Maryland floats revised NOX plan that will again endanger some coal capacity

In its Nov. 4 Form 10-Q quarterly report, NRG Energy (NYSE: NRG) said that a revised NOX-control proposal from the Maryland Department of the Environment (MDE) is a danger to coal-fired capacity in that state.

Said the brief Form 10-Q notation: “In December 2014, MDE proposed a regulation regarding NOx emissions from coal-fired electric generating units, which if finalized would have required by 2020 the Company (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to either (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. In early 2015, a new gubernatorial administration in Maryland decided not to finalize the regulation as proposed. In September 2015, MDE proposed revised regulations to address future NOx reductions, which when finalized may negatively affect certain of the Company’s coal-fired units in Maryland.”

What it is referring to is a NOx proposal that MDE issued on Sept. 18 and was taking comment on until Oct. 23. That proposal said that these regulations apply to thirteen coal-fired EGUs currently operating in Maryland, which account for most of the state’s power plant NOx emissions:

  • Brandon Shores Generating Station (Units 1 and 2);
  • C.P. Crane Generating Station (Units 1 and 2);
  • H.A. Wagner Generating Station (Units 2 and 3);
  • Chalk Point Generating Station (Units 1 and 2);
  • Morgantown Generating Station (Units 1 and 2); and
  • Dickerson Generating Station (Units 1, 2 and 3).

Crane, Wagner and Brandon Shores belong to Talen Energy (NYSE: TLN), though Talen has a pending deal to sell Crane to another party. Chalk Point, Morgantown and Dickerson belong to NRG.

The MDE noted that most of these coal units are old and may have limited useful lives. To meet prior air mandates, selective catalytic reduction (SCR) was installed on the newer, bigger units, with cheaper selective catalytic reduction (SNCR) installed on the older, smaller units that tend to run little these days.

The Brandon Shores units, which are relatively new (built in the 1980s), and the Morgantown units are all equipped with SCR. Wagner Unit 3 and Chalk Point Unit 1 also have SCR. The other units all have SNCR or selective alternative catalytic reduction (SACR) controls.

MDE is proposed four compliance options for these coal units:

  • The first option requires the installation and operation of an SCR on any unit by June 1, 2020. Under option one, an owner or operator must install and continuously operate an SCR control system at all times, not to exceed a NOx emission rate of 0.09 lbs/MMBtu during the ozone season based on a 30-day rolling average. The NOx emission rate (0.09 lbs/MMBtu) was based upon a comprehensive review of literature on SCR installations and represents an achievable emission rate associated with state-of-the-art SCR technology at coal units. In all applicable cases, this would require removal and replacement of any existing SNCR or SACR with a SCR. Estimated costs for state-of-the-art SCRs can range from $40 million to $200 million (2014 dollars) per unit, with the additional cost of operating and optimizing the SCR ranging from $430,000 to $4.3 million (2014 dollars) on a per unit basis. Retrofit costs in addition to other factors, such as physical layout of the plant may add additional costs to the installation of SCR on some existing coal-fired EGUs.
  • The second option requires the unit to permanently retire by June 1, 2020. Deactivation of coal-fired EGUs removes NOx emissions that were produced from older, lesser controlled units. The market will determine which energy source will replace the energy capacity loss from the retired coal-fired energy, the department said. Cost impacts are indeterminate.
  • The third option requires the unit to permanently switch fuel from coal to natural gas by June 1, 2020. The feasibility of this option will be affected by the proximity of the unit to adequately-sized natural gas pipelines and the availability of natural gas as a fuel. This option may also entail significant costs and lead time to design and install a new boiler or retrofit an existing boiler to operate on natural gas. Costs associated with conversion from coal to natural gas are typically 15% to 30% (based on 2013 estimates) of the cost of installing a new natural gas boiler, while the installed costs of natural gas combined cycle generation is approximately $1 million/MW of capacity, the MDE noted. However, several studies have noted that it could be more cost effective to construct a new natural gas-fired unit than to retrofit an existing coal-fired unit to natural gas. A new natural gas combined cycle unit of 25 MW-300 MW could cost an estimated $25 million to $300 million (2014 dollars).
  • The fourth option requires a systemwide NOx 24-hour block average or NOx mass cap be met by June 1, 2020, and deeper ozone season NOx reductions in 2016, 2018 and 2020. This option allows affected units to choose between meeting a daily systemwide NOx tonnage cap of 21 tons per day for every day of the ozone season or meeting a systemwide NOx emission rate of 0.13 lbs/MMBtu as a 24-hour block average. The rate and the cap in option 4 are consistent with levels assuming SCR controls on all units. If option 4 is selected, more stringent 30-day systemwide rolling average NOx emission rates must be met starting in May 2016, 2018 and 2020. The fourth option requirements are anticipated to be met through averaging emissions from well performing SCR units and emissions from the SNCR-equipped units.

New gas-fired plants are in the works in Maryland

There are currently four natural gas combined cycle (NGCC) plants proposed in Maryland, the MDE pointed out:

  • Mattawoman Energy Project is a proposed natural gas-fueled, 859-MW combined cycle generating station featuring two H-class combustion turbines and two duct-fired heat recovery steam generators that is slated for construction in Brandywine, Maryland, with an estimated completion date of 2017.
  • Old Dominion Electric Cooperative’s Wildcat Point is a proposed combined-cycle, natural gas-fired plant slated for construction on the Rock Springs site in Cecil County, Maryland. The plant which will be supplied natural gas via the Transco pipeline will generate approximately 1,000 MW.
  • Keys Energy Center is a proposed natural gas-fired combined-cycle plant in Prince George’s County, Maryland, scheduled to be on line by mid-2017. The facility is expected to bring 735 MW of electrical generation to Maryland.
  • The Competitive Power Ventures (CPV) St. Charles project is a proposed 661-MW natural gas-fired combined cycle plant in Charles County, Maryland.

“While there is a large degree of uncertainty regarding possible retirement of existing coal-fired power plants and resulting job losses, the expansion of the natural gas electric generation sector can be a catalyst for economic growth in Maryland,” the MDE 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.