PJM’s Independent Market Monitor sounded alarms about market power in the energy and capacity markets Thursday and said it may intervene in the RTO’s next Base Residual Auction in May.

Joe Bowring, president of IMM Monitoring Analytics, made his comments in releasing the 2020 State of the Market report.

Bowring cited what he called lax enforcement of PJM’s must-offer requirement, overpayments to black start operators and units that fail to follow dispatch. He warned that abuses are likely to increase when the RTO initiates fast-start pricing. PJM spokesman Jeff Shields declined immediate comment on the report, saying the RTO will address the findings in its formal response in the second quarter.

Prices, Load down

The Monitor’s report also summarized the impact of the COVID-19 pandemic. “If there was only one story to tell about the market in 2020, it’s that prices were down and down significantly,” Bowring said.

A reduction in average hourly load (-3.1%) and load-weighted average LMPs (-20.4%) resulted in a 14% drop in PJM billings to $33.6 billion. Real-time, load-weighted LMPs averaged $21.77/MWh last year, the lowest since the PJM markets began in 1998. Load was the lowest since 2011.

For the first time, transmission costs exceeded capacity costs as a share of the total price of wholesale power. Transmission rose from $10.39/MWh in 2019 to $11.98/MWh in 2020 while capacity’s share fell from $11.27/MWh to $9.45/MWh.

Bowring said the shift resulted from several factors. “There are a lot of transmission projects going on. There is no competition for transmission. … And it’s also the case that capacity prices for this period were relatively modest.”

Capacity Resources

Among the Monitor’s recommendation was tougher enforcement of rules requiring generators with capacity contracts to offer their full installed capacity (ICAP) into the day-ahead market.

Bowring said units whose capacity is reduced because of ambient derates during hot weather should be required to take forced outages for the difference.

During 2020, an average of 1,167 MW of capacity failed to meet the ICAP must-offer requirement, and in 10% of the hours, the shortfall was 2,026 MW. “These megawatt levels are larger than the reserve shortages that triggered scarcity pricing in 2020 and larger than most supply contingencies that led to synchronized reserve events in 2020,” the report said.

It also said storage and intermittent resources should be subject to an enforceable ICAP must-offer rule reflecting their limitations and that storage should never be considered as transmission.

Bowring also reiterated his opinion that the capacity market seller offer cap is “way too high,” the subject of a February 2019 complaint on which FERC has not acted. (See Monitor Defends Offer Cap Complaint.)

“It’s going to be interesting to see whether they address it prior to the next auction [in May] because it’s conceivable that market power will be exercised using that high market seller offer cap,” Bowring said. “And if it is, then there’s a significant possibility that we will actually file a complaint in the middle of the auction.”

He also repeated his call for limiting capacity to “physical and substitutable” assets, saying demand response and energy efficiency should be excluded from the market and considered in demand calculations.

Energy Market, Virtual Bidding

Bowring also said weakened fuel-cost policies are undermining the ability to ensure that cost-based offers are verifiable and enforceable.

He additionally called for closing “loopholes” that allow resources to avoid offer capping even after failing the three-pivotal-supplier test. “When you fail the three-pivotal-supplier test, you should be offer capped, and there should be no way to evade it,” he said. “And there are ways to evade it at the moment.”

Markup, which Bowring said is one measure of market power, represented 10% of prices in 2020, or $2.19/MWh.

“In the fourth quarter of 2020, there were about 80 days in which there were three pivotal suppliers, and if you add them up for the four quarters of the year, it’s several hundred days in which there were three jointly pivotal units. At the moment there are no rules in PJM to address that.”

Bowring said the problem is FERC rulings allowing generators to use market-based rates even if they have market power, based on an assumption that RTO mitigation rules will prevent abuses.

“We took the commission up on that and started filing market-based rate filings, saying we do not believe that the implementation of market power mitigation in PJM is adequate,” Bowring said. (See PJM Monitor Challenges MBRAs over Market Power.)

Failing the TPS test “should result in a cost-based offer with zero markup,” he added.

The report recommended PJM prevent uplift payments to units not following dispatch or using inflexible operating parameters.

“If you put in really inflexible parameters because you haven’t invested in your unit or choose not to, that’s your choice. But the market should not be paying you uplift as a result of that,” Bowring said. “We think PJM has allowed coal units to have unduly inflexible parameters.”

Bowring said PJM overpaid such units $3.8 million in the last several years. “When we see it, we talk to both the generation owner and PJM. In some cases that money has been returned; in some cases it’s not. But we’re continuing to pursue those cases.”

He said uplift payments are likely to significantly increase with the implementation of fast-start pricing, when uplift will be calculated every five minutes.

“There’s a significant difference being introduced between what the dispatch signal tells you and what the price tells you, so we expect there are going to be more units not following dispatch. And the fact that PJM doesn’t have good rules for tracking that will result in uplift,” he said. “We expect that result to be very significant.”

The IMM praised FERC for recently eliminating virtual bidding at all but aggregates and zones. But it said the commission should go further and eliminate trading at nodes that aggregate only small portions of the transmission system.

The current rules allow virtual traders to take advantage of differences between day-ahead and real-time modeling, “which is what we term ‘false arbitrage,’” Bowring said. “It’s not helping the market.”

Ancillary Services, Gas

The report also repeats the Monitor’s call for new capital recovery factors (CRF) for black start units that incorporate current tax rates. Black start units also should be required to commit to providing black start service for the life of the unit, the IMM said.

It calculated that PJM is overpaying black start units $15 million annually under current rules, with lifetime overpayments totaling $96 million. Bowring acknowledged that black start owners dispute the Monitor’s calculations. “My guess is that [the dispute is] ultimately going to end up in front of the commission,” he said.

Bowring also had criticism for the natural gas market, citing the high prices experienced in ERCOT last month.

“I think that it’s very clear that market power is being exercised in the commodity market for gas during extreme conditions,” he said. “We think there should be an ISO for gas pipelines … which I think would be good for the business models of pipelines as well as its integration with the power markets.”

Coal Market Share Continues Decline

Last year saw a continuation in the shift away from coal and toward natural gas.

Coal-fired generation dropped by almost 21%, making up 19% of the total fuel mix for the year. Natural gas production rose almost 7% to claim a 40% market share, while nuclear was nearly unchanged at 34%. Wind production rose almost 10% to a 3.3% share, while solar with net energy metering rose 38% but amounted to only 0.5% of the total. Although battery production almost doubled to 36 GWh, its share was less than that for solar.

Coal-fired generators, which were the marginal real-time units three-quarters of the time as recently as 2008, were on the margin less than 20% of the time in 2020, with natural gas marginal almost 80% of the time.

For the second year in a row, average short run marginal costs for coal plants were higher than that for gas-fired combustion turbines.

Only 5% of coal units recovered their avoidable costs in 2020, down from 26% in 2019 and 68% in 2018. “The economics of coal remain very challenging,” Bowring said.

Seven coal units with a combined capacity of 2,361 MW are at risk of retirement out of a fleet of 49,744 MW, the IMM said. Also at risk are 50 combustion turbines totaling 1,829 MW and seven other units totaling 574 MW. All the at-risk units had an average age of at least 43 years.

The Monitor said its analysis of PJM’s nuclear fleet found that all but the single-unit Davis Besse and Perry plants in Ohio were profitable last year, even when subsidies for those in Ohio, Illinois and New Jersey were excluded.

“What it demonstrates is that the units receiving [zero-emission credits] in Illinois and New Jersey … do not need them, and we’ve said that to the regulators in Illinois and New Jersey,” Bowring said.

Less than Meets the Eye

Bowring noted that although the nameplate capacity for wind and solar projects in PJM’s interconnection queue exceed that for combined cycle plants, the higher attrition rates of renewable projects and derates for their capacity contributions means they will not overtake gas any time soon.

There are currently 23 GW of combined cycle projects in the queue, about 15.8 GW of which will go into service based on historical completion rates.

While solar projects have a combined nameplate capacity of 79 GW, only 9.6 GW are likely to be completed, and that would be derated to 4.5 GW based on effective capacity. Similarly, wind projects totaling 31.7 GW are likely to result in only 953 MW of effective capacity.

“It does not mean that we’re going to see more solar than combined cycled added any time soon,” Bowring said. “It could eventually mean that, but based on the existing data, it does not mean that.”