Reliability Must RunEdit
Reliability Must Run (RMR) is a mechanism in wholesale electricity markets designed to guarantee grid resilience by ensuring certain generation units operate and are compensated even when the market price signal would not sustain their operation. In practice, RMR orders or contracts step in when grid operators assess a real risk that system reliability could be compromised if only economically competitive resources were dispatched. By locking in steady generation capacity, RMR aims to prevent outages during peak demand or extreme conditions, and to maintain a credible backstop against contingency events that could threaten service to consumers. The approach sits at the intersection of market design and prudent regulation, balancing the incentives for efficiency with the nonnegotiable need for dependable power.
RMR has become a prominent feature in several major U.S. electricity markets, including PJM Interconnection, ISO New England, and MISO (the Midcontinent Independent System Operator). Its use reflects a tension common to modern energy policy: how to reward reliability and grid security within competitive markets that prize price signals and the efficient use of resources. Proponents argue that RMR is a necessary safeguard—an insurance policy against the risk of outages that could have wide-reaching economic and social costs. Opponents, however, contend that it can entrench uneconomical plants and distort price signals, slowing the transition to more flexible and lower-cost resources. The debate over RMR often tracks broader disputes about market design, regulatory oversight, and the optimal pace of energy transition.
Historical background
The concept of ensuring resource adequacy through mechanisms beyond purely market-based dispatch emerged in the wake of concerns about reliability and planning discipline in an era of restructuring. The 2000s saw rapid changes in electricity markets, with regulators and market operators seeking to replace older, vertically integrated planning with competitive mechanisms that still guaranteed a stable supply of electricity. The memory of large-scale outages, such as the 2003 blackout in North America, underscored the question of whether markets alone could always deliver enough capacity during extreme conditions. In response, grid operators began to rely more explicitly on capacity mechanisms and, where necessary, Reliability Must Run arrangements to prevent forced outages and curtailments.
RMR arrangements are typically tied to the capacity market framework that many regions use to ensure generators have a financial incentive to remain available for reliability purposes. The basic logic is straightforward: some resources, due to market prices or technical limitations, would not operate without some form of primary support, even if they provide essential reliability services. By cataloging these resources and compensating them for their commitment, market operators seek to avoid reliability gaps while preserving competition among the rest of the fleet. The result is a hybrid system that blends price signals from competitive markets with targeted payments designed to maintain system integrity. References to these structures appear in regional market documentation and regulatory filings, including discussions of capacity market design, regulation, and the role of FERC in overseeing market rules.
How it works
Reliability Must Run typically involves a formal order or contract that obligates a generating unit to stay available and to operate when needed for reliability reasons. The operator of the grid—whether it is a regional transmission organization or an independent system operator—identifies which units fall under RMR and negotiates terms that reflect the value of keeping those units online for reliability. Owners of RMR-recognized plants receive compensation that covers a portion of their fixed and variable costs, even if their net market price would not justify continued operation in a fully competitive market. This payment is designed to ensure that the resource remains available during critical periods and can be called upon to meet reserve margins.
Because RMR shifts part of the cost of reliability onto ratepayers or customers, the mechanisms are designed with transparency and accountability in mind. Regulators, often at the state or regional level, scrutinize the necessity of each designation, the terms of payments, and the consequences for overall system costs. The practical effect is a balancing act: preserving the reliability of the grid during peak demand, while avoiding unwarranted subsidies that would distort competition or inflate bills unnecessarily. For context, discussions about grid resilience, baseload power, and the role of various resource types (such as nuclear power, coal power, and natural gas) frequently intersect with RMR policy.
Economic and policy considerations
From a market-oriented perspective, RMR is a tool to reduce the probability of outages without fully abandoning the price signals that guide efficient resource allocation. By guaranteeing a minimum level of availability, RMR reduces the risk that scarcity rents or sudden price spikes would translate into reliability emergencies. Proponents point to the tangible benefits of avoided outages—economic disruption, safety concerns, and social costs—that can far exceed the incremental payments made to plants under RMR. In regions where reliability risk is perceived as elevated, RMR can be justified as a prudent public-private partnership that leverages competitive forces while recognizing the limits of market self-regulation.
Critics of RMR, however, argue that it can shelter uneconomic capacity and dull price signals that would otherwise drive investment toward more flexible, efficient, or cleaner resources. Subscriptions of this view assert that RMR payments can create permanent subsidies for aging plants, slow the retirement of fossil-fueled capacity, and make it harder for newer, low-cost technologies to compete. Opponents also caution that opaque or opaque-like pricing structures may obscure the true cost of reliability, shifting burden to consumers and potentially diverting capital from transmission upgrades, energy efficiency, or demand-side resources that could deliver reliability at lower long-term cost. In policy discussions, the question becomes whether to emphasize near-term security or long-run efficiency and innovation.
A broader policy dimension concerns how reliability should be valued in public budgeting and regulation. Some argue for strengthening capacity markets or improving performance-based penalties and incentives so that reliability is rewarded through market signals rather than through ad hoc subsidies. Others contend that getting the price right requires a careful mix of market discipline, regulatory oversight, and selective reliability payments, especially in regions with tight resource adequacy margins or remote generation constraints. In all cases, debates around RMR intersect with energy policy goals, including the pace of de-carbonization, the role of domestic energy resources, and the balance between consumer protection and industrial competitiveness. See discussions of energy policy and regulation in relation to reliability planning.
Regional implementations and examples
Regional market designs illustrate how RMR plays out in practice. In PJM Interconnection, which covers a broad swath of the eastern United States, reliability planning involves a mix of forward capacity markets, contingency reserves, and, where necessary, reliability obligations that can resemble RMR-like arrangements to keep essential units online during stressed periods. In ISO New England, RMR-type actions have historically been used to ensure resource adequacy in a region with limited fuel diversity and high winter demand risk, with payments designed to stabilize essential plants during critical months. The Midcontinent Independent System Operator (MISO) manages similar considerations across a large footprint, balancing competitive market signals with reliability requirements in a grid that spans multiple states with varying resource mixes.
Across these regions, the exact design of RMR payments, the length of contracts, and the governance processes for designation are shaped by local regulatory frameworks, competitive market rules, and the reliability risk profile of the region. The role of state utility commissions, regional planning bodies, and federal oversight by FERC features prominently in approving and adjusting these arrangements. The regional experience demonstrates that while the core objective—keeping the lights on—remains constant, the mechanics of achieving it can differ based on market structure, resource mix, and policy priorities.