NRG Energy (NYSE: NRG) expects to deactivate the gas-fired Contra Costa plant in California in May of this year, with other former GenOn Energy power plants to be deactivated in 2015, said NRG in its Feb. 27 annual Form 10-K report.
In December 2012, NRG completed a takeover of GenOn Energy, which added a whole new roster of power plants, many of them coal-fired, that GenOn had previously targeted for deactivation. NRG said it expects to deactivate these former GenOn plants on this schedule, with all MW ratings on a net basis and representing NRG’s share of the plant:
- Avon Lake (coal), Ohio, April 2015, 730 MW;
- Contra Costa (natural gas), California, May 2013, 675 MW;
- Gilbert (natural gas), New Jersey, May 2015, 190 MW;
- Glen Gardner (natural gas), New Jersey, May 2015, 160 MW;
- New Castle (coal), Pennsylvania, April 2015, 330 MW;
- Portland (coal), Pennsylvania, January 2015, 400 MW;
- Titus (coal), Pennsylvania, April 2015, 245 MW; and
- Werner (oil), New Jersey, May 2015, 210 MW.
NRG will also:
- deactivate the coal-fired Indian River Unit 3 (150 MW) in Delaware by Dec. 31, 2013;
- place the coal-fired units at the Shawville facility (600 MW) in Pennsylvania in long-term protective layup in April 2015;
- deactivate the 335-MW Unit 3 at the 670-MW El Segundo gas-fired plant in California within 90 days from the date of first fire of the second unit at the replacement El Segundo Energy Center, which is under construction. This deactivation is currently estimated to occur by the end of the second quarter in 2013.
El Segundo Energy Center LLC is continuing construction at its El Segundo Power Generating Station, a 550-MW fast-start, gas turbine combined-cycle facility in El Segundo, Calif. The facility is being constructed under a 10-year, 550-MW power purchase agreement (PPA) with Southern California Edison. NRG expects a commercial operation date of Aug. 1, 2013.
Through the GenOn acquisition, the company is continuing construction of the Marsh Landing project, a 720-MW natural gas-fired peaking facility adjacent to the company’s Contra Costa generating facility near Antioch, Calif. The facility is being constructed pursuant to a 10-year PPA with Pacific Gas & Electric (PG&E). NRG expects a commercial operation date in mid 2013.
The four gas-fired (765 MW) S. R. Bertron steam units in Texas and blackstart unit are currently mothballed according to Electric Reliability Council of Texas protocols, but all operated in 2012, the Form 10-K noted.
Several coal plants in line for new emissions projects
The Form 10-K had a long list of coal plants and their history with installations of emissions controls. In terms of future emissions projects, they are:
- Conemaugh Units 1-2, Pennsylvania, selective catalytic reduction (SCR) for NOx control in 2014;
- Big Cajun II Unit 1, Louisiana, dry sorbent injection (DSI) in 2015 for SO2, selective non-catalytic reduction (SNCR) in 2014 for NOx, activated carbon injection (ACI) in 2015 for mercury, and electrostatic precipitator (ESP) upgrade or new fabric filters in 2015 for particulate control;
- Big Cajun II Unit 2, conversion to natural gas in 2014, SNCR added the same year;
- Big Cajun II Unit 3, plant average limit (PAL) for SO2 control in 2013, SNCR in 2017, ACI in 2015 and ESP upgrade in 2015;
- Limestone Units 1-2, Texas, SNCR in 2017, ACI in 2015;
- W.A. Parish Units 5-7, Texas, ACI in 2015; and
- W.A. Parish Unit 8, ACI in 2015.
Based on current rules, technology and plans, as well as preliminary plans based on proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 will be around $630m, consisting of $398m for legacy NRG facilities and $232m for GenOn facilities. These costs are primarily associated with controls to satisfy the Mercury and Air Toxics Standards (MATS) at Big Cajun II, W.A. Parish, Limestone, and Conemaugh, and NOx controls at Sayreville and Gilbert. A decrease from NRG’s previous estimate is a result of changes in technology related to MATS compliance at Big Cajun II Unit 3, and shifts in compliance schedules. Testing and engineering to finalize cost estimates related to further changes on the Big Cajun II MATS compliance plan and the recent Consent Decree lodged in United States of America v. Louisiana Generating LLC are underway, but costs are not expected to exceed the current plan. NRG continues to explore cost effective compliance alternatives to reduce costs.
NRG pointed out that it has one of the largest and most diversified power generation portfolios in the United States, with approximately 45,105 MW of fossil fuel and nuclear generation capacity in 345 active generating units at 88 plants as of Dec, 31, 2012. It also has one combined-cycle and two peaking natural gas plants under construction totaling 1,345 MW. Following the GenOn acquisition, NRG increased its U.S. operating segments generation portfolio by 14,850 MW for the East, 5,390 MW for the West, and 1,200 MW for South Central.
The company said it is adequately hedged, using forward coal supply agreements for its domestic coal consumption for 2013. As of Dec. 31, 2012, NRG had purchased forward contracts to provide fuel for approximately 42% of the combined company’s expected requirements from 2013 through 2017, excluding inventory. Excluding purchases by GenOn before the December 2012 acquisition, the company purchased approximately 29 million tons of coal in 2012, of which 98% was Powder River Basin coal and lignite, and the rest from the Appalachian basin. Going forward, NRG expects the burn, based on forecasted generation, market volatility and its inventory on site, related to a full year of the acquired GenOn coal assets to approximate an additional 9.7 million tons of Appalachian coal.
NRG advances carbon capture project, Dunkirk reliability reprieve
In May 2012, NRG entered into a financing arrangement in the form of a $54m tax-exempt bond financing. The proceeds are being used to construct a peaking unit at the W.A. Parish plant and one or more components of a commercial scale carbon capture, utilization and storage project (CCUS). The CCUS is sponsored in part by a grant from the U.S. Department of Energy.
In August 2012, NRG, through its wholly owned subsidiary, Petra Nova Power I LLC, entered into an engineering, procurement and construction (EPC) agreement for a 75-MW turbine as a peaking unit (later to be retrofitted for use as a cogeneration facility to provide steam and power to operate the CCUS). The gas turbine facility went into construction in the fourth quarter of 2012, and a commercial operations date is targeted for the second quarter of 2013.
Construction of the CCUS is intended to allow NRG, through subsidiary Petra Nova LLC, to utilize the captured CO2 in enhanced oil recovery operations in oil fields on the Texas Gulf Coast. In December 2012, the final air permit was issued by the Texas Commission on Environmental Quality for the full carbon capture system. The final Environmental Impact Statement is approved and the Record of Decision is expected to be issued by the U.S. DOE in March 2013.
In March 2012, NRG’s Dunkirk Power LLC filed a notice with the New York Department of Public Service (DPS) of its intent to mothball the coal-fired Dunkirk Station no later than Sept. 10, 2012. The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power d/b/a National Grid (NG). As a result of those studies, NG determined that the mothball of Dunkirk would have a negative impact on the reliability of the New York transmission system and that portions of the plant may be retained for reliability purposes via a non-market compensation arrangement.
In July 2012, Dunkirk Power filed a reliability must run (RMR) agreement with the Federal Energy Regulatory Commission. In July 2012, NG and Dunkirk Power agreed on the material terms for a bilateral reliability support services (RSS) agreement and submitted those terms to the New York State Public Service Commission for recovery in NG’s rates. In August 2012, the NYPSC approved terms and Dunkirk Power and NG entered into the RSS agreement that began on Sept. 1, 2012. NG issued a request for proposals with respect to its reliability need in the Dunkirk area for the two years beginning June 1, 2014. Dunkirk Power submitted a proposal and is awaiting the results.