Gavan, John C., and Rob Gramlich. John C. Gavan and Rob Gramlich - A New State-Federal Cooperation Agenda for Regional and Interregional Transmission, 2021. Publisher's VersionAbstract

    Excerpt from the Introduction:

    The experience of grid operators and planners in the United States and around the world has shown that both decarbonization and power system resilience will require large-scale regional and inter-regional trans- mission expansion. In the United States, transmission planning, cost recovery, and siting are all subject to both state and federal jurisdiction. To meet the challenge of expanding transmission to implement decarbonization, the Federal Energy Regulation Commission (FERC) and the National Association of Regulatory Utility Commissioners (NARUC) recently announced the Joint Federal-State Task Force on Electric Transmission to focus on this issue.1 Resolving issues of siting and cost recovery for interstate electric transmission lines will encourage constructive state-federal cooperation. The task force and related regional and national coordination among the states, FERC, the Department of Energy (DOE), and federally regulated transmission providers will be critical to ensuring a resilient and clean power system.

    Bushnell, James, Scott Harvey, Benjamin Hobbs, and Steven Soft. “Opinion on Economic Issues Raised by FERC Order 745, “Demand Response Compensation in Organized Wholesale Energy Markets” ” (2011).Abstract


    On March 15, 2011, the Federal Energy Regulatory Commission released Order 745. The pur- pose of the Order was to require that demand response (DR) resources participating in RTO or ISO markets are paid at the locational marginal price when such resources contribute to the supply-demand balance as a substitute for generation and when the demand response resources pass a net benefits test defined in the order.

    Hogan, William. “ Demand Response Compensation, Net Benefits and Cost Allocation: Preliminary Comments ” (2010).Abstract


    The Federal Energy Regulatory Commission’s Supplemental Notice of Proposed Rulemaking (NOPR) addresses the question of proper compensation for demand response in organized wholesale electricity markets. Assuming that the Commission would proceed with the proposal “to require tariff provisions allowing demand response resources to participate in wholesale energy markets by reducing consumption of electricity from expected levels in response to price signals, to pay those demand response resources, in all hours, the market price of energy (also referred to as the ‘locational marginal price’ or ‘LMP’) for such reductions,” the Commission posed questions about applying a net benefits test and rules for cost allocation.

    There is now an extensive record in this matter, and I have written on the various issues. The purpose of the present paper is to summarize critical points and pose implications for the issues of net benefit tests and cost allocation. The limited time of the technical conference format dictates a certain brevity, referring to the prior submissions for a fuller exposition. My comments highlight several questions: Why are we here? Why is this subject so confusing? Why are retail rates relevant? How can we match ends and means? Do we need a net benefits test? How should we allocate costs? Where should we go from here?


    The Commission’s Supplemental NOPR did not address the underlying arguments presented in response to the original NOPR in this matter. But many of the basic issues in considering net benefits tests and cost allocation arise from the fundamentals that the Commission should address. Despite the important role that LMP plays in successful market design, the Commission should not assume that paying LMP is always appropriate.