When a consumer turns on a light switch or charges their phone, they have no way of knowing what type of power plant generates the electricity they’re consuming.

The power could have come from a nuclear plant, hydro facility, solar farm, or any other available resource class. Yet, it is the job of grid operators to ensure that energy supply and demand are constantly in balance. These same operators plan for future scenarios by seeking commitments that enough capacity will be available to serve existing and projected new load.

Importantly, grid operators are modernizing their planning criteria to maintain reliability as the mix of generation changes from predominately dispatchable thermal (carbon-emitting) resources to less flexible, invertor-based (non-carbon emitting) resources. This is where the term “capacity accreditation,” the practice of measuring and valuing a resource’s contribution to maintaining resource adequacy, comes into play – an issue in power markets handled differently by each region.

Hydropower and pumped storage have distinct operating characteristics shaped by licensing and regulatory requirements, making it essential for owners to understand changes in planning parameters. These changes could affect generator revenues, costs to load, and impact utility planning guidelines.

CALCULATING RELIABILITY

Grid operators aim to meet a 1-day-in-10-year reliability standard, meaning the grid should only experience one day of blackouts every 10 years. To achieve this, operators have historically accredited resources based on installed capacity (ICAP) or unforced capacity (UCAP), which adjusts ICAP by accounting for outage rates. For example, a 100 MW plant with a 5% outage rate would be accredited as 95 MW under UCAP.

With the increased frequency of extreme weather events, outage risks are shifting away from the annual peak hour, and fuel availability is at times constrained. These changes have prompted some grid operators to develop more sophisticated methodologies for capacity accreditation. For example, gas plants tend to perform well in the summer when load could be higher, but fuel supply is readily available. Yet, in the winter, when demand for natural gas for heating purposes increases, the fuel supply available for power generation can be constrained due to pipeline limitations. By applying this logic, a 100 MW ICAP gas fired generator does not necessarily have 100 MW (or even 95 MW) of capacity value.

Grid operators are becoming increasingly aware of these system challenges as they plan for contingencies outside of the peak hour. Some grid operators have incorporated other risks into capacity accreditation, which, on average, will lower a resource’s capacity accreditation value and result in a smaller regional supply stack. Grid operators and economists contend that consideration of these factors better values the ability of certain technologies to serve load at times other than the peak hour.

UNDERSTANDING EFFECTIVE LOAD CARRYING CAPABILITY

A common methodology employed by grid operators to serve load during non-peak hours is Effective Load Carrying Capability (“ELCC”). ELCC, simply put, uses probabilistic modeling to determine how much “perfect” capacity is always available to meet load (i.e., no outages, can ramp up or down, no operating limitations such as minimum down or minimum run times, etc.), as it would be required to replace resources within each class (wind, solar, storage, coal, nuclear, gas combustion turbines and combined cycles, etc.).

ELCC also accounts for correlated outages. For example, the risk of potential gas plant failures increases in winter, not only from frozen equipment at affected plants, but also from gas supply shortages, which can affect multiple plants simultaneously. To further contextualize, if it takes 60 MW of “perfect” capacity to replace a 100 MW ICAP accredited gas plant, then the gas plant’s accredited capacity value is 60 MW.

The composition of other generators connected to the grid also impacts ELCC values due to correlated risks. For example, gas plants on the same pipeline share similar gas supply issues. For storage technologies, longer duration technologies like pumped storage tend to have higher ELCC values than shorter duration storage technologies such as batteries. However, as more storage technologies are added with the same discharge parameters, their capacity value decreases because they are calculated to have correlated discharge profiles.

ELCC accreditation also varies by region based on local resource availability. In the Pacific Northwest, short-duration storage has a low ELCC value because hydropower reservoirs provide greater reliability. Once 4-hour storage meets 10% of the system peak, additional storage adds little to no reliability value.

To see how ELCC can impact the supply stack in certain regions, let’s look at the largest RTO in the United States, PJM.

PJM strives to hold an auction for capacity once per year for the delivery year starting three years in the future. In January 2024, the Federal Energy Regulatory Commission (FERC) approved another set of changes to PJM’s capacity construct, the Reliability Pricing Model (RPM). These changes allowed PJM to implement a marginal ELCC methodology for all generation classes, including both thermal and non-thermal resources. The table below presents a projection of accreditation values PJM has calculated for the different classes of resources:

In PJM, each generator within an ELCC Class is assigned a unit-specific adjustment factor based on its performance compared to the class average, which affects its capacity rating. Certain hydropower resources, for example, are initially derated by 62%, and their final capacity rating is adjusted by the unit-specific factor. A 100 MW Hydro Intermittent resource with a 0.95 adjustment factor would have a UCAP of 36.1 MW. This formula is applied to all resources in PJM that submit offers in RPM auctions.

Application of the ELCC methodology in PJM has considerably tightened the accredited supply, as shown by the results from the most recent base residual capacity auction for the 2025/26 delivery year:

For delivery years 2022/23 through 2024/25, PJM’s base residual auction cleared an average of 171,940 MW of UCAP. However, for the 2025/26 auction, only 145,883 MW cleared, a 15% decrease. While some of the decline could be attributed to retirements, estimated at 5,200 MW of ICAP, most reductions are linked to PJM’s transition to the ELCC methodology. Holding all else equal, a shorter supply stack would increase prices.

WHY IT MATTERS

It’s important for hydropower and pumped storage owners to be aware of the regulatory changes discussed in this article.

If an owner is in a region with a capacity market, then these changes will materially impact future revenues and costs to load. Also, if utilities adopt more sophisticated capacity accreditation methodologies, then there will be an impact on consumer rates, as utilities will likely have to purchase more capacity through their rate base or through Power Purchase Agreements.

Therefore, the owners of hydropower and pumped storage assets must properly educate both RTOs/ISOs and utility planners on the capacity value of their resource while developing a greater understanding of the financial implications of such revisions.