The Local Reliability Gap
A generating unit can be chronically uneconomic in the wholesale energy market and still be the cheapest available source of local voltage support. That mismatch is the gap reliability must run contracts exist to fill. The market clears on energy, and in some regions capacity, but it does not directly pay a unit for the ability to hold voltage at a specific substation when a constrained transmission corridor limits imports.
When the owner of such a unit announces retirement, the system operator faces a problem that the market alone does not solve. A reliability must-run (RMR) contract is one instrument used in some markets to keep the unit available until a longer-term fix is in place, although whether such a mechanism exists, what it covers, and who ultimately pays for it depend on the market design and the applicable tariff.
RMR arrangements are a form of out-of-market reliability designation. They pay for availability rather than dispatched energy, and they typically arise in areas where the network was planned around large central plants close to load centers. Understanding how these contracts work, why they are controversial, and what alternatives exist matters for anyone involved in grid planning, plant ownership, or retail cost allocation.
What an RMR Contract Does in Practice
Under an RMR arrangement, the system operator or utility designates a specific generator as necessary for local reliability. The owner receives a payment to keep the unit in service or ready to run, even when normal market dispatch would otherwise have it offline. The payment generally covers going-forward operating costs, any capital expenditure needed to keep an aging unit available, and, in some cases, compensation for market opportunities the owner forgoes by accepting the designation.
RMR is distinct from ordinary must-run dispatch. A must-run instruction tells an operator to keep a unit online for a defined period; an RMR contract is a commercial arrangement that compensates the owner for availability and for accepting those instructions over a longer horizon. The distinction matters because the payment structure and regulatory oversight differ.
Operating instructions depend on the reliability service required. Some units are instructed to run at minimum load to provide reactive power and local voltage support. Others are held in reserve for specific contingencies. A unit may run for only a few hours per year yet remain under RMR designation for several years, because the transmission upgrade or alternative resource needed to replace it takes longer to deliver than the retirement decision that triggered the need.
Why These Contracts Arise
RMR designations usually emerge when three conditions meet: an aging generating unit, a local area with limited import capability, and a retirement or de-rating proposal. The transmission network was often designed around large central plants located close to load centers. When one of those units retires, the surrounding area can lose voltage support, short-circuit strength, or the ability to ride through a contingency. If imports from elsewhere cannot make up the difference quickly, the operator keeps the unit running.
The issue is not just total generation. The system may have ample capacity elsewhere, but a distant generator generally cannot provide the same local voltage support. Reactive power has to travel through network impedance before reaching the constrained node, and the electrical distance between the unit and the problem location limits how much support it can deliver. For this reason, RMR units often run not for energy but for their ability to hold voltage at a particular substation.
Retirements are not the only trigger. Load growth in a constrained area can also push a system toward an RMR designation if existing generation is needed for a few more years until transmission or new resources can be connected. Large, concentrated loads have drawn regulatory attention in several jurisdictions, and the same local reliability questions appear when load arrives faster than grid upgrades. In that setting, RMR contracts are a temporary patch rather than a market failure signal on their own.
The Market Blind Spot
In markets with nodal pricing, dispatch clears supply and demand at each node, but voltage support and system strength are not priced in the same way everywhere. Zonal and national market designs offer a coarser locational signal still. A generator that provides these services from a remote location cannot deliver them through a constrained path, and a unit inside the constrained area may be the only practical source. The market can still clear with that unit offline, because the energy imbalance is met elsewhere, while the local reliability condition deteriorates.
This is the core reason RMR contracts exist outside the normal dispatch process. The market price signals the value of energy, not the value of keeping a particular plant connected at a particular bus. When the two values diverge sharply, an out-of-market payment is one way to bridge the gap. The alternative is a market design that explicitly prices local reliability services, which several jurisdictions are exploring but few have fully implemented.
The Economics and the Controversies
RMR payments are usually recovered from transmission customers or through a reliability charge, depending on the jurisdiction. Like renewable curtailment, an RMR designation turns a physical network limit into an explicit cost rather than leaving it hidden in dispatch outcomes. The underlying condition is often grid congestion, and the cost is deliberate: it keeps a unit available without letting supplemental payments distort energy-market prices. If the plant bid its full costs into the merit order, it would set a higher local price or require out-of-market uplift.
A recurring criticism is that RMR status can blunt the signal to build transmission or new resources. A unit retained under RMR may reduce the urgency for a permanent solution, and a generator may have limited incentive to invest in upgrades if the RMR payment already covers costs. System operators try to manage this by reviewing designations periodically and committing to exit paths, but the process is often slower than plant retirement decisions.
There is also a debate about cost allocation. If the need is local, charging all customers in a large region can be perceived as cross-subsidizing a particular load pocket. Some markets allocate the cost to the transmission zone or load area where the reliability need occurs. Others socialize it across the entire footprint because the unit maintains wider system reliability. Both approaches exist, and the choice influences how clearly the cost signal reaches the area that caused the constraint.
Exit Paths and Planning Implications
RMR contracts are treated as a stopgap in most jurisdictions. The longer a unit stays under RMR, the more clearly it indicates that transmission planning and resource interconnection are not keeping pace with retirements and load growth. Possible exit paths include transmission reconductoring or rebuilds, synchronous condensers, static synchronous compensators, grid-forming batteries, and new generation located at the constrained node. Each option has different lead times, costs, and technical capability.
Some regions have moved toward more structured local reliability markets or mandatory must-offer requirements that incorporate voltage support costs into capacity prices. Others still rely on bilateral reliability contracts negotiated case by case. The institutional variety reflects different market structures and different levels of confidence in centralized planning. What is common across them is the recognition that the energy market price alone does not always reveal the full reliability need at a particular location.
One practical lesson from RMR experience is that the cost of keeping an old unit alive is often small compared with the cost of the transmission fix it delays, but the reverse can also be true if the designation persists for too long. The mechanism matters less than the planning process surrounding it. Where transmission planning anticipates retirements years in advance, RMR designations can often be avoided. Where planning lags, the RMR contract becomes an expensive form of insurance with no obvious end date.
For utilities and system operators, an RMR contract is a signal that local reliability is being managed outside the market. The designation generally triggers a review of why the constrained area has not attracted new generation or transmission. If interconnection queues are clogged, if network upgrades are stalled, or if retirement notices arrive faster than planning studies, the RMR arrangement is a symptom of a deeper coordination problem.
For generators, an RMR contract provides revenue certainty, but it is not a growth strategy. The arrangement may require maintaining aging equipment, meeting availability commitments, and accepting dispatch instructions that override market opportunities. The owner may also face regulatory scrutiny over costs, and the terms can make RMR status less attractive than it first appears.
For customers, the main question is whether the RMR cost is transparent and temporary, and whether it is being used to delay a genuinely planned grid fix. The charge is often small relative to total bills, but it can persist unnoticed for years. Clear reporting of RMR expenses and periodic reviews of the underlying need are the practical tools that keep a temporary patch from becoming a permanent subsidy.
References
- NERC — Long-Term Reliability Assessment: used for the relationship between generator retirements, load growth, and local reliability needs.
- FERC — Large Loads Co-Located at Generating Facilities technical conference (Docket AD24-11): used for background on concentrated load growth and the local reliability questions it raises.
