American Electric Power pursues coal shutdowns, retrofits

Based upon current estimates, investment by American Electric Power (NYSE: AEP) to meet various U.S. Environmental Protection Agency requirements ranges from $6bn to $7bn between 2012 and 2020, which includes investments to convert 1,055 MW of coal generation to natural gas.

“We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance,” said AEP in its Oct. 26 Form 10-Q report. “As of September 30, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired. We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.”

The cost estimates will change depending on the timing of implementation and whether EPA provides flexibility in the final rules. The cost estimates will also change based on: the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards; additional rulemaking activities in response to court decisions; the actual performance of the pollution control technologies installed on units; changes in costs for new pollution controls; new generating technology developments; total MWs of capacity retired and replaced, including the type and amount of such replacement capacity; and other factors.

At this point, AEP has told the applicable regional transmission organizations that it plans to retire these plants and units, representing 4,606 MW in total, before or during 2016;

  • Appalachian Power, Clinch River Unit 3, 235 MW;
  • APCo, Glen Lyn, 335 MW;
  • APCo, Kanawha River, 400 MW;
  • APCo/Ohio Power, Philip Sporn Unit 1-4, 600 MW;
  • Indiana Michigan Power, Tanners Creek Units 1-3, 495 MW;
  • Kentucky Power, Big Sandy Unit 1, 278 MW;
  • OPCo, Conesville Unit 3, 165 MW;
  • OPCo, Kammer, 630 MW;
  • OPCo, Muskingum River Unit 1-4, 840 MW;
  • OPCo, Picway, 100 MW; and
  • Southwestern Electric Power, Welsh Unit 2, 528 MW.

Duke Energy (NYSE: DUK), the operator of the coal-fired W. C. Beckjord plant, has announced its intent to close the facility in 2015. AEP’s OPCo subsidiary owns 12.5% (54 MW) of one unit at that station.

In September 2012, based upon an agreement in principle with the EPA, the state of Oklahoma and other parties, Public Service Co. of Oklahoma filed an environmental compliance plan with the Oklahoma Corporation Commission to retire the coal-fired Units 3 and 4 of the Northeastern Station, a total of 930 MW, in 2026 and 2016, respectively. In April 2012, the utility reached an agreement in principle that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit at Northeastern no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026. The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

“Natural gas prices and pending environmental rules could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of certain coal-fired units,” AEP noted. “We are still evaluating our plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units based on changes in emission requirements and demand for power. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable under our accounting evaluations, it could materially reduce future net income and cash flows.”

AEP in front of state commissions with various coal unit plans

Looking at ongoing efforts to get new emissions controls or coal shutdowns approved:

  • Indiana Michigan Power (I&M) filed an application with the Indiana Utility Regulatory Commission seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its coal-fired Rockport plant with environmental controls estimated to cost $1.4bn to comply with new requirements. In July 2012, certain intervenors filed testimony which recommended cost caps ranging from $1.1bn to $1.4bn. In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed project plan and cost estimates are filed with the IURC. A hearing is scheduled for December 2012.
  • In May 2012, Kentucky Power (KPCo) withdrew its application to the Kentucky Public Service Commission seeking approval of a CPCN to retrofit the coal-fired, 800-MW Big Sandy Unit 2 with a dry flue gas desulfurization (FGD) system. KPCo is currently re-evaluating its options to meet the short- and long-term energy needs of its customers at the most reasonable costs.
  • In February 2012, SWEPCo filed a petition with the Arkansas PSC seeking a declaratory order to install environmental controls at the coal-fired Flint Creek plant. The estimated cost of the project is $408m, excluding AFUDC and company overheads. As a joint owner of Flint Creek, SWEPCo’s portion of those costs is estimated at $204m. The Arkansas PSC staff and the Sierra Club filed testimony that recommended the PSC deny the requested declaratory order. A hearing was held in October 2012 and a decision is pending.
  • In September 2012, PSO filed an environmental compliance plan with the OCC which requested approval for: full cost recovery through base rates by 2026 of an estimated $256m of new environmental investment that will be incurred prior to 2016 at Northeastern Unit 3; full cost recovery through 2026 of Northeastern Units 3 and 4 net book value (combined net book value of the two units is $235m as of Sept. 30, 2012); full cost recovery through base rates of an estimated $83m of new investment incurred through 2016 at various gas units; and a new 15-year purchase power agreement with Calpine Oneta Power, effective in 2016, with cost recovery through a rider. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.
  • In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149m. Included in the depreciation rates increase within that proposal was a decrease in the average remaining life of Tanners Creek to account for the change in the retirement date of Units 1-3 from 2020 to 2014. In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Units 1-3 to 2015.

SWEPCo is currently constructing the Turk plant, a new baseload 600-MW pulverized coal ultra-supercritical generating unit in Arkansas, which is scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of Turk and will operate the completed facility.

Also of note in the area of coal generation, in the third quarter of 2011, management decided to no longer offer the output of Sporn Unit 5 into the PJM market. Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the Interconnection Agreement.

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.