Indiana okays $1.2bn spend at AEP’s Cook nuclear plant

The Indiana Utility Regulatory Commission on July 17 approved a nearly $1.2bn upgrade project at Indiana Michigan Power’s Donald C. Cook nuclear plant – but disallowed spending on projects that could lead to an eventual plant uprate.

In April 2012, Indiana Michigan Power, a unit of American Electric Power (NYSE: AEP), filed a petition for this “Life Cycle Management Project” at Cook, which is located in Michigan. It also requested approval of certain ratemaking and accounting treatment for the LCM Project so as to allow for full and timely recovery of reasonable construction and operation costs associated with the LCM Project, as well as reasonable study, analysis and development costs incurred in connection with the project.

I&M’s petition explained that life cycle management for a nuclear power plant consists of the integration of aging management and economic planning to:

  • optimize the operation, maintenance, and service life of systems, structures and components;
  • maintain an acceptable level of performance and safety; and
  • maximize return on investment over the service life of the plant.

The project consists of sub-projects requiring significant capital investment (along with associated operating and maintenance expenses) intended to fulfill the extended operating licenses of Units 1 and 2 by:

  • safely and reliably extending the operating lives of the units consistent with their operating licenses (i.e., until 2034 and 2037, respectively);
  • increasing the safety and reliability of these units; and
  • also preserving the option for a potential future increase in the electric output of these units through a potential future “capacity uprate.”

Units have extended NRC licenses out to 2034 and 2037

Cook Units 1 and 2 were placed in service in 1975 and 1978, respectively, under 40-year Nuclear Regulatory Commission-issued operating licenses obtained in 1974 and 1977. In 2005, I&M received 20-year license renewals from the NRC to allow Units 1 and 2 to operate until 2034 and 2037, respectively.

The Cook plant generates about 50% of the power consumed by I&M’s customers. Unit 1 achieved a capacity factor of 95.5% during its last operating cycle, and Unit 2 achieved a 100% capacity factor during its most recent operating cycle, the utility told the commission.

The estimated cost of the LCM Project is about $1.169bn. The utility said that alternatives to the LCM Project were much more costly. For example, replacing the Cook units with new nuclear capacity would cost $6bn to $9bn per unit (about $6,000 per kW).

Paul Schoepf, Director of Nuclear Projects at Cook, testified that LCM Project cost estimate through 2018 is $1.169bn, which includes actual costs incurred in the second half of 2011. Schoepf explained that this is a “bottoms-up” estimate, meaning that individual cost estimates were developed.

URC says upsized equipment for a later uprate not needed right now

The commission in its July 17 order found that the proposed LCM Project, with the exception of the upsizing of certain components, is reasonable and necessary, and when completed will be used and useful in the provision of retail electric utility service to Indiana customers.

The $1.169bn estimated construction cost (with the exception of the approximately $23m in incremental upsizing cost) and the anticipated construction schedule for the LCM Project were approved. “Throughout this proceeding I&M expressed a high degree of confidence in its cost estimate for the LCM Project and its ability to successfully manage the project’s implementation within that cost estimate,” the order noted. “Therefore, our approval of the expected costs as reasonable and necessary is limited to the expected cost of $1.169 billion, less the approximately $23 million in incremental up sizing costs. Any increase in expected cost of the LCM Project for which I&M intends to seek cost recovery will require additional approval in a separate proceeding that allows for public notice and an evidentiary hearing.”

The order said about disallowing the costs of larger components: “Based on the evidence presented, we find that the incremental costs for the upsized components are not properly considered life cycle management and. fail to satisfy the definition of a clean energy project. The evidence demonstrates that the upsizing of these components is not necessary from a safety and reliability perspective or to allow the Cook Units to operate during its extended license period. Rather I&M seeks recovery of the up sizing costs as a ‘hedge,’ a cost incurred today that presents cost advantages for a future power uprate, should one ever be determined necessary.”

Those upsized components are a transformer, heat exchangers and pumps. The commission noted that this “hedge” is in part related to doubts about the future of certain I&M coal-fired capacity, including at the Tanners Creek power plant, in light of new U.S. Environmental Protection Agency emissions mandates. The state’s Office of Utility Consumer Counselor (OUCC) addressed that point in this case.

“[I&M witness Paul] Chodak testified that I&M has not requested, nor is it requesting, a power uprate at this time,” the commission noted. “The OUCC also pointed out that I&M’s IRP does not demonstrate a need for additional capacity until Tanners Creek Unit 4 is retired, which is not expected until 2024 – more than half-way into the Cook Plant’s extended licensing period. The IRP further indicates that the optimal replacement technology for the Tanners Creek Unit 4 is a natural gas combined cycle facility, not a power uprate to the Cook Plant. I&M provided no evidence as to when, or if, a power uprate would be pursued. Instead, the Company emphasized that the timing of the need for additional capacity is uncertain, due to continuing uncertainty surrounding environmental regulations and the resulting uncertainty of coal-fired unit retirement dates, as well as uncertainties surrounding the economy and load growth.”

The utility has been authorized timely recovery of its pre- and post-in-service construction and financing costs, and its incremental depreciation and property tax costs and expenses, associated with the LCM Project and incurred on and after Jan. 1, 2012 through the LCM rate rider. I&M’s proposed initial LCM Rider rates were denied. The utility needs to file LCM Rider proceedings semi-annually and may initiate its first LCM Rider proceeding under within 60 days following the issuance of the July 17 order. The commission will conduct ongoing review of the construction of the LCM Project in conjunction with the petitioner’s semi-annual LCM Rider proceedings.

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.