Resource Adequacy: Enough Power, Except When It Matters

Two True Statements That Sound Contradictory

In its 2026 summer assessment, the North American Electric Reliability Corporation reported that all assessed regions are expected to have adequate resources under normal peak conditions, helped by more than 58 GW of new capacity added since the previous summer. Two months earlier, its long-term assessment found that thirteen of twenty-three assessment areas face elevated or high resource adequacy risk over the next five years.

Neither figure is spin. They answer different questions, and the gap between them is the single most important thing to understand about this topic. NERC’s own director of reliability assessment put it plainly when the summer numbers landed — the improved conditions should not be read as overall reliability risk declining.

Resource adequacy is not a yes-or-no property of a power system. It is a probability distribution, and almost all of the interesting risk lives in its tail. A grid can be comfortably adequate for the summer it usually gets and dangerously short for the summer it gets once a decade — and since the second kind of summer is the one that causes blackouts, headlines and political consequences, the average tells you very little.

What “Adequate” Actually Means

The industry standard is older and stranger than most people assume, and it is worth knowing precisely, because every adequacy claim in the press is built on it.

The benchmark is “one day in ten years” — formally, a loss-of-load expectation of 0.1 events per year. A system is deemed adequate if, on a probabilistic basis, it would be expected to fall short of demand roughly once per decade. That is the criterion behind every reserve-margin target you will see quoted: PJM’s installed reserve margin near 17.7%, MISO’s reference level around 18.6%, and so on. Those percentages are not judgements about prudence — they are the arithmetic output of hitting a one-in-ten standard given a particular fleet.

Three metrics do the real work underneath, and the distinction between them is where the modern debate sits:

Modern assessments are run as large Monte Carlo exercises — thousands of simulations per hour across decades of historical weather, layering load-forecast uncertainty, generator forced outages, and variable renewable output. The sophistication is real. But every one of these models rests on a distribution of assumptions, and the headline that reaches the public is a single word: adequate.

The Number That Broke the Models

What has changed is not the methodology but the input. In a single annual revision, NERC’s ten-year demand outlook moved by an amount without precedent in the three decades it has been tracking.

A 69% upward revision to a ten-year demand forecast, in one year, is not a refinement. It is an admission that the planning baseline was wrong — and it happened because the load additions arriving now are unlike anything the planning process was built to handle. A single data-centre campus can request more power than a mid-sized city, on a timeline shorter than any generation project can be built.

From a Capacity Problem to an Energy Problem

Underneath the demand shock sits a quieter structural change that matters more for how adequacy is assessed. For most of the twentieth century, adequacy was a capacity question: did the system own enough megawatts of dispatchable plant to cover peak demand plus a margin? Thermal plants were available when called, so counting nameplate capacity was a reasonable approximation.

That approximation is breaking down. The 58 GW added over the past year was predominantly solar and battery — resources whose contribution depends entirely on when the system needs them. Solar has substantial capacity value at a mid-afternoon peak and almost none at 8pm. A four-hour battery can cover a short evening ramp and not a three-day cold snap. The relevant question is no longer how many megawatts exist, but whether energy is available in the specific hours the system is short.

Grid operators have adapted the arithmetic — capacity credit and effective load-carrying capability discount variable resources to their reliability contribution rather than their nameplate. And the risk window itself has moved: in solar-heavy systems the tightest hours are no longer the afternoon peak but the evening, as solar output falls while demand remains high. Battery storage directly addresses that short-duration gap, which is why ERCOT expects to have close to 19 GW of it by summer 2026.

Where the Risk Sits, and Why

The regional picture is not uniform, and the causes differ enough to matter. The long-term assessment places MISO, PJM, ERCOT, the WECC Northwest and Basin areas, and SERC-Central in the highest risk category, where planned resources would leave energy shortfalls beyond adequacy targets. The drivers cluster into four recognisable patterns.

• Load growth outrunning additions. The dominant cause, and the one directly traceable to data centres and electrification. ERCOT’s near-term metrics have actually improved, but continued load growth outpaces resource additions in later years.
• Retirements arriving faster than replacements. In the WECC Basin area, summer demand is forecast to rise by more than 1.7 GW over a decade while existing capacity declines by nearly 2.3 GW through retirements — a gap opening from both ends at once.
• Dependence on imports that may not be there. New England’s elevated-risk designation stems substantially from declining firm import commitments and greater reliance on non-firm supply at peak. Neighbours are a resource only when they are not short simultaneously.
• Weather-dependent supply. The Pacific Northwest faces drought-driven hydropower reductions tied to below-normal snowpack — the region’s traditional reliability anchor eroding precisely as summer heat peaks.

That last one deserves emphasis because it generalises. As more of the fleet becomes weather-dependent, supply and demand become correlated through the same variable. A heat dome raises cooling demand, lowers thermal plant efficiency, reduces hydro availability and can coincide with low wind. These are not independent risks that diversify away; they are a single event expressing itself on both sides of the balance.

The Counter-Argument, Taken Seriously

A piece in the Strain thread should be careful not to assume the pessimistic reading is automatically the correct one. There is a substantive critique of these assessments, and it is worth stating.

Independent analysis has argued that NERC’s seasonal assessments are conservative — that supplementing them with interconnection-queue data on resources likely to come online suggests the flagged regions are adequate even under extreme conditions. The mechanism of the critique is straightforward: assessments count resources meeting strict inclusion criteria, and can therefore understate capacity that is genuinely arriving. There is also a structural incentive worth acknowledging: a reliability body faces asymmetric consequences, since being wrong about a shortage is far more damaging than being wrong about a surplus.

Two things temper that. First, the same queue data underpinning the optimistic case has a completion rate closer to one in five, so counting queued capacity as arriving capacity requires care. Second, the conservatism cuts both ways — the assessments also assume normal peak conditions for their headline verdict, which is an optimistic assumption in an era of correlated weather extremes.

Reading It Through the Frameworks

Where is the physical risk mispriced? This is the primer’s first question in its natural habitat. Adequacy risk is quantified in reliability studies and expressed in engineering units, but it becomes a market signal only indirectly — through capacity prices, scarcity pricing and, increasingly, the political response to a shortfall. The gap between a documented tail risk and its market expression is where the opportunity has repeatedly appeared.

Where does policy become the cash flow? Adequacy is the reason capacity markets exist at all: a payment for being available rather than for producing. When adequacy tightens, capacity prices rise sharply — and that revenue stream is a regulatory construct that can be redesigned. Texas has taken a different route, granting operators authority to curtail large new loads in emergencies and funding programmes to expedite reliability resources. Demand-side curtailment as a reliability tool is a significant development, because it makes the load itself part of the adequacy solution rather than only part of the problem.