East Kentucky Power Cooperative is still working, through the opposition of the Sierra Club, at the Kentucky Public Service Commission to extend a recently-built SO2 scrubber on its J. Sherman Cooper Unit 2 to cover the plant’s Unit 1.
EKPC originally filed the application with the commission on this project in August 2013.
On Jan. 3, James Read, a Principal with The Brattle Group, supplied testimony to the commission on behalf of EKPC that rebuts contentions made by Tyler Comings of Synapse Energy Economics as a witness for the Sierra Club. Comings said, among other things, that EKPC “no longer needs to procure additional capacity” and the “market valuation analysis likely overestimates the value of the project.”
The decision to retrofit Cooper Unit 1 is a decision about how to manage one of EKPC’s existing generation assets, not procure new capacity, Read countered. “As the owner of Cooper Station, EKPC is obligated to try to realize the potential value of Cooper Unit 1 for its members,” he said. “Our analysis indicates that the proposed retrofit is a good investment.”
The estimated net present value (NPV) of the Cooper 1 retrofit is large, Read added. There is substantial “headroom” for unfavorable market price outcomes (electric energy prices below forecast values) and unfavorable cost outcomes (costs higher than projected) to come into play before the project would lose its attractiveness, he said.
“Even if one were to accept Mr. Comings’ alternative forecast of electric energy prices, the NPVs he calculates based on his alternative price forecast understate the NPV of the Cooper 1 retrofit,” Read pointed out. “In particular, the NPVs he calculates do not reflect uncertainty about future market prices and the value of dispatch and retirement flexibilities implicit in Cooper Unit 1.”
If the question is, “will the lights go out if EKPC does not acquire additional capacity,” then the answer is “no,” he said. Now that EKPC is integrated into the PJM Interconnection system, it purchases the capacity and energy its members consume in the PJM markets. Acquiring additional capacity is therefore an option for EKPC, not a requirement. However, EKPC continues to own generation resources, and whether or not it chooses to acquire additional capacity, EKPC continues to be responsible for managing its existing generation.
If EKPC does not retrofit Cooper 1, it will have to retire it in 2015. EKPC can defer decisions about whether to acquire additional capacity, but it must decide now whether to retrofit or retire Cooper Unit 1, Read said.
Although there is the potential for Cooper Unit 1 to remain in service for many more years, the utility calculated the NPV of the retrofit proposal under alternative assumptions about its remaining operating life. “We focused our assessment on results we obtained when it was assumed that Cooper 1 would operate for only ten more years,” Read pointed out. “The ten-year NPV results do not include the value of energy or capacity revenues that might be realized from operating beyond the 2025 time horizon.”
In the same Jan. 3 filing as the Read testimony was testimony from Julia Tucker, Director of Power Supply Planning for EKPC. Tucker described how the June 2013 entry of EKPC into the PJM market didn’t change the need for the Unit 1 retrofit project.
EKPC said the Unit 1 retrofit would cost about $15m. EKPC is seeking from the commission a Certificate of Public Convenience and Necessity (CPCN) for the rerouting of certain duct work at the Cooper station, and approval of an environmental compliance plan amendment so it can recover the project costs through EKPC’s environmental surcharge.
Cooper was constructed in 1962 and consists of two units. Cooper 1 began commercial operations in 1965 and is rated at 116 MW. Cooper 2 began commercial operations in 1969 and is rated at 225 MW.
The project would consist of new ductwork from the Unit 1 ID fan to the Unit 2 ductwork tie-in location, exhaust gas regulating and isolation dampers, integration of the controls systems, and new CEMS equipment. The project scope also includes foundations, support steel, access steel to support the new balance of plant (BOP) equipment, demolition of the existing stack division wall, and sealing of the existing Unit 1 stack breaching. In addition to the new BOP equipment, the circulating dry scrubber (CDS) equipment will incorporate a modified hydrated lime feed system to allow dual hydrator operation, and longer fabric filter bags and cages to support the increased gas flow through the CDS equipment. The combined exhaust gas from the CDS equipment will be routed to the existing stack via the Unit 2 ID fan.
The Cooper plant is fueled primarily by Kentucky coal. U.S. Energy Information Administration data shows that coal suppliers to the plant in 2013 included Jamieson Construction, Mountainside Coal and B&W Resources.