If you’ve been following US wholesale power markets (and in particular PJM), you might be confused by all the commotion around the PJM capacity auction delays and random buzzwords (e.g. MOPR, FRR). While there have been lots of articles written about PJM’s capacity market, much of the information is scattered and assumes some existing knowledge of capacity markets and/or current events. Here I’ve tried to put together a basic introduction to PJM capacity markets and recent market developments below. This knowledge will be particularly helpful if you’re interviewing for MBA utility leadership programs in PJM markets (e.g. Exelon, PSEG), but overall, it’s just an interesting story to follow in the utility-scale power space.
How PJM Power Plants Are Compensated:
PJM is the largest and oldest power market in the US, coordinating electricity across 13 states. PJM has multiple power markets (i.e. energy, capacity, ancillary services), so a power plant in PJM will often receive multiple revenue streams. Take a 100MW gas-fired plant, which might receive:
Energy payments, which compensate for actual MWh generated (paid as $/MWh). If the 100WM plant has a capacity factor of 50%, at an average wholesale power price of $25, this equates to 100MW * 50% * 8760hrs in year * $25 = $10,950,000.
Capacity payments, which compensate for standby generation (paid as $/MW-day). If the 100MW plant receives at a capacity price of $100-MW/day, each year my plant receives 100MW * $100/MW-day * 365 days a year = $3,650,000.
Ancillary service payments, which are typically smaller than energy and capacity and help support the grid (e.g. balancing the grid).
Some more information can be found here or the PJM website in general.
It’s helpful to understand capacity markets in particular. Without going into too much detail, capacity payments were originally meant to incentivize new generation and help increase power resources – in the example above, a new 100MW power plant would be offered $100/MW-day ($3.65 million per year in the example above) just for getting built. PJM does this because they want to ensure they have enough reserve margin to meet peak demand, and needs new plants to provide availability capacity during extremely hot days. Other markets, such as ERCOT, are energy-only and don’t have capacity markets, which is why ERCOT energy prices can shoot up to $9,000/MWh during peak times.
Years ago, PJM’s generation mix contained coal and natural gas plants that might have received ~ 2/3 revenue from energy and 1/3 from capacity. Over time, with the onset of cheaper renewables and newer, more-efficient gas fired plants, aging gas plants that once operated round-the-clock were no longer profitable serving as baseload, and thus shifted to provide generation only during peak hours. Thus, their energy payments decreased greatly due to lower generation, but their capacity payments stayed consistent.
The original intent of the capacity market was to incentivize new build and help increase revenue, but older coal plants sometimes rely almost exclusively on capacity payments to stay in operation. While fossil plants initially received 33% of total revenue from capacity payments, today these older plants might receive >70% of revenue from capacity payments, and depend on them to remain in operation.
PJM Capacity Market Pricing / MOPR:
Capacity prices are set through annual clearing auctions, where generating plants bid capacity prices and a subset of all bids clear. In PJM, this is called the Reliability Pricing Model (“RPM”), and prices are set in a 3-year forward looking auction that locks in capacity prices for next 3 years (i.e. 2019 auction will set prices from 2020 through 2023).
When the PJM capacity market was first established, it also included a minimal offer price rule (“MOPR”) that barred gas generators from “artificially depressing” capacity auction clearing prices through below-cost bids. New gas-fired plants couldn’t bid a below-market price in order to guarantee clearing the market, and were subject to bidding their minimum cost (set to 90% the cost of new entry) . This article does a great job of clearly explaining MOPR .
While there are various PJM capacity pricing sub-zones and the details are more complex, in general, PJM capacity prices have been falling over time due to less-expensive and more efficient generation bidding lower prices at each auction. Thus, legacy gas and coal plants, which already lost much of their energy revenues, were now facing potential capacity revenue declines as well. PJM capacity prices haven’t declined nearly as much as NY-ISO prices – see this other post I wrote on the NY-ISO capacity market.
The MOPR Issue:
In 2016, Calpine and other large fossil generators filed a complaint with PJM regarding price suppression in capacity markets caused by state subsidies. The argument was that if a state provided incentives or RPS mandates requiring utilities to procure renewables (and forced utility companies to sign a PPA with a solar plant), then the ‘cost’ of new generation was subsidized, which allowed these new solar plants to bid a clearing price lower than the MOPR rule gas generators were subject to. Their complaint alleged that:
The existing MOPR was unjust and unreasonable because it failed to address impact of subsidized resources on the capacity market
States were interfering with FERC’s exclusive jurisdiction over wholesale markets
Since MOPR applied only to new natural gas-fired resources, “it failed to mitigate price distortions caused by out-of-market support granted to other types of new entrants or to existing capacity resources of any type”
Generation resources (e.g. solar, wind, nuclear) receiving out-of-market support had increased substantially and depressed capacity prices, affecting the competitiveness of existing gas generation
See more info here
In 2018, PJM filed several proposals to FERC to attempt to reform its capacity market. One proposal tried to create a two-stage capacity market to handle the price impacts of subsidized resources. The other expanded the Minimum Offer Price Rule (MOPR) to cover subsidized resources. (more info here)
FERC ruled later that year that PJM’s MOPR was indeed unfair, but rejected both proposals put forward and required PJM to come up with a new solution.
Commission found that PJM’s existing capacity market rules were unjust and unreasonable under the Federal Power Act and must be modified
Subsidies-enabled resources had a “suppressive effect” on the price of capacity procured by PJM through its capacity market
FERC called for a fix that would include expansion of MOPR to apply to both new and existing resources
FERC requested PJM to change current capacity market to ensure subsidized plants did not suppress capacity prices
more info here
In mid-2019, FERC forced PJM to delay its annual capacity auction, and instead wait for a FERC-approved tariff. The 2019 PJM capacity auction was delayed (which set prices through 2022-2023), and is still currently in limbo.
In December 2019, FERC finally issued its PJM capacity market mitigation order.
PJM must expand current MOPR to cover all new (incl. renewables) and existing resources that receive state subsidies
Resources exempt from MOPR include existing renewables and new resources not receiving state subsidies
more info here
What the New MOPR Rule Means:
The near-term impact means nuclear generators and new renewables must bid their competitive cost in the capacity market, thereby raising near-term capacity prices.
Many renewables and nuclear plants receive some form of out-of-market subsidies. Subject to the new MOPR, they must bid their true costs and will raise their bids (which might prevent them from clearing).
Capacity prices are therefore expected to be higher in the near-term.
The new MOPR effectively raises the price floor for all new state-subsidized resources, and will prevent more nascent industries, such as offshore wind, from bidding into the capacity market at a clearing price
While the decision harms new renewables that might depend on immediate capacity payments, it also keep legacy coal and fossil units dependent on capacity prices in operation.
The longer-term impact is unclear. As part of PJM rules, states have the option to depart the PJM capacity market altogether under the Fixed Resource Requirement (“FRR”). In particular,
The Fixed Resource Requirement alternative (FRR) allows states’ utility companies to secure capacity outside of PJM, so long as they can demonstrate that resource plans satisfy PJM's federally-mandated reliability requirements
Several states already have ambitious renewables goals and/or existing subsidized nuclear generation may adopt FRR, thereby leaving the PJM capacity market. States with offshore wind goals (NJ) or heavily subsidized nuclear (IL), would likely benefit under the FRR
Major utility companies in these states (e.g. Exelon, PSEG) have also been urging states to leave PJM, which would help their existing assets compete (e.g. Exelon’s nuclear plants, PSEG’s new offshore wind goals...etc.)
more info here
So it’s complicated and very controversial, but the short of it is that there’s currently a lot of uncertainty around the future PJM capacity market. I’m interested to see what states will do and the impact on future capacity market prices. The next PJM capacity auction may resume as early as next year, and by then, we’ll have much better visibility on the future of PJM. If you have any other questions, feel free to reach out.
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