FirstEnergy coal deactivations key to PJM shutdowns so far in 2013

As of Sept. 30, 63,765 MW of capacity were in generation request queues in the PJM Interconnection region for construction through 2024, compared to an average installed capacity of 195,000 MW in the first nine months of 2013.

Wind projects account for 16,442 MW of nameplate capacity or 25.7% of the capacity in the queues and gas-fired combined-cycle projects account for 37,634 MW of capacity or 59% of the capacity in the queues.

Those figures are from a report released Nov. 14 on the state of the market in PJM covering the third quarter and the first nine months of this year. The report was prepared by Monitoring Analytics LLC, the Independent Market Monitor for PJM.

There are 22,070.4 MW planned to be retired between 2011 and 2019, with all but 614.5 MW retired by June, 2015, around the time the federal Mercury and Air Toxics Standards take effect (the initial MATS compliance deadline is April 2015). The AEP zone accounts for 3,560 MW, or 32.7% of all MW planned for deactivation from 2013 through 2019. Since Jan. 1, 2013, 1,437 MW that were scheduled to be deactivated have withdrawn their deactivation notices, and are planning to continue operating, including the Avon Lake and New Castle generating units in the ATSI zone.

These are the upcoming plant retirements through the end of 2014:

  • Walter C Beckjord Units 2-3, DEOK region, 222 MW, Coal, Nov. 21, 2013;
  • Indian River Unit 3, DPL, 169.7 MW, Coal, Dec. 31, 2013;
  • BL England Unit 1, AECO, 113 MW, Coal, May 1, 2014;
  • Deepwater Units 1 and 6, AECO, 158 MW, Natural gas (steam), May 31, 2014;
  • Riverside Unit 6, BGE, 115 MW, Natural gas (combustion turbine), June 1, 2014;
  • Portland, Met-Ed, 401 MW, Coal, June 1, 2014;
  • Burlington Unit 9, PSEG, 184 MW, Kerosene (combustion turbine), June 1, 2014;
  • Chesapeake Units 1-4, Dominion, 576 MW, Coal, Dec. 31, 2014; and
  • Yorktown Units 1-2, Dominion, 323 MW, Coal, Dec. 31, 2014.

The actual deactivations this year through Oct. 9, with summer net dependable MW ratings, were:

  • Exelon Corp., Schuylkill Unit 1, 166 MW, Heavy Oil, PECO, Jan. 1;
  • Exelon Corp., Schuylkill Diesel, 3 MW, Diesel, PECO, Jan. 1;
  • Ingenco Wholesale Power LLC, Ingenco Petersburg, 2.9 MW, Diesel, Dominion, May 31;
  • AES Corp., Hutchings Unit 4, 61.9 MW, Coal, DAY, June 1;
  • NRG Energy, Titus Unit 1, 81 MW, Coal, MetEd, Sept. 1;
  • NRG Energy, Titus Unit 2, 81 MW, Coal, MetEd, Sept. 1;
  • NRG Energy, Titus Unit 3, 81 MW, Coal, MetEd, Sept. 1;
  • NextEra Energy, Koppers Co. IPP, 8 MW, Wood waste, PPL, Sept. 30;
  • FirstEnergy, Hatfield’s Ferry Unit 1, 530 MW, Coal, AP, Oct. 9;
  • FirstEnergy, Hatfield’s Ferry Unit 2, 530 MW, Coal, AP, Oct. 9;
  • FirstEnergy, Hatfield’s Ferry Unit 3, 530 MW, Coal, AP Oct. 9;
  • FirstEnergy, Mitchell Unit 2, 82 MW, Coal, AP, Oct. 9; and
  • FirstEnergy, Mitchell Unit 3, 277 MW, Coal, AP, Oct. 9.

Certain PJM regions to rely more heavily on combined cycle gas

A potentially significant change in the distribution of unit types within the PJM footprint is likely as a combined result of the location of generation resources in the queue and the location of units likely to retire. In both the Eastern MAAC (EMAAC) and Southwestern MAAC (SWMAAC) locational deliverability areas (LDAs), the capacity mix is likely to shift to more natural gas-fired combined cycle (CC) and combustion turbine (CT) capacity. Elsewhere in the PJM footprint, continued reliance on steam (mainly coal) seems likely, despite retirements of coal units, the report noted.

The PJM queue contains a substantial number of projects that are not likely to be built, including 15,726 MW that should already be in service based on the original queue date, but that is not yet even under construction. These projects may also create barriers to entry for projects that would otherwise be completed by taking up queue positions, increasing interconnection costs and creating uncertainty, the report added.

Natural gas, especially in the eastern part of PJM, increased in price in the first nine months of 2013. Comparing prices in the first nine months of 2013 to the first nine months of 2012, the price of Northern Appalachian coal was 0.4% lower; the price of Central Appalachian coal was 2.8% higher; the price of Powder River Basin coal was 24.1% higher; the price of eastern natural gas was 54% higher; and the price of western natural gas was 43% higher. Natural gas prices were above coal prices in the first nine months of 2013, with prices above $10/MMBtu for some days.

In the first nine months of 2013, nuclear units had a capacity factor of 93.8%, compared to 92.7% in the first nine months of 2012. Combined cycle units ran less often, decreasing from a percent capacity factor of 62.9% in the first nine months of 2012 to 52.9% in the first nine months of 2013. The capacity factor for steam units, which are primarily coal fired, increased from 45.5% in the first nine months of 2012 to 49.8% in the first nine months of 2013, the report said.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.