Effective Price Formation Remains Vital in RTOs: Stakeholders Agree in Modernizing Market Design Comments

Changes in the production and consumption of electricity are placing ever larger stresses on the six regional transmission organizations (RTOs) overseen by the Federal Energy Regulatory Commission (FERC or Commission). RTOs operate markets to coordinate the use of electric supplies and transmission capability to meet customer demand. Through a series of technical conferences and related proceedings, FERC has led an inquiry into how RTOs should adapt market rules to account for changing conditions. In an Order Directing Reports issued April 21, 2022, FERC requested information from the six jurisdictional RTOs. The RTOs filed responses in October 2022, and industry stakeholders were invited to comment on those filings by January 2023.

The R Street Institute (RSI) filed comments emphasizing our belief that competitive markets serve end-use customers better than regulated monopolies. Competitive wholesale power markets operated by RTOs have produced benefits well exceeding their costs, and the core value proposition for RTOs continues to be in regionally coordinated market-based dispatch of resources to meet consumer demand. The case for RTOs remains strong.

RTO markets can improve their performance in a variety of ways, particularly in working toward robust energy and ancillary service (E&AS) designs that help reduce reliance on less efficient capacity markets. Improvements include:

1. Market design reform should be focused on ensuring efficient price formation. Efficient prices support grid reliability and help reduce the overall cost of serving end-use customers.
2. Regulatory oversight of price formation practices may reasonably differ across RTOs. Textbook market design is appropriate in regions comprised of mostly competitive, independent power generators. Different challenges arise in RTOs in which customers are served predominantly by traditionally regulated utilities, since these utilities lack incentives to respond efficiently to market conditions.
3. Market design reform should be proactive rather than reactive. Proposed reforms should be evaluated based on expected costs and benefits across reasonable scenarios of future market conditions.
4. RTO market designs need not be forced into harmonization, but harmonization can be valuable. The Commission’s role is to balance the benefits of robust regional stakeholder processes against the benefits of greater consistency across markets.
5. RTO efforts to meet increasingly variable and uncertain net loads should be developed through market design reform and not by out-of-market operating practices. Sustainable approaches to managing net load variability will integrate system requirements into real-time E&AS markets in a transparent, rule-based manner.
6. Market design reforms should unleash demand-side opportunities. Demand-side participation is chronically underutilized, yet it holds large reliability, cost savings and market power mitigation potential. Regulatory oversight only partially substitutes for the diversity of positions and interests of end-use consumers.

Many of the themes advanced by RSI were also found in the comments of other stakeholders.

Holistic Approach Required

Stakeholders agreed that increasing net load variability created challenges for current markets. While the consequences are often seen in market operations—for example, in ramping challenges and increased price volatility—many stakeholders said the response should not be limited to changes to market operations. The Clean Energy Buyers Association (CEBA) said the Commission should “continue a holistic approach to reforms, including transmission planning and cost allocation, cost management, and generator interconnection.” Other stakeholders expressed similar views, adding gas-electric coordination, demand-side integration and interregional transmission to the list of relevant topics.

A Commitment to Robust Price Formation

Nonetheless, market design reforms were central to most comments. Views expressed mostly fell into three broad areas: 1) robust price formation in E&AS markets; 2) barriers to resource participation; and 3) new flexibility products. Locational marginal pricing (LMP) remains as important as ever for coordinating regional generation and transmission capabilities. Prices reflecting marginal costs is an efficiency benchmark not unique to the electricity industry. LMP incorporates all major components of wholesale electricity marginal cost: system-wide energy value, transmission congestion and line losses. Accounting for these components remains vital in the future.

Higher market prices have led some observers to worry that LMP contributed to price increases, but stakeholder comments were nearly unanimous in endorsing use of LMP. Many of the comments endorsed analysis presented in a paper submitted by the New York Independent System Operator in its October 2022 Response that shows that LMP works both in theory and in practice. PJM Interconnection (PJM) and the California Independent System Operator, as well as regional power markets in Ontario and Texas, have experiences with non-LMP market designs, and each found ample reason to adopt LMP systems instead. In addition, the paper indicates that experience has shown that LMP-based markets can adapt well to system changes.

Stakeholders suggested rules governing supply of ancillary services may create unjust barriers to entry. Economists have concluded that even markets with relatively few participants can produce competitive outcomes so long as barriers to entry are low. Public interest organizations emphasized that demand response provided valuable reliability services during extreme weather events and urged the Commission to eliminate barriers to demand participation. The market monitor for the Southwest Power Pool also encouraged cutting barriers to demand-side participation. Advanced Energy United recommended steps to enable distributed energy resources to participate in RTO markets.

Other technical reforms to price formation practices garnering support in multiple comments filed include greater use of operating reserve demand curves (ORDCs) and the co-optimization of E&AS markets. ORDCs help reward resources capable of providing reliability services prior to emergency conditions. Constellation Energy Generation (Constellation) noted setting parameters for ORDCs has been challenging and stakeholders would benefit from Commission guidance. The Edison Electric Institute (EEI) explained that co-optimization “helps to determine the economic trade-offs between the variety of services the resources can provide” and thus improves price formation. Similarly, Constellation emphasized co-optimization encourages resources to follow operator dispatch instructions whether called upon to provide E&AS. Co-optimization of E&AS markets serves to keep market incentives aligned with system reliability needs.

Many stakeholders raised concerns over the degree to which RTOs engaged in out-of-market interventions, noting the practices may have a considerable impact on market-clearing prices.

Need for New Flexibility Products Debated

A highly technical debate is brewing over the best approach to meet growing flexibility needs. The dominant approach has focused on ramping and other flexibility-related ancillary services, but critics of that approach argue that increased flexibility can be found among current resources by a mix of strategies that avoid introducing flexibility products. Included among these strategies are eliminating rules that inadvertently encourage inflexibility; refining resource bid parameters to better reflect resource capabilities; and (once again) co-optimizing E&AS procurement. Also, the addition of flexibility products with thin markets may create market power concerns.

Regional Flexibility, But Not Too Much

Commenters generally supported the Commission’s approach to regional variation. The EEI’s comments were typical, stating the Commission “should allow and encourage the RTOs/ISOs to develop … market enhancements that reflect regional characteristics and concerns.” The Electricity Consumers Resource Council expressed similar views, noting the variety of approaches helps uncover market practices that work best. CEBA struck a cautionary tone, observing that FERC should “avoid unwarranted ‘flexibility’ that will limit participation by resources, particularly renewable resources, in E&AS markets.”

Time for Commission Guidance

It is likely time for the Commission to provide RTOs and stakeholders guidance in the process of reforming market design to address growing net load variability. In PJM’s October 2022 Response to the Order Directing Reports, it called for the Commission to issue a policy statement in the docket. Such a statement would, in PJM’s words, “help to focus RTOs and their stakeholders on these issues at a time when there are countless issues that could distract from their development.” Several stakeholders supported PJM’s call. RSI agrees. Enough information has been placed on the record in this docket to ground a policy statement and such a statement would assist RTO stakeholder response.