PJM Interconnection’s wholesale electric energy, capacity and regulation markets produced competitive results during the first quarter of this year, said the “2015 State of the Market Report for PJM: January through March,” released May 18 by Monitoring Analytics LLC, the Independent Market Monitor for PJM.
The Independent Market Monitor, Joseph Bowring, analyzed of market structure, participant behavior and market performance for each of the PJM markets. “Our analysis concludes that the results of the PJM Energy, Capacity and Regulation Markets in the first three months of 2015 were competitive,” Bowring said.
Energy market prices decreased significantly from the first three months of 2014 as a combined result of lower fuel prices, lower demand and improved grid operations. The load-weighted average real-time Locational Marginal Price (LMP) was 45.2% lower in the first three months of 2015 than in the first three months of 2014, $50.91 per MWh versus $92.98 per MWh. But the load-weighted average LMP in the first three months of 2015 was 36.1% higher than in the first three months of 2013 and was higher than the load-weighted average LMP in the first three months of 2009 through 2013 and for 11 of 16 first quarters since the markets began in 1999.
Energy prices in PJM in the first quarter of this year were set, on average, by units operating at, or close to, their short run marginal costs, although this was not always the case during the high demand hours in February and March. This is evidence of generally competitive behavior and resulted in a competitive market outcome.
Net revenue is a key measure of overall market performance as well as a measure of the incentive to invest in new generation to serve PJM markets. While net revenues were uniformly lower in the first three months of 2015 than in the first three months of 2014, net revenues were higher than in the first quarter of 2013. The comparison to the first three months of 2014 reflects the high net revenues in January 2014. In the first three months of 2015 compared to the first three months of 2014, average net revenues decreased by 50% for a new combustion turbine, 44% for a new combined cycle, 61% for a new coal plant, 72% for a new diesel unit, 50% for a new nuclear plant, 26% for a new wind installation, and 13% for a new solar installation.
While total energy uplift charges decreased by $560.6 million or 75% in the first three months of 2015 compared to the first three months of 2014, from $747.5 million to $186.9 million, total uplift was still high compared to prior years, reflecting, among other things, inflexible gas supply arrangements.
Congestion costs decreased in PJM by $603.6 million or 48.8%, from $1,236.1 million in the first three months of 2014 to $632.5 million in the first three months of 2015. Congestion reflects the underlying characteristics of the power system, including the capability of transmission facilities, the fuel cost and geographic distribution of generation facilities and the geographic distribution of load. Congestion is neither good nor bad, but is a direct measure of the extent to which there are multiple marginal generating units dispatched to serve load as a result of transmission constraints and the costs of operating those units. ARRs and FTRs serve as an effective, but not total, offset against congestion. ARR and FTR revenues offset 88.5% of the total congestion costs in the Day-Ahead Energy Market and the balancing energy market within PJM for the first ten months of the 2014 to 2015 planning period.
During the first quarter, PJM installed capacity increased 65.5 MW or 0.0% from 183,724.1 MW on Jan. 1 to 183,789.6 MW on March 31. Installed capacity includes net capacity imports and exports and can vary on a daily basis. Of the total installed capacity on March 31: 39.7% was coal; 30.8% was gas; 18% was nuclear; 5.8% was oil; 4.7% was hydroelectric; 0.4% was wind; 0.4% was solid waste; and 0.1% was solar.
As of March 31, a total of 67,268.0 MW of capacity were in generation request queues for construction through 2024, compared to an average installed capacity of 200,808.1 MW as of March 31. Of the capacity in queues, 8,703.1 MW, or 12.9%, are uprates and the rest are new generation. Wind projects account for 15,216.0 MW of nameplate capacity or 22.6% of the capacity in the queues. Combined-cycle projects account for 40,933.4 MW of capacity or 60.9% of the capacity in the queues.
On the other hand, 26,787.8 MW have been, or are planned to be, retired between 2011 and 2019, with all but 2,924.8 MW planned to be retired by the end of 2015. The AEP Zone accounts for 6,024.0 MW, or 22.5%, of all MW planned for retirement from 2015 through 2019. That is due to a major coal plant shutdown program of American Electric Power (NYSE: AEP), with most of the AEP shutdowns to occur by June 1 of this year.
The report noted that a significant change in the distribution of unit types within the PJM footprint is likely as natural gas-fired units continue to be developed and steam units continue to be retired. While only 1,992.5 MW of coal-fired steam capacity are currently in the queue, 9,343.8 MW of coal-fired steam capacity are slated for deactivation. Most of these retirements, 7,692.8 MW, are scheduled to take place by June 1, 2015, in large part due to the EPA’s Mercury and Air Toxics Standards (MATS). In contrast, 43,479.3 MW of gas-fired capacity are in the queue, while only 1,572.0 MW of natural gas units are planned to retire. The replacement of coal steam units by units burning natural gas could significantly affect future congestion, the role of firm and interruptible gas supply, and natural gas supply infrastructure, the report added.