Duke works through coal, nuclear issues in various states

Duke Energy (NYSE: DUK) subsidiaries in Indiana, Ohio, the Carolinas and Florida are working through various issues related to existing power plants, with one new gas-fired plant nearing completion in North Carolina.

Duke Energy outlined the status of its in-flux existing and new power plants in its Aug. 8 quarterly Form 10-Q report filed with the SEC.

Duke Energy Progress, part of a July 2012 Duke Energy merger with Progress Energy, is constructing a new 625-MW combined cycle natural gas-fired generating facility at its existing Sutton Steam Station in New Hanover County, N.C. Total estimated costs at final project completion (including AFUDC) for the project, which is approximately 88% complete, are $570m. The Sutton project is expected to be in service in the fourth quarter of 2013.

In developments involving another part of the Progress Energy merger, in February 2012 the Florida Public Service Commission (FPSC) approved a Stipulation and Settlement Agreement among Duke Energy Florida, the Florida Office of Public Counsel (OPC) and other customer advocates. The 2012 settlement will continue through the last billing cycle of December 2016, unless replaced. The agreement addresses four principal matters:

  • the Crystal River nuclear Unit 3 delamination prudence review then pending before the FPSC;
  • certain customer rate matters;
  • Duke Energy Florida’s proposed and now shelved Levy Nuclear Station project cost recovery; and
  • cost of removal reserve.

The FPSC has an open proceeding to review Duke Energy Florida’s February 2013 decision to retire Crystal River Unit 3, the mediated resolution of insurance claims with Nuclear Electric Insurance Limited (NEIL), the costs spent to repair Crystal River Unit 3 since the 2012 settlement, an abandoned uprate project, and the amount of the regulatory asset to be placed in rates in 2017. On April 26, the FPSC set final hearings to resolve all remaining issues beginning Oct. 21. On June 19, the FPSC granted a joint motion to extend the due dates for discovery and testimony by 30 days to allow time for the parties to finalize issues, coordinate depositions and discovery, and potentially resolve discovery disputes.

On Aug. 1, Duke Energy Florida, OPC, and other customer advocates filed a Revised and Restated Stipulation and Settlement Agreement with the FPSC. If approved, this 2013 settlement will replace and supplant the 2012 settlement and substantially resolve additional issues, including: matters related to Crystal River Unit 3; Levy; the Crystal River 1 and 2 coal units, and future generation needs in Florida. The 2013 settlement is subject to review and approval by the FPSC, which is expected by the end of 2013.

Under the 2013 settlement, in the event Duke Energy Florida decides to retire the Crystal River 1 and 2 coal units in order to comply with environmental regulations, including the Mercury and Air Toxics Standards (MATS), it will be allowed to continue to recover existing annual depreciation expense through the end of 2020. Beginning in 2021, Duke Energy Florida will be allowed to recover any remaining net book value of the assets from retail customers through the Capacity Cost Recovery Clause.

Duke Energy Florida currently projects a significant need for additional generation to offset the impact of the lost capacity resulting from the retirement of Crystal River Unit 3 as well as the possible retirement of the Crystal River 1 and 2 coal units. The 2013 settlement establishes a recovery mechanism for additional generation needs. This recovery mechanism, the Generation Base Rate Adjustment (GBRA), will apply to:

  • the construction, uprate of existing generation, and/or purchase of up to 1,150 MW of combustion turbine and/or combined cycle generating capacity prior to the end of 2017; and
  • the construction of additional generation of up to 1,800 MW to be placed in service in 2018 upon FPSC approval of a need determination.

Edwardsport IGCC costs still a source of ongoing review

Another long-running issue for Duke has been cost overruns and how to account for them at the recently completed Edwardsport IGCC coal plant in Indiana. Duke Energy Indiana experienced design modifications, quantity increases and scope growth above what was anticipated from the preliminary engineering design, which increased capital costs for the project.

  • In January 2009, a new cost estimate was approved by the Indiana Utility Regulatory Commission (IURC) for $2.35bn (including $125m of AFUDC).
  • In April 2010, Duke Energy Indiana filed a revised cost estimate for the IGCC project requesting approval of the revised cost estimate of $2.88bn (including $160m of AFUDC).
  • In June 2011, Duke Energy Indiana updated its cost forecast to $2.82bn (excluding AFUDC).
  • In October 2011, Duke Energy Indiana revised its project cost estimate to $2.98bn (excluding AFUDC).
  • In October 2012, Duke Energy Indiana further revised its projected cost estimate to $3.15bn (excluding AFUDC).

In December 2012, the IURC approved a settlement agreement finalized in April 2012, between Duke Energy Indiana, the Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana, on the cost increase for the construction of the project including subdockets before the IURC related to the project. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595bn, including estimated AFUDC through June 30, 2012. Duke Energy Indiana is allowed to recover AFUDC after June 30, 2012, until customer rates are revised, with such recovery decreasing to 85% on AFUDC accrued after Nov. 30, 2012. Duke Energy Indiana also agreed not to request a retail electric base rate increase prior to March 2013, with rates in effect no earlier than April 1, 2014.

The IURC modified the settlement agreement as previously agreed to by the parties to: require Duke Energy Indiana to credit customers for cost control incentive payments which the IURC found to be unwarranted as a result of delays that arose from project cost overruns; and provide that if Duke Energy Indiana should recover more than the project costs absorbed by Duke Energy’s shareholders through litigation, any surplus must be returned to the Duke Energy Indiana’s ratepayers.

In December 2012, Duke Energy Indiana filed an arbitration action against General Electric and Bechtel Corp. in connection with their work at the Edwardsport IGCC. Duke Energy Indiana is seeking damages of not less than $560m. Duke Energy Indiana cannot predict the outcome of this matter, Duke noted in the Form 10-Q.

Over the course of construction of the project, Duke Energy Indiana recorded pre-tax charges of approximately $897m related to the Edwardsport project including the settlement agreement discussed above.

The Joint Intervenors have appealed the IURC order approving the April 2012 settlement agreement and other related regulatory orders to the Indiana Court of Appeals. The Appellants’ brief is due Sept. 9, and a final decision is anticipated mid-2014.

Duke gets ready to shut down a lot of coal-fired capacity

Separately, on April 10, the IURC approved Duke Energy Indiana’s filed plan for the addition of certain environmental pollution control projects on several of its coal-fired units in order to comply with existing and proposed environmental rules and regulations. The expenditures approved in the plan will be presented for recovery in Duke Energy Indiana’s semi-annual environmental cost recovery rider.

The plan calls for a combination of selective catalytic reduction (SCR), dry sorbent injection systems for SO3 mitigation, activated carbon injection systems and/or mercury re-emission chemical injection systems. The capital costs are estimated at $395m (excluding AFUDC). Duke Energy Indiana also indicated that it preliminarily anticipates the retirement of the coal-fired Wabash River Units 2 through 5 in 2015 and is still evaluating future equipment additions or retirement of Wabash River Unit 6.

Across the Duke Energy system, the potential or firm coal unit early retirements include;

  • Duke Energy Carolinas, Lee Units 1 and 2 (excludes 170 MW Lee Unit 3 that is expected to be converted to gas in 2014);
  • Duke Energy Progress, Sutton Station, which is expected to be retired by the end of 2013;
  • Duke Energy Florida, Crystal River Units 1 and 2;
  • Duke Energy Ohio, Beckjord Station Units 2 through 6 and Miami Fort Unit 6; and
  • Duke Energy Indiana, Wabash River Units 2 through 6 (Wabash River Unit 6 is being evaluated for potential conversion to gas).

While the ultimate compliance requirements for the Duke Energy subsidiaries for the MATS, Clean Water Act 316(b), coal combustion residuals (CCRs) and Steam Electric Effluent Limitations Guidelines (ELGs) will not be known until all the rules have been finalized, for planning purposes, the Duke Energy companies currently estimate that the cost of new control equipment that may need to be installed on existing power plants to comply with EPA regulations could total $5bn to $6bn, excluding AFUDC, over the next 10 years. This range includes estimated costs for new control equipment necessary to comply with the MATS rule, which is the only rule that has been finalized.

The Duke Energy companies also expect to incur increased fuel, purchased power, operation and maintenance, and other expenses in conjunction with these EPA regulations, and also expect to incur costs for replacement generation for potential coal-fired power plant retirements. Until the final regulatory requirements of the group of EPA regulations are known and can be fully evaluated, the potential compliance costs associated with these EPA regulatory actions are subject to considerable uncertainty.

On June 7, the proposed ELGs were published in the Federal Register with comments due by Sept. 29, following a 45-day extension. The EPA is under a court order to complete a final rule by May 22, 2014. The EPA has proposed eight different options for the rule, which vary in stringency and cost. The proposal would regulate seven waste streams, including wastewater from air pollution control equipment and ash transport water, Duke noted. This rule is applicable to all steam electric generating units, including most, if not all of the coal, natural gas and nuclear-fueled facilities in which the Duke Energy companies have an ownership interest. Compliance is proposed as soon as possible after July 1, 2017, but may extend until July 1, 2022. Duke Energy said it is still evaluating the proposal. Given the number of options and the long compliance term, Duke Energy added that it is unable to determine the ultimate impact of the final rule, but the impact could be significant.

Nuclear capacity still in the works at Duke

In July 2011, Duke Energy Carolinas signed a letter of intent with South Carolina-owned utility Santee Cooper related to the potential acquisition by Duke Energy Carolinas of a 5% to 10% ownership interest in the V.C. Summer Nuclear Station being developed by Santee Cooper and South Carolina Electric and Gas (SCE&G) near Jenkinsville, S.C. The letter of intent provided a path for Duke Energy Carolinas to conduct the necessary due diligence to determine whether future participation in this project is beneficial for customers. In November 2012, the term of the letter of intent expired, though Duke Energy Carolinas remains engaged in discussions at this time.

In December 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC), which has been docketed for review, for a combined license (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station at a site in Cherokee County, S.C. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the North Carolina and South Carolina utility regulatory commissions have concurred with the prudency of Duke Energy Carolinas incurring certain project development and pre-construction costs. As of June 30, Duke Energy Carolinas has incurred approximately $350m for work on this project.

The Lee COL application is impacted by the ongoing activity by the NRC to address its Waste Confidence rule, a generic finding by the NRC that spent fuel can be managed safely until ultimate disposal. The rule has been remanded to the NRC by the U.S. Court of Appeals for the D.C. Circuit. In response to the court’s remand and in connection with numerous petitions asserting waste confidence contentions, including in the Lee proceeding, the NRC determined that no final licenses for new reactors would be issued until the remand is appropriately addressed.

In September 2012, the NRC provided a timeline of 24 months from the time of its order for the staff to finish the generic Environmental Impact Study and publish a final Waste Confidence rule. Assuming the NRC uses the entire 24-month period for promulgation of a new rule, licenses would not be issued until September 2014 at the earliest, Duke noted. The COL is also impacted by the time required to fully respond to an NRC request for additional information that addresses seismic hazard evaluation resulting from recommendations of the Fukushima Near-Term Task Force. Due to the schedule for both fully responding and for NRC review of the response, the Lee COL is not expected until 2016.

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.