Federal Power Act § 202(c): Shaping Grid Response

FROM EMERGENCY AUTHORITY TO ACTIVE RELIABILITY INSTRUMENT

Originally published in Public Utilities Fortnightly

As load growth accelerates and weather volatility persists, expanded use of Section 202(c) of the Federal Power Act is shaping how the grid responds during emergencies. These federal directives can require facilities to operate differently than planned and beyond otherwise applicable environmental restrictions, raising practical and financial considerations for system operators, regulators, utilities and independent generators. Understanding the evolving process is essential for managing compliance, cost recovery, and operational readiness.

Section 202(c) of the Federal Power Act authorizes the Secretary of Energy to require temporary connections and to direct the generation, delivery, interchange, or transmission of electric energy during an emergency.  Congress framed the authority broadly.  An emergency may arise from sudden increases in demand, shortages of generation or transmission facilities, fuel constraints, or other causes affecting reliability.

The statutory structure is deliberate.  DOE determines that an emergency exists, what actions are required, and compels operation.  The Federal Energy Regulatory Commission addresses the economic consequences of such a directive by prescribing a just and reasonable compensation and cost allocation.

A Section 202(c) directive may also permit limited relief from otherwise binding environmental restrictions to the extent necessary to meet the emergency.  That relief, while temporary and bounded, can nonetheless expand a facility’s usable output and alter dispatch capability during stressed conditions.

Historically, Section 202(c) was used sparingly.  More recently it has emerged as an active tool to address reliability as large load growth, infrastructure constraints, and weather volatility have placed sustained pressure on regional systems.  

The DOE has responded with directives and inquiries to balancing authorities and reliability coordinators nationwide.  Those inquiries extend beyond traditional generators to auxiliary, cogeneration, and backup facilities capable of supporting the grid.

Section 202(c) is no longer theoretical.  It is operational.  The economic questions that follow a directive are immediate.

Multiple Cost Allocation and Cost Recovery Frameworks

Recent experience reveals three approaches to handling the economic consequences of a Section 202(c) directive by DOE.

PJM: Ex Ante Tariff Framework.  PJM has adopted tariff provisions that expressly address DOE-directed emergency operation.  In 2025, FERC accepted revisions clarifying how generators may recover costs incurred in complying with a Section 202(c) directive.  The PJM approach adapts its Deactivation Avoidable Cost Credit construct to emergency service.

Cost categories are defined in advance.  Market revenues earned during the emergency period are netted against eligible costs.  Residual amounts are allocated region-wide when the directive addresses system adequacy rather than localized transmission needs.  Settlement mechanics are embedded in existing market processes.

The significance lies in structure.  Recovery is predefined.  A generator can comply with a directive and implement compensation through an existing tariff pathway without first seeking Commission action to establish recovery predicates.

MISO: Generator-Initiated Commission Action.  MISO presents the opposite condition.  When the DOE directed continued operation of certain units, affected generators examined the tariff and concluded it lacked a fit-for-purpose mechanism for recovery and allocation of costs attributable solely to federal compulsion.  

Consumers Energy filed a complaint.  The Commission agreed that the tariff did not adequately address DOE-driven operation and established structural recovery predicates under Sections 202(c) and 309.

The Commission separated allocation mechanics from cost adjudication.  It first addressed who would pay and how revenues would be netted.  Detailed cost support would follow in a separate proceeding.  Subsequent proceedings involving other MISO generators have followed the same sequencing.  Allocation scope, eligible cost categories, and revenue netting principles are established before dollar amounts are adjudicated.

The lesson is practical.  Where a tariff does not clearly recognize federal emergency compulsion as a distinct trigger, generators may need Commission action to supply missing structural elements before meaningful recovery can occur.  

In these proceedings, challenges to DOE’s emergency determination are treated as collateral to FERC’s economic role.  The Commission confines its review to compensation mechanics and allocation design. That statutory separation is reflected in procedural posture.

Early predicate-setting filings are becoming risk management tools.  Absent an embedded tariff mechanism, waiting for full cost accumulation can increase liquidity exposure without improving legal position.  Structural predicates first.  Cost adjudication second.

Other Organized Markets

ISO New England, NYISO, SPP, and CAISO do not currently maintain PJM-style, Section 202(c)-specific compensation provisions.  Each region has reliability tools, uplift mechanisms, or retention constructs tied to operator-initiated actions.  None expressly addresses cost allocation and revenue netting for generation compelled by DOE for broader adequacy purposes.

These regions have not yet produced Commission findings of tariff insufficiency comparable to MISO.  That absence does not resolve the question.  The operative inquiry is whether existing constructs treat federal compulsion as a distinct economic trigger.  If not, the structural sequencing seen elsewhere is likely to emerge.

A generator facing a directive must determine whether existing mechanisms cover delayed retirement, sustained availability without dispatch, incremental maintenance, fuel carrying costs, and compliance expenses.  If they do not, the MISO template provides a roadmap.

Non-RTO and Bilateral Contexts

A December 2025 DOE directive affecting Tri-State’s Craig Station Unit 1 presents a different posture.  The DOE issued its order shortly before scheduled retirement of Unit 1, requiring its continued availability in the WECC region. 

Tri-State and co-owners of Unit 1 sought rehearing at DOE, raising statutory and constitutional arguments.  Because the unit operates outside an organized market, there is no centralized tariff through which costs are absorbed.  Recovery, if available, would depend on Commission action and the interplay of wholesale and retail rate structures.

The case confirms that Section 202(c) issues are not confined to organized markets.  In non-RTO settings, the absence of a centralized allocation mechanism increases uncertainty.  

Structural predicates may still be required, but they must be constructed through Commission action interacting with wholesale and retail rate structures.  The institutional pathway is less defined. The compulsion remains the same.  The issues arise whenever federal authority compels operation beyond market expectations.

ERCOT: Another Dimension

In January 2026, DOE issued orders authorizing operation of certain ERCOT natural gas units beyond environmental limits and separately authorizing ERCOT to require large industrial and commercial loads to operate on-site backup generation prior to declaration of firm load shed.
No deployment ultimately occurred. 

The episode nevertheless raised material questions.  Will large loads be compensated if they incur costs or losses when required to rely on backup facilities?  How does a DOE order interact with Texas initiatives such as the Large Load Demand Management Service being developed under state law?

ERCOT does not operate under FERC oversight.  Compensation questions therefore turn on state regulations and market rules.  With more than two hundred gigawatts of large load seeking interconnection, coordination between federal emergency authority and Texas reliability constructs will become increasingly consequential.

Practical Considerations for Generation Owners

Generation owners should evaluate the governing tariff or regulatory framework before a directive issues and determine whether it expressly addresses federal emergency compulsion, cost eligibility, revenue netting, and allocation scope.  Cost taxonomies should be prepared in advance. 

Variable operating expenses must be distinguished from incremental maintenance, staffing, depreciation associated with deferred retirement, taxes, insurance, and directly attributable regulatory costs.  Emergency-related expenditures should be segregated.  Comprehensive revenue netting should be assumed. 

In regions without predefined mechanisms, timing gaps should be anticipated.  Commission action may establish structural predicates before costs are fully known, and final cost approval may follow later.  Liquidity planning matters.  Backup units, cogeneration facilities, and industrial sites may be drawn into emergency service.

Reliability Tool in Active Use

Section 202(c) was designed as emergency authority.  It is now an active instrument of reliability management.  DOE determines when compulsion is warranted.  FERC and state regulators determine who pays and how.

The central question is structural.  Is recovery embedded in advance, or must it be constructed after the directive issues?  That distinction drives timing, liquidity exposure, and regulatory risk. Regions that embed emergency recovery within their tariffs offer predictability.  Regions that do not will rely on generator-initiated proceedings to supply missing structural elements.

As load growth accelerates and weather volatility persists, directives under Section 202(c) are likely to remain part of the federal reliability toolkit.  Preparation and careful assessment of existing compensation mechanisms will determine whether emergency service can be delivered with economic clarity as well as operational reliability.