Investors regularly optimize for demand growth but often struggle to model the complexity imposed by supply constraints.
In energy, remembering both sides of the equation has never been more important.
New analysis from the North American Electric Reliability Council (NERC), the institution charged with guaranteeing coordination across the North American power sector, highlights a new risk for infrastructure investors and LPs allocating capital in 2026: Coal retirements.
In energy markets, data center demand projections have soared, capturing investor attention and securing nearly $250 billion of project financing capital last year alone, but awareness of matching power supply constraints is only just becoming widespread.
The US and Canadian power grids are clearly facing strain from data center demand, but NERC now says the real risk to reliability in power service comes from planned power plant retirements – overwhelmingly from coal plant retirements.
The focus on elevated risk across 12 or NERC’s 23 assessment areas stems more from coal retirements than from demand growth over the next decade. The biggest risks are concentrated in the next five years, as the boom in 1. new utility scale battery additions and 2. natural gas uprates presaged by 2025 financing activity fails to compensate for coal retirements until the early 2030s.
King Coal grows old
A wave of coal generation buildout in the early 1980s following the oil embargo of the late 1970s has now reached its design life end point, and in competitive power markets many owners now face a bill for costly upgrades on the basis of capacity payments alone if they want to stay online. These units are set for retirement.
A number of even older coal units have repeatedly extended their operating life, but would need to be almost entirely rebuilt to stay online for another decade.
These units are also set for retirement.
The ordinary response by power market operators and local regulators to NERC’s alarming new forecast would be to designate many of these coal units as “reliability must run” units, commonly called RMR units by power market participants.
These RMR units are forcibly kept online and running to manage the peak hours of demand in the energy year, operating inefficiently from a market perspective but maintaining total system reliability.
RMR unit economics tend to be disastrously expensive for power market operators seeking to control costs, and for politicians hoping to limit rate increases for retail power consumers (and voters). They keep inefficient units online and burning costly fuel, even as offtake is highly intermittent.
RMR constructs vary by region and state, but they universally create a special revenue structure to compensate the unit’s owners for keeping online a unit they would otherwise retire.
Power market operators and politicians have traditionally been reluctant to encourage a proliferation in RMR orders for that reason. But some asset managers and investors have been able to garner well-above general market returns in recent years by betting that these kinds of RMR orders will be necessary to maintain basic resource adequacy standards as defined by NERC.
The federal government has stepped in with emergency orders to keep some units online under rarely used authorities that can keep coal units forcibly open and running hot, but the lack of precedent has created uncertainty about who will end up paying for units now producing power that is 1. vital for controlling seasonal capacity costs but 2. remains uncompetitive for much of the year.
Investor Considerations
While some investors with pre-existing exposure to aging coal plants that able to qualify for traditional RMR contract structures may garner higher-than-forecast revenue for those units over the next five years, a one-way RMR bet on NERC’s latest model comes with multiple risks.
With high capacity costs already in focus, ratepayers and their representatives may push back on expensive RMR constructs applied to many more plants. Any downward shift in the shape of forecasted load demand could just as suddenly cut off an “RMR payoff” for a qualifying coal plant as the capacity is no longer needed.
New investors may be better served focusing on the price trajectory and market structure of capacity attributes, taking a more technology-agnostic view of the resource adequacy service being provided.
Capacity payments are increasingly important to both current revenue stacks at generating units across organized power markets – and as part of project finance considerations.
Noreva Price Outlooks
Noreva’s base case for capacity pricing shows a significant appreciation in capacity pricing in several key markets. Summer capacity pricing in SPP will stabilize in a $6-8/kw-mo band through 2050 according to current long-term
Noreva forecasts, but in MISO North summer capacity could rise by nearly 700% over the same period in the base case as retirements bite.
Understanding how to service that call on capacity in the most efficient way and with the most targeted electrons will be the key technology, operational and financial challenge energy transition investors face through the coming wave of power generation project financing.
With at least $500 billion of power generation supply planned capex set to drive investment in the next decade, understanding the nuances of the interplay between fuel types, forecast risks and attribute markets is vital to effective capital allocation by LPs.
