PJM Outlines New Proposed Framework; Offers Bridge to New Supply
- 2 days ago
- 9 min read
ENERGY POLICY PERSPECTIVES: VOL. 21
Yesterday, PJM’s Board outlined its new framework under the Critical Issue Fast Path (CIFP)
accelerated stakeholder process to address resource adequacy and large-load growth issues,
which it expects to formally submit to the Federal Regulatory Commission (FERC) by the end of
July. We believe the framework can be reduced to four functions: 1) measure large load
additions; 2) contract new supply; 3) curtail unsupported load when necessary; and 4)
compensate verified load flexibility where regulators determine it is appropriate. We believe
this represents an assertive position by the Board, but functionally it is more of an interim
bridge to manage its current shortfall rather than a complete resource-adequacy solution.
The framework depends on FERC approval, state cost allocation, utility execution and whether
contracted projects can actually be built. PJM’s proposed framework shifts value away from a
pure-merchant-capacity construct and toward orchestration, contracting and cost-allocation
capabilities. For utilities, the opportunity is to turn large-load demand into a regulated or
contractually protected growth platform without shifting development, utilization or
stranded-cost risk to existing customers. For IPPs, we view the framework as more
constructive for development platforms, but potentially negative for legacy merchant
scarcity value over the medium term, as project-specific contracted returns shift value away
from system-wide scarcity rents. Accordingly, we believe IPPs with strong origination,
structuring, collateral and utility-relationship capabilities are best positioned for this
proposed framework.
PJM is moving beyond only a capacity market. The proposed framework creates a layered
resource-adequacy structure that keeps the Reliability Pricing Model (RPM) as the core forward
capacity auction but adds the Reliability Backstop Procurement (RBP) for long-term contractual
support for incremental supply, bilateral contracts allowing individual loads to bring their own
resources (PJM’s facilitated bilateral matchmaking launched June 9th, initial matches expected
in August and to continue until early next year) and Interim Resource Adequacy Service (IRAS)
to manage unsupported load before the new incremental capacity actually arrives. This is not
an abandonment of its capacity auction but an acknowledgement that new generation capacity
and resource adequacy is not keeping up with load growth. PJM projects new large load
demand to increase by approximately 70 GW by 2038. Meanwhile, the latest capacity auction
fell 6.8 GW short of its reliability standard and added only 525 MW of new generation (including
208 MW of uprates) for the 2028/2029 delivery year.
Four-part proposed framework:
Large Load Registry. This is a data and accountability foundation for the other three
policies to reduce the risks associated with bad large-load forecasts by developing and
maintaining a registry of large loads. Electric distributors will provide information on
expected load additions, timing, location, ramp schedules, supporting capacity, backup
generation and service arrangements. We believe this should help distinguish credible
projects from speculative ones and help improve transparency, accuracy and potentially
speed of decisions.
Reliability Backstop Procurement. Largely reflective of PJM’s previous Stage 4 proposal,
RBP is effectively a long-term capacity contract layered on top of RPM. It is a one-time
procurement expected to run from September 30th through October 21st (results expected in early December prior to 2029/2030 BRA). The procurement will provide capacity only
commitments until 2042/2043 (up to 15 years) with pay-as-bid pricing ($555/MW-day
UCAP on RBP portfolio's weighted-average price, then netted against any RPM capacity
revenue) for projects entering service by June 1, 2032. It addresses the revenue certainty
and bankability issues related to RPM, but does not directly solve permitting, equipment
availability, interconnection delays or construction timing. Therefore, we think it may be
more credible as a 2030+ supply development mechanism rather than a physical solution
to the expected shortfalls highlighted by the past two auctions. Costs of the procurement
will be initially allocated to the Load Serving Entities (LSEs) with states and utilities
ultimately determining how the obligations are assigned among different retail customer
classes.
Interim Resource Adequacy Service. Formerly known as “Connect and Manage”, IRAS is a
near-term reliability bridge that essentially creates a service quality distinction for new
large loads (>50 MW at a single site) entering service after June 1, 2027 that do not bring
qualifying capacity, receive RBP credit or satisfy PJM’s reliability standard. These loads are
allowed to connect with the understanding their service is conditional and in times of
scarcity their service may be curtailed.
Compensation for reduced load. The large loads are technically providing a reliability
service when they reduce load, so this proposal creates a mechanism to compensate them
for this flexibility. On the surface this seems contradictory to IRAS as it allows for a
performance-based compensation mechanism for large loads that are directed to reduce
withdrawals/curtail under IRAS, even though the acceptance of that curtailment risk was
a prerequisite to them being allowed to connect. Ultimately, the amount of compensation,
if any, is determined by the states or relevant retail regulators so we sense the
language/mechanism is largely constructed to be inclusive of the various state regulatory
environments.
Governance signal and independence. One of the major critiques levied at PJM at the FERC
Technical Conference held last Thursday was the Board’s unwillingness to take actions that
were unpopular with industry stakeholders who can remove PJM Board members. The Board
rejected a voluntary procurement proposal that received more than 2/3rds sector-weighted
stakeholder support in favor of the mandatory centralized procurement in this proposal. This
is a promising initial data point demonstrating the Board’s prioritization of its reliability
mandate over stakeholder consensus.
RBP does not solve the near-term physical shortage. While the intended target is for RBP to
largely fill the 2028/2029 BRA shortfall, projects may not actually come online until 2032, there
is no special interconnection “fast track” and developers remain responsible for network
upgrades. This solves revenue, certainty, project bankability, and long-term contracting
visibility that may help greenfield projects, but supply chain constraints, interconnection
delays, permitting, transmission expansion and EPC execution still constrain financed projects
from coming online. In our opinion, IRAS is the more meaningful bridge to help work through
the near-term shortage period by curtailing new large loads that it cannot reliably support and
excluding them from RPM demand forecasts (beginning with the 2029/2030 delivery year BRA
this December) until sufficient new capacity is offered to cover them.
Resource-adequacy test on capacity not energy. Large loads seeking a grid interconnection
are left with three options: 1) bring or contract qualifying new capacity; 2) receive RBP capacity
support; 3) accept conditional service and curtailment exposure under IRAS. A large load
seeking bring your own new capacity (BYONC) status must be paired with new PJM-recognized
capacity, recorded in the Large Load Registry and verified by PJM (registered and committed
through RPM). Private arrangements (behind-the-meter/modular power solutions, backup
generation, bilateral energy PPA with an existing generator and other arrangements) can help a site operate through grid curtailment, but do not automatically exempt it from IRAS
treatment. This ultimately only ensures that enough accredited capacity has been added to
keep the system capable of meeting peak demand at the target reliability standard not whether
the paired resources produce enough electricity to offset the data center’s energy
consumption (hourly, daily, seasonally, annually). The implicit assumption is that competitive
markets and system operations should produce enough energy outside scarcity periods, an
oversimplification with numerous potential faults, particularly given the high-load factor of
some AI data centers and reliance on increasingly constrained grid infrastructure to get power
from where it is created to where it is needed.
Cost allocation remains dependent upon the states. PJM can allocate wholesale obligations to
LSEs, but states determine which retail customers ultimately bear the cost. The proposed policy
therefore improves the framework for causation-based allocation but does not alone
guarantee or necessitate that data centers bear all resulting costs. This overlaps heavily with
the Ratepayer Protection Pledge (RPP), which was expanded to 300+ organizations covering
~263 million Americans and ~80% of U.S. power delivered to homes and businesses last
Thursday, but operates at a different jurisdictional level. PJM’s framework converts part of the
broad political public commitment (RPP is not itself a retail tariff, FERC rate or state statute)
into wholesale-market architecture that can help to enforce part of it by applying a narrower,
administrable test based on new accredited capacity participating in RPM. It strengthens the
RPP’s credibility but still requires state commissions to convert the LSE obligations into
enforceable customer-specific tariffs and contracts.
Equity framing for utilities and IPPs. PJM’s proposed framework shifts value away from a pure-merchant-
capacity construct and toward orchestration, contracting and cost-allocation
capabilities. The key distinction is not simply regulated utilities versus IPPs; it is which
companies can convert large-load growth into bankable, deliverable and appropriately
allocated capacity obligations.
Utilities. We believe the framework is strategically constructive, but not automatically
earnings accretive as the translation of their increased institutional importance is heavily
dependent upon state commission treatment. The principal utility opportunity is to turn
large-load demand into a regulated or contractually protected growth platform. The core
upside is not simply higher load or a larger data center pipeline, but which utilities can
convert that pipeline into protected capital deployment (incremental rate base or long-duration
contracted revenue with limited stranded-cost exposure) without transferring
development and utilization risk to existing customers. This is heavily dependent upon the
regulatory environment (i.e. state) in which they are operating.
IPPs. We view the proposed framework as more constructive for development platforms,
but potentially negative for legacy merchant scarcity value in the medium term as project-specific
contracted returns shift value away from system-wide scarcity rents. The RBP
provides a new long-term contracting option for incremental capacity while BYONC and
bilateral contracting create direct and accelerated demand from large loads seeking firm-service
treatment. The RBP provides a visible alternative for IPPs and large loads which we
believe could help pull forward contracting decisions, particularly for projects capable of
entering service in the near-term. New supply is unlikely to arrive quickly so the near-term
merchant impact will likely remain constructive, in our view. PJM’s selection process
prioritizes earlier delivery before least-cost ordering which helps turn the “speed-to-power”
option value into a more concrete monetizable product. We believe IPPs with
strong origination, structuring, collateral and utility-relationship capabilities, not merely
fleet ownership, are advantaged as the commercial shift continues to move beyond
conventional energy PPAs toward broader capacity-and-reliability contracts to match what
ISO/RTO, state and other political and regulatory bodies are increasingly demanding.
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