America’s capacity markets are quietly telling long-duration storage it is not worth paying for, and a veteran storage financier has now quantified the gap. In an interview published August 19, 2026, Raafe Khan, head of energy storage at Camelot Energy Group, laid out three structural flaws in US capacity markets that he says create a “major disconnect” for long-duration energy storage (LDES) financing. First, capacity-accreditation discounts for longer duration are weak: in PJM, a 4-hour battery earns a 59% accreditation, a 6-hour battery 68%, and an 8-hour battery just 71% — doubling the duration buys only about 12 percentage points of recognition. Second, commitment terms are far too short: capacity auctions grant contracts of only one to three years against assets with 20-25 year lives, whereas the UK offers terms up to 15 years. Third, administrative price caps (recently around $325 per MW-day) are constantly being hit during supply shortages, suppressing the very price signal that would reveal storage’s true value. Khan also argues that data-centre demand is an “accelerant” for storage, not its foundation, and that vertical integration is more about risk management than profit expansion. It is a sobering look at the pricing machinery that determines whether long-duration storage gets built — and a reminder that the same duration-value question behind a 5kWh vs 10kWh vs 16kWh home battery choice is playing out, at billion-dollar scale, in the wholesale market.
Overview of the Technology / News
Capacity markets exist to guarantee that enough generation or storage will be available to meet peak demand years in advance, paying resources simply to be on standby. In the United States, PJM — the largest wholesale electricity market in the world — and its peers run annual auctions in which resources bid to provide that capacity, and the clearing price becomes the revenue floor for new-build investment. Storage participates in these markets, but the rules that govern how much capacity a battery is credited for — and for how long — are where the disconnect lies.
The key metric is the Effective Load Carrying Capability (ELCC), which measures how much a resource can actually be relied upon to keep the lights on given its duration and its correlation with system peaks. A battery’s ELCC rises with duration — a longer battery can serve longer, deeper shortfalls — but as Khan’s PJM figures show, the accreditation curve is steeply discounted: the marginal recognition for each additional hour of duration shrinks rapidly, which economically penalises exactly the long-duration systems the grid will increasingly need.
Why This Development Matters
This matters because financing, not technology, is now the binding constraint on long-duration storage. The technologies exist — flow batteries, iron-air, thermal storage, compressed air — and the cost curves are improving. What is missing is a revenue model that a lender can underwrite for 20 years. When a capacity market pays a 6-hour battery barely more than a 4-hour one, and only commits to that payment for a couple of years, no financier can justify the capital a long-duration asset requires.
There is a second significance in what the disconnect will cost the grid. As renewables displace dispatchable thermal generation, the system’s need shifts from two-to-four-hour batteries toward multi-day storage that can ride out prolonged lulls and seasonal shortfalls. If the market refuses to price that duration, it will not get built — and the reliability gap will be filled by the very fossil plants the transition is trying to retire. The pricing rules are, in effect, a policy choice with physical consequences.
Technical Deep Dive
The ELCC mechanics deserve a closer look, because they explain why the accreditation curve is so flat. ELCC is computed by modelling how much a resource’s addition reduces the system’s loss-of-load probability, which is dominated by the worst few hours of the year. A 4-hour battery already covers most of the daily peak, so going to 6 or 8 hours adds capacity value only for the rarer, longer-duration events — which the model, focused on the extreme tail, discounts heavily. The result is a near-flat accreditation curve that under-values the resilience value of duration, even though climate-driven, multi-day events are precisely the growing risk.
The commitment-term problem is a financing-architecture issue rather than an engineering one. A capacity asset is financed against a contracted revenue stream; shorten that stream from 20 years to two, and the project must recover its cost in two years of payments or seek merchant revenue it cannot guarantee. The UK’s 15-year contracts, by contrast, let a long-duration project secure bankable, long-tenor revenue — which is why the UK has pulled ahead of the US in LDES deployment despite a smaller market. The administrative price cap compounds both: by capping the price at roughly $325 per MW-day, the market cannot send the high-price signal that would both reward reliability and attract the capital to build it.
There is a residential echo in all of this that makes the market’s logic concrete. The 5kWh vs 10kWh vs 16kWh home battery decision is, at heart, the same duration-value calculation: how many hours of stored energy do you actually need, and what is each additional hour worth? Just as a household weighs whether the extra capacity pays for itself through home battery peak shaving savings during peak-rate hours, a capacity market is supposed to weigh whether each additional hour of grid-scale duration earns its keep — and Khan’s critique is that, today, it does not.
Real-world Applications
The immediate application is investment-allocation in the US storage sector. Khan’s analysis explains why so much US capital has flowed into 4-hour lithium systems while multi-day technologies struggle to close deals: the market is simply paying more, more reliably, for shorter duration. Developers reading these incentives will keep building what the market rewards, which is why the rules — not the technology — are the real object to change.
The broader application is policy design. The three flaws Khan identifies are all fixable through market-rule changes: steeper duration-aware ELCC curves, longer commitment terms, and higher or removed price caps. States and grid operators looking to procure long-duration storage can use this framework as a checklist — and the contrast with the UK’s 15-year contracts is a ready-made template for reform that the US Federal Energy Regulatory Commission (FERC) and the regional transmission organisations could adapt.
Industry Impact / Market Implications
For the LDES industry, this is a candid diagnosis of its central commercial obstacle. Technologies that are technically ready are being held back by market design, and until that design changes, the sector’s growth will remain below its potential. It also validates the strategic bets of developers who have sought alternative revenue streams — tolling agreements, corporate PPAs and data-centre contracts — precisely because the capacity market alone will not finance them.
For the broader storage market, Khan’s point about data centres is the sharpest signal. Treating hyperscaler demand as an accelerant rather than a foundation is a call for discipline: the data-centre boom is real and large, but it is a cyclical, concentrated buyer, and a storage industry built only on it would be fragile. The durable foundation must be a capacity market that prices duration correctly — the same structural fix that would, down the line, strengthen the best home energy storage 2026 case for every homeowner sizing a battery against an increasingly renewables-heavy grid.
Future Outlook
The near-term watch-items are the PJM and other capacity-market rulemakings. Any move toward duration-aware accreditation, longer contract tenors or relaxed price caps would immediately change the economics of long-duration storage and redirect capital. FERC’s posture toward capacity-market reform, and the UK model’s influence on it, will be the leading indicators to watch.
Over the next two to five years, expect capacity-market design to become the central battleground of the storage transition, with the US under growing pressure to match the UK’s longer-tenor, duration-aware approach as multi-day reliability events multiply. The strategic lesson for the whole market is that the 5kWh vs 10kWh vs 16kWh home battery question — how much duration you need and what it is worth — is being answered, and argued over, at every scale, from a household’s utility bill to the clearing price of the world’s largest electricity market.
