DOE Emergency Grid Orders Put Backup Generation to the Test

ENMG Analysis

The U.S. Department of Energy issued back-to-back emergency orders for PJM Interconnection and Duke Energy Carolinas as hot weather and rising electricity demand placed additional pressure on two major power systems in the Mid-Atlantic and Carolinas.

DOE issued the orders under Section 202(c) of the Federal Power Act, which allows the energy secretary to require temporary generation or transmission actions during an emergency.

On September 1, Energy Secretary Chris Wright issued Order No. 202-26-41 for PJM. Two days later, DOE issued Order No. 202-26-43 for Duke Energy Carolinas. Both orders allow the grid operators to dispatch specified generating units and direct certain backup-generation resources to operate as a last resort before or during an Energy Emergency Alert Level 3, the stage at which firm customer load may need to be interrupted.

The actions followed several other emergency orders during the summer, including a July order for PJM, a July order for the Southwest Power Pool, and an August order requiring the Eddystone Generating Station in Pennsylvania to remain available. DOE also issued a separate Florida order on September 1 requiring Orlando Utilities Commission to keep Stanton Energy Center Unit 1 available through November 30.

Together, the actions show how federal and regional officials are using temporary emergency authority to manage a system in which demand growth, extreme weather, generation retirements and the rapid expansion of large electricity users are converging.

What the DOE Emergency Grid Orders Authorize

PJM submitted its application to DOE on September 1. Order No. 202-26-41 took effect immediately and remains in effect through September 8.

The order directs PJM to dispatch specified units and authorize their operation when needed to maintain reliability. It also allows PJM, working with transmission owners and electric distribution companies, to direct backup-generation resources to operate before declaring an EEA 3 or while an EEA 3 is in effect.

Duke Energy Carolinas submitted its application on September 3. Order No. 202-26-43 took effect that day and also runs through September 8. Its basic structure is similar: Duke may dispatch specified units and direct backup-generation resources to operate as a last resort before or during an EEA 3.

DOE’s official records for the PJM order and the Duke Energy Carolinas order include the underlying applications and resource exhibits.

The September actions extend a pattern examined in ENMG’s earlier coverage of PJM’s emergency grid order.

EEA 1, EEA 2 and EEA 3 are not the same

The reference to EEA 3 is important because under NERC’s emergency-operations standard, the three alert levels represent progressively more serious grid conditions.

• EEA 1 indicates that all available generation is committed or that operating reserves are becoming difficult to sustain. The system is tight, but firm customer load is still being served.
• EEA 2 means the system is energy deficient and operators have implemented measures such as demand response, interruptible-load curtailments or other load-management procedures. Firm load generally remains served.
• EEA 3 means the system cannot maintain required contingency reserves and interruption of firm load is imminent or already occurring.

That makes the backup-generation language in the DOE orders more than a routine dispatch instruction. The resources are intended to create an additional buffer before utilities reach the point of controlled load shedding.

The orders do not mean that every available generator must operate at maximum output. They authorize grid operators to use specified resources when necessary to maintain reliability. The actual value of a resource depends on whether it can start quickly, whether fuel is available, whether it can operate safely, and whether its location supports the part of the grid under stress.

How Backup Generation Supports DOE Emergency Grid Orders

In January 2026, DOE estimated that more than 35 GW of unused backup-generation capacity was available nationwide. The department first publicized that figure while preparing for Winter Storm Fern, so it is not a new estimate produced for the September orders. The department has continued citing backup resources as a potential reliability tool, but the 35 GW figure should not be interpreted as a verified pool of capacity immediately available to PJM, Duke Energy Carolinas or any other individual grid operator. DOE has not publicly identified every resource included in the estimate or demonstrated that all 35 GW can start when needed, obtain fuel, operate within local system constraints or safely disconnect customer load from the grid. PJM previously said it was still determining which facilities possessed usable backup generation and how those resources were connected. The estimate therefore describes potential national capacity—not capacity dispatched under the September orders.

The department has not published a detailed public inventory demonstrating how much of that capacity remains operational, available during a particular emergency or capable of responding within PJM or Duke Energy Carolinas. One analysis cited by Utility Dive estimated that only approximately 9 GW might be available based on EIA data, while PJM said the usable amount within its territory was unclear.

That figure refers to power capacity, measured in gigawatts. It does not mean that 35 gigawatts were dispatched under the September orders, nor does it describe the amount of electricity produced over the emergency period. Energy production would be measured in megawatt-hours or gigawatt-hours.

The distinction matters:

• GW measures the rate at which equipment can produce electricity.
• MWh measures how much electricity is produced over time.
• A 100 MW generator operating for one hour produces 100 MWh.
• The same generator operating at a 50% capacity factor over a year would produce substantially less energy than its theoretical maximum.

Backup resources can include generators at data centers, industrial facilities, commercial buildings and other large loads. Backup resources may include on-site generators and, depending on the facility and applicable operating arrangements, battery systems or other directly connected resources. Their reliability value is usually greatest during short periods of system stress, rather than as a substitute for the energy supplied by a fleet of utility-scale plants over days or seasons.

There are also operational limitations. Some generators require time to start, some depend on diesel or natural-gas deliveries, and others may be constrained by emissions permits, maintenance conditions or local distribution equipment. A resource located behind a customer meter may reduce demand on the bulk system, but it still has to be coordinated safely with the utility and distribution operator.

The 35 GW estimate therefore represents a potential emergency resource pool, not a fully interchangeable national reserve.

Why data-center growth is part of the story

Large electricity users are an important part of the policy discussion. Data centers, advanced manufacturing plants and other industrial facilities can add substantial load to a local grid, sometimes faster than new generation and transmission can be developed.

That is why the emergency orders’ references to backup generation have particular significance for the data-center sector. A facility with on-site generators or battery storage may be able to temporarily reduce its demand on the grid during an emergency. In practice, that arrangement requires clear operating rules, communications systems, fuel planning and safeguards for critical services.

ENMG previously examined this issue in its coverage of flexible interconnection for data-center load and grid reliability. Flexible interconnection can allow large loads to connect under operating conditions that include curtailment or reduced service during periods of grid stress. The approach may accelerate new industrial development, but it also shifts more responsibility to system operators and customers to define when and how load is reduced.

The September orders are not permanent interconnection policies. They are emergency tools. Their repeated use, however, highlights the need for longer-term planning around generation, transmission, storage, demand response and large-load connection standards.

The Florida order adds a generation-retirement dimension

On September 1, DOE separately issued Order No. 202-26-42 directing Orlando Utilities Commission to ensure that Unit 1 at the Stanton Energy Center in Orlando remains available to operate.

According to DOE, the coal-fired unit had been scheduled to enter an extended cold shutdown in June 2026. The order is effective from September 2 through November 30.

The action differs from the PJM and Duke orders because it focuses on keeping a specific plant available rather than authorizing a broad emergency framework for backup generators. It also illustrates the operational tradeoff facing utilities and regulators: retiring older generating units can reduce fuel and maintenance requirements, but removing dispatchable capacity may leave fewer options during periods of extreme demand or limited supply.

Keeping a plant available does not guarantee that it will be economical or frequently dispatched. It does, however, preserve an operating option while utilities add new generation, reinforce transmission and evaluate future resource needs.

The same issue appears in DOE’s August order involving Eddystone Units 3 and 4 in Pennsylvania. DOE’s Eddystone record says PJM and Constellation must keep the units available through November 20 and use economic dispatch to limit costs. The order does not make the units a substitute for long-term capacity planning, but it prevents their immediate unavailability during a period of regional reliability concern.

Grid-Reliability Benefits and Unresolved Tradeoffs

The immediate benefit of the September orders is operational flexibility. PJM and Duke have more tools available before they need to interrupt firm customer load. That can benefit households, hospitals, manufacturers, businesses and other customers that depend on continuous service during hot weather.

The limitations are equally important.

Emergency dispatch can increase emissions when backup generators or emissions-limited units operate outside normal patterns. It can also expose weaknesses in fuel supply, generator maintenance, transmission availability and local distribution systems. The orders are temporary and do not by themselves resolve the underlying balance between rising demand and the pace at which new resources are being built.

The broader generation mix also matters. Natural-gas plants can provide flexible output, while coal and nuclear units can support sustained generation when available. Wind and solar resources contribute energy but vary with weather and time of day. Battery storage can respond quickly, although its duration depends on the size of the system and the length of the emergency. Transmission allows regions to share resources, but congestion can limit those transfers.

What energy professionals should watch next

As of September 8, 2026, neither order has been extended and both are scheduled to expire at 11:59 PM EDT today. No EEA declarations or resource dispatches under the orders have been publicly reported.

The next signals will be operational and regulatory:

1. Whether PJM or Duke actually directs backup resources to operate and how much capacity is used.
2. Whether either system reaches EEA 1, EEA 2 or EEA 3 during the September heat period.
3. Whether DOE renews or expands emergency orders after the September 8 expiration date.
4. How regional operators treat large-load interconnection requests, particularly from data centers and industrial facilities.
5. Whether utilities retain additional coal, gas or nuclear capacity while new generation and transmission projects move through permitting and construction.
6. How regulators address emissions and cost recovery associated with emergency operation.

The central lesson from the latest orders is not that 35 GW of backup generation has solved the reliability challenge. It is that the country has a sizeable but unevenly distributed set of emergency resources that grid operators may need to call upon while the wider power system adapts to hotter weather, new industrial demand and changing generation portfolios.

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