Integrating reliability-must-run practices into wholesale electricity markets

One of the challenges of electric power market design comes in the need to consider the consequences of design choices for both market outcomes and grid reliability. Strictly speaking, the two kinds of consequences are not neatly separable, as market choices affect system reliability and system reliability affects market outcomes. The interaction between the two is often strongest exactly with policies enforced in the name of reliability, as with “Reliability Must Run” (RMR) agreements. In a report prepared for the R Street Institute, I examine a bit of the experience with RMR policies in several U.S. ISOs and suggest four principles that should guide policy design.

RMR agreements are contracts between Independent System Operators (ISOs) and a generation unit that is planning to retire. They are intended to keep the unit in operation in cases in which retirement may lead to local violations of reliability standards. RMR service is conceived of as a temporary tool intended to give market adjustments and transmission planning processes time to respond.

RMR policies are a small, but sometimes locally significant out-of-market action taken by the ISO. As with any out-of-market action, two market-related questions should be considered: (1) Is the reliability service obtained actually the lowest cost way to meet reliability requirements, and (2) Will the out-of-market action interfere with short-run and long-run incentives promoting system efficiency? This last issue is important, because a badly implemented RMR policy can reduce or eliminate incentives for market participants to operate and invest in ways contributing to low-cost, reliable system operation.

Both concerns were at issue in the Midcontinent ISO’s RMR agreement with the owners of the Presque Isle power plant on Michigan’s upper peninsula (see this item in the RTO Insider: $23 Million Owed to Ratepayers in Presque Isle SSR Case, note that RMR agreements are terms “System Support Resources” or “SSR” in MISO).

Grid reliability is not solely the responsibility of transmission grid operators. It is the shared product of the interaction of transmission operators, transmission owners, generators and consumers. Since most parts of the system are owned privately and operated separately, extensive coordination among these entities is necessary. Some coordination is obtained through rule-following and constant communication, but ultimately the system relies upon price signals to provide the strong incentives needed to ensure that private actions support grid reliability.

The most effective system to coordinate generation and load in the short run is a real-time market with locational marginal pricing and co-optimized procurement of energy and reserves.

To some extent reliance on RMR agreements has fallen across ISOs, so perhaps the issue is of dwindling importance. However, RMR policies make for a manageable case study of the interaction between markets and reliability policies, the lessons from which may be of broader significance for electric power market design. In the report I suggest the following four principles that should guide RMR policy choices:

  1. When reliability principles dictate out-of-market actions by ISOs, energy and reserve prices should reflect the implied resource scarcity;
  2. Rules governing RMR service should provide for transparency in operation and with respect to cost of service;
  3. ISOs should enter into RMR agreements only when the benefits of meeting reliability standards through the agreement exceed the costs; and finally,
  4. ISOs should consider cost-effective alternatives to RMR agreements when such alternatives will adequately address the potential reliability needs.

The report was intended to be an introductory survey accessible to the non-specialist, so technical detail has been avoided and the focus placed on general principles.