Appendix C.

[3] See CIFP-LLA pp. 3–5.

[4] See CIFP-LLA pp. 5–6.

[5] See CIFP-LLA pp. 4 and Appendix C.