Elec. Power Supply Ass'n (22-3176/3666) v. Fed. Energy Regulatory Comm'n
| Docket Number | 22-3176,22-3666,22-3794,22-3796 |
| Decision Date | 21 December 2023 |
| Parties | ELECTRIC POWER SUPPLY ASSOCIATION (22-3176/3666); PJM POWER PROVIDERS GROUP (22-3794/3796), Petitioners, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, PJM INTERCONNECTION, L.L.C., Intervenor-Petitioner (22-3794/3796), AMERICAN MUNICIPAL POWER, INC., OLD DOMINION ELECTRIC COOPERATIVE, PJM INDUSTRIAL CUSTOMER COALITION, PENNSYLVANIA PUBLIC UTILITY COMMISSION, MONITORING ANALYTICS LLC, and PJM INTERCONNECTION, L.L.C. (22-3176/3666); MARYLAND OFFICE OF PEOPLE'S COUNSEL, DELAWARE DIVISION OF THE PUBLIC ADVOCATE, and NEW JERSEY DIVISION OF RATE COUNSEL (22-3176/3666/3794/3796), Intervenors. |
| Court | U.S. Court of Appeals — Sixth Circuit |
Argued: October 19, 2023
On Petitions for Review of Orders of the Federal Energy Regulatory Commission. Nos. EL 19-58-006; ER 19-1486-003.
ARGUED:
Paul W. Hughes, McDermott Will & Emery LLP, Washington, D.C for Petitioners.
Jared B. Fish, Federal Energy Regulatory Commission, Washington D.C., for Respondent.
Jason T. Gray, Duncan & Allen LLP, Washington, D.C., for Intervenors.
ON BRIEF:
Paul W. Hughes, McDermott Will & Emery LLP, Washington, D.C for Petitioners.
Jared B. Fish, Federal Energy Regulatory Commission, Washington, D.C., for Respondent.
Jason T. Gray, Duncan & Allen LLP, Washington, D.C., Gerit F. Hull, American Municipal Power, Inc., Columbus, Ohio, Scott H. Strauss, Amber L. Martin Stone, Spiegel & McDiarmid LLP, Washington, D.C., Robert A. Weishaar, Jr., McNees Wallace & Nurick LLC, Washington, D.C., Kenneth R. Stark, McNees Wallace & Nurick LLC, Harrisburg, Pennsylvania, Jeffrey W. Mayes, Monitoring Analytics, LLC, Eagleville, Pennsylvania, Regina A. Iorii, Delaware Department of Justice, Wilmington, Delaware, Adrienne E. Clair, Jecoliah R. Williams, THOMPSON COBURN LLP, Washington, D.C., Christian A. McDewell, Kriss E. Brown, Pennsylvania Public Utility, Harrisburg, Pennsylvania, for Intervenors.
Before: Sutton, Chief Judge; Clay and Larsen, Circuit Judges.
Before us are two questions: Did the Chairman of the Federal Energy Regulatory Commission exceed his authority in moving for a remand of a ratemaking challenge without the support of any other members of the Commission? If not, did the Commission's underlying ratemaking decisions sink to the level of arbitrary and capricious agency action? As to the first question, the Commissioner exceeded his administrative authority. We accordingly remand the matter to the agency in the first instance to determine what, if anything, can or should be done about this ultra vires action. Once the agency has had the opportunity to resolve that point, any interested party may renew the petition for review of the second question.
Americans have come to expect their electricity and other forms of power to be available at the flick of a switch. But technology has not yet provided a cost-efficient way to store electricity. Utilities as a result must have the capacity to handle peak demand when consumers need it. Fed. Energy Regul. Comm'n, Staff Report, Energy Primer: A Handbook for Energy Market Basics 36-37, 46, 52 (Apr. 2020). Rather than make an expensive upfront investment in generator capacity that would sit unused most of the time, utilities typically agree to buy and sell excess reserves to their neighbors as supply and demand require. Id. at 36-37. A utility normally purchases power from its neighbors when the price falls under its own cost of generating an additional unit of electricity, and it sells power when it can obtain a price above its own costs. Id. at 37.
The market for electricity works only as well as power flows between generators and purchasers. Since the late 1990s, the government has required the utilities that own power plants to permit open access to their transmission lines. Id. at 39. When a power plant generates electricity, it flows across the entire transmission grid, mixing with power from other plants on its way to the purchaser. Id. at 54. Overseeing this transmission system for much of the country are "independent system operators" and "regional transmission organizations." Id. at 39, 61. These entities forecast the wholesale demand for electricity and determine which generators and load-serving entities on their grid are in the best position to supply it. Id. at 63-64. They also maintain generation reserves by purchasing capacity not currently scheduled for operation and arranging for it to enter operation if power production unexpectedly falls. Id.
The oldest of these organizations and the largest measured by all-time peak load is PJM Interconnection, L.L.C. Id. at 62. It started in 1927 as a reserves-pooling agreement between three utilities and expanded in 1956 to become the Pennsylvania-New Jersey-Maryland Interconnection. Id. at 38, 85. Hence PJM's current name. Today, the utility operates part or all of the transmission lines in 13 states in the mid-Atlantic and Midwest as well as the District of Columbia. Id. at 85. Governing PJM are a Board and a "Members Committee" representing five classes of stakeholders: power generators, transmission owners, electric distributors, power marketers, and large consumers. Id. at 86. Each day, PJM calculates the price of power at each location on the grid in advance and then adjusts the prices in real time. Id. at 87-88.
PJM also obtains reserves to maintain the reliability of the transmission system. PJM maintains "Step 1" reserves sufficient to replace its largest online generator within 15 minutes and "Step 2" reserves to address other supply shortfalls or fluctuations. Id. at 88; JA0981-82, ¶¶4-5. PJM acquires these reserves through auctions at which it offers to pay a price up to a "reserve penalty factor" approved by the Commission. JA0983-84, ¶7; see Energy Primer, supra, at 88-89. As its name suggests, the reserve penalty factor functions as a price cap and represents the maximum price the agency is willing to allow the market to set for a quantity of reserves. Put another (slightly more accessible) way, it's the highest cost that PJM will incur to redispatch its system to procure an additional megawatt of reserves. In 2012, the Commission approved a price cap for PJM's Step 1 reserves of $850 per megawatt hour, and in subsequent years the next 190 megawatts of Step 2 faced a cap of $300 per megawatt hour. Beyond that point, PJM usually pays nothing for additional reserves.
Over time, price caps create regulatory friction for businesses caught between fixed prices and ongoing market developments. See generally Samuel Evan Milner, Robbing Peter to Pay Paul: Power, Profits, and Productivity in Modern America 26-36, 178-81, 197-203 (2021) (providing examples of price controls that collapsed in the face of economic contingencies and dynamic markets). When PJM adopted its price caps for reserves, the maximum price at which energy suppliers could offer power to the market was $1,000 per megawatt hour. But in 2016, regulators raised the cap to $2,000 per megawatt hour. That change made it more difficult for PJM to obtain adequate reserves (by increasing the opportunity cost to forego market sales). This pricing schedule also did not place any value on additional reserves after the first 190 megawatts on top of Step 1, a threshold that PJM believed had become obsolete in the face of changing power market conditions. Between 2015 and 2017, for instance, PJM calculated that fluctuations in wind power alone would consume over 80% of that reserve. In practice, PJM continued to obtain most of its necessary reserves and often paid an auction price of $0 per megawatt hour for reserves because power plants already operating could supply idle capacity at no cost. But PJM believed that it had achieved this result only by "biasing" generator scheduling and undertaking out-of-market support, workarounds that it saw as evidence that this pricing system was faltering and would eventually lead to shortages. JA0039-40, JA0683.
Because PJM operates in the interstate market for transmitting and selling electricity, it could not modify its reserve price caps without approval from the Commission. See 16 U.S.C. § 824. Regional transmission organizations ordinarily seek approval for new rates under 16 U.S.C. § 824d, which requires a showing that the proposed rates are just and reasonable. But PJM's Operating Agreement allowed it to use that authority only if a weighted majority of its Members Committee approved it, and the Board failed to obtain the necessary stakeholder support.
In March 2019, the PJM Board instead filed this request under 16 U.S.C. § 824e(a), which required PJM to prove both that its existing rates were unjust and unreasonable and that its proposed replacements would cure the defects. PJM requested two major changes from the Commission. It asked the Commission to raise the reserve price cap for Step 1 to $2000 per megawatt hour, reflecting the costs that it believed it would have to pay to obtain reserves. And it asked the Commission to replace the flat $300 per megawatt hour cap after Step 1 with a downward sloping price schedule that would more accurately account for the value of additional reserves.
In May 2020, the Commission agreed with PJM that the existing price cap for reserves and stepwise demand curve were unjust and unreasonable. It found that PJM's reserve market "systematically fail[ed] to acquire within-market" reserves needed to operate its system reliably for three reasons. JA0687. First, PJM operators frequently distort demand upward in market forecast software. This persistent bias, the Commission reasoned, likely shows that the need for reserves "far exceed[s]" the mandatory requirements, suggesting a flaw in the existing...
To continue reading
Request your trial