Few observers outside the electric utility industry understand the U.S. power grid, often called the world’s largest machine. It’s three grids, actually—the Eastern Interconnect, the Western Interconnect, and the Texas Interconnect. Much of the Eastern and Western Interconnects are subdivided regionally into independent organizations—independent system operators (ISOs) or regional transmission operators (RTOs)—that monitor, coordinate, and control power distribution in their territories.
The largest among them is the PJM Interconnection. Initially named for Pennsylvania, New Jersey, and Maryland, PJM’s footprint today includes all or part of 13 states and the District of Columbia. PJM is the largest electricity market in North America, administering two main types of transactions—energy and capacity (there’s also a third transaction called ancillary services).
A Brief Explainer of PJM’s Market Constructs
Energy is just what it says: It’s electricity bid into the market by generating facilities at a specific price per megawatt-hour (MWh), based on the projected need in the day-ahead market for the next day, and the spot or “real-time” market, for immediate needs. Bids are “stacked” from lowest to highest, and the market price sets (“clears”) at the point where supply meets demand, based on the bid and accepted price of the last megawatt needed. Interestingly, once that price is set, all bids receive the final clearing price, regardless of the generators’ original bids.
The second market that PJM executes is an annual capacity market, what PJM calls the Base Residual Auction (BRA), which provides payments to power plants based on their generation capacity and an agreement to provide a specific amount of that capacity when called upon by PJM. These payments help cover their typically significant overhead and are a vital source of income for both scheduled and unscheduled maintenance needed to keep the plants available.
Capacity markets arose across sections of the country following location-specific deregulation, which began in 1988 with federal legislation, the Public Utility Regulatory Policies Act (PURPA), followed by the 1992 Energy Policy Act and buttressed by the Federal Energy Regulatory Commission’s (FERC) Acts 888, 889, and 2000. These acts broke up utilities’ vertical integration, which required utilities to sell their power plants to a third party or transfer them to an unregulated affiliate.
PJM’s Attempts to Ensure Reliable Capacity
PJM has typically held BRAs every spring for the power delivery period of June 1-May 31, three years ahead. However, in 2019 PJM suspended deadlines and activities related to the Base Residual Auctions for the 2022/2023 and 2023/2024 delivery years, “pending direction from [FERC] on new rules for the annual capacity auction” while FERC and PJM grappled with market issues and controversies around pricing for generation resources subsidized by the states, especially new entrants and renewables.
When the auction resumed last year, I wrote about the significant drop in capacity prices at that time, which cleared 144,477 MW for delivery year June 1 to May 31, 2023, at a cost of $3.9 billion. Costs were $4.4 billion lower than the 2021–2022 auction. Prices varied widely by sub-region, from a scant $50 MW/day in “RTO” which includes Ohio, West Virginia, and part of Maryland, Indiana, Kentucky, and Pennsylvania, to $126.50 MW/day in the Baltimore Gas & Electric (BGE) region. As a comparison, the price was $140/MW-day in the preceding 2018 auction.
This year things are different in one sense. Prices are for the next delivery year (June 1, 2023, to May 2024) rather than three years ahead. But they’re also the same. In a race to the bottom, RTO prices dropped again to $34.13 MW/day, while BGE regional prices plunged to $69.95 MW/day, with the same price for the Dayton Power & Light area.
PJM, the 500-pound gorilla of regional transmission operators, has a well-earned reputation for careful and precise capacity resourcing, system preparedness and reliability, sufficient reserves, and a well-managed grid. And PJM has gone the extra mile to ensure enough capacity in all conditions, arguably more than any other grid operator. Following the January 2014 brutally cold polar vortex and the “cold snap” that immediately followed, PJM recognized that several generators it had relied on could not provide electricity during these periods. System reliability was affected by gas curtailments and overall insufficient gas supplies; frozen mechanical equipment, frozen coal piles and coal handing equipment; frozen natural gas and oil lines—and, of course, record demand for electricity. Having lost about 20% of its generating capacity, the PJM grid was pushed to the brink of failure. But it held.
In response, PJM developed a program called “Capacity Performance” which would make larger capacity payments to generators, but also penalize them significantly if they failed to meet their commitments. The program, phased in over a two-year period to become the principal capacity product, also called for increased payments to generators that over-performed from others that under-performed.
Despite these innovations, capacity payments have plummeted. Observers noted that beyond providing significantly lower revenues, this year’s auction results saw about 11,000 fewer megawatts of generation offered into the BRA compared to the previous auction— even though it cleared about the same amount (144,870 MW) of capacity as last year. Cleared capacity included about 3,329 MW from new generation and 404 MW from uprates to existing or planned generation.
Competitive Generators Challenge FERC Decisions
The Electric Power Supply Association (EPSA), a trade organization representing competitive generators, weighed in on the auction results. While EPSA was pleased that the BRA procured sufficient capacity, it said it was concerned about maintaining sufficient compensation for resources to support reliability in all conditions and durations. “To the extent that the trend of retirements and lower additions of new resources continues in PJM, however, this may pose challenges sooner than expected and to surrounding regions as well as PJM itself. The BRA results are a clear reminder of the cumulative impact of FERC decisions on market design affecting supply and retirements.” EPSA also said it is “actively seeking reversal of the Focused [Minimum Offer Price Rule (MOPR)] and revisions to the Market Seller Offer Cap due to their negative impacts on generators that provide reliable, dispatchable power.”
EPSA, along with the PJM Power Providers Group, the Pennsylvania Public Utility Commission, and the Public Utility Commission of Ohio, moved to legally challenge FERC’s application of the MOPR, filing its initial brief with the U.S. Court of Appeals Third Circuit on May 9, 2022. The group’s main concern was FERC’s default approval of the MOPR as “arbitrary and capricious” and an “unreasoned departure” from precedent. The group argued that FERC is exceeding its authority under the Federal Power Act (enacted in 1920 to establish FERC’s regulation of hydropower resources and amended in 1935 to include electric utilities). The group argued that the MOPR favors state-preferred resources to the detriment of other existing resources and imposes costs and policy choices from some states onto neighboring states.
Separately on June 13, in the U.S. Court of Appeals District of Columbia Circuit, EPSA, and its co-petitioners appealed FERC’s ruling on PJM’s Market Seller Offer Cap. The cap is applied to Capacity Market bids to prevent the bidder from exercising market power, the ability of an organization or group to set or substantially affect market prices in a particular geographic area. The cap is either a default or a “unit-specific” cap, determined by a supplier’s request but based on a FERC-approved formula.
Under PJM’s prior rules, the default cap recognized that a competitive capacity offer could include the opportunity cost of assuming a capacity commitment. FERC had previously found that feature is critical to PJM’s market design, and the D.C. Circuit Court affirmed that finding. But subsequently, the petitioners argued, FERC abandoned that approach and the economic theory underlying the broader market structure “without explanation or even acknowledgment that it was doing so.”
Power markets in the U.S., including PJM, continue to change and evolve, particularly as developers plan, build, and interconnect new utility-scale renewables to an aging, overstressed, and constrained grid. And it’s anyone’s guess whether the U.S. Supreme Court decision on June 30 that dramatically curtails the Environmental Protection Agency’s authority to limit greenhouse gas emissions from power plants could eventually extend to other federal regulatory agencies, including FERC. In the meantime, grid operators nationwide will face worsening and devastating weather events, wildfires, insufficient base and peaker resources—and, yes, low capacity prices that may force many more generating resources to shutter permanently.
—David Gaier is an independent writer and corporate communications consultant, and previously a spokesman for two major public energy companies. He has also worked in-house and in agencies across several industries and is a U.S. Marine Corps and U.S. Foreign Service veteran.