The Kentucky Public Service Commission on Dec. 1 approved a July 24 application from East Kentucky Power Cooperative for a Certificate of Public Convenience and Necessity in connection with its proposal to acquire from Bluegrass Generation Co. and then operate three existing simple-cycle combustion turbine units at the Bluegrass Station in La Grange, Kentucky.
Each unit has winter and summer ratings of 198 MW and 165 MW, respectively. The output of Bluegrass Station Unit 3 is currently committed to Louisville Gas and Electric and Kentucky Utilities under a tolling agreement, which is scheduled to terminate on April 30, 2019. LG&E and KU are part of PPL.
Under the Tolling Agreement, LG&E/KU is entitled to 165 MW of firm generation and capacity from Bluegrass Station Unit 3, and LG&E/KU would be responsible for the delivery of natural gas through firm transportation agreements to the site of Bluegrass Station Unit 3 and for securing electric transmission service in their balancing area.
EKPC was also approved by the commission to assume certain evidences of indebtedness related to the proposed acquisition. The total price to be paid by EKPC for this acquisition was redacted from the Dec. 1 order.
EKPC is a not-for-profit, member-owned electric generation and transmission cooperative that provides wholesale electricity to its 16 owner-member distribution cooperatives, which serve about 525,000 customers across 87 counties. EKPC is a member of PJM Interconnection.
EKPC currently owns or purchases a total of about 2,794 MW of net summer generating capability and 3,009 MW of net winter generating capability, consisting of the 149 MW Dale Station, 341 MW Cooper Station and 1,346 MW at Spurlock Station, all of which are baseload coal-fired generation.
In addition, EKPC’s generation includes natural-gas fired units at Smith Station, which has a summer rating capacity of 774 MW and a winter rating capacity of 989 MW, and five landfill gas-to-energy facilities totaling 14.4 MW. Finally, EKPC purchases 70 MW and 100 MW of hydropower from the Southeastern Power Administration at Laurel Dam and the Cumberland River system of dams in Kentucky and Tennessee, respectively.
EKPC has endeavored to secure adequate capacity since 2012 because of the potential loss of over 300 MW of capacity from possible plant retirements, i.e., 199 MW from Dale Station and 116 MW from Cooper Unit 1, due to more stringent environmental regulations, and the estimated increase in its total energy requirement of 1.4 percent per year over a 20-year period from 2015 through 2034. Without any additional load growth or increase in load factors, EKPC’s winter capacity falls nearly 650 MW short of its historic peak winter demand when the coal-fired Dale Station is completely closed in 2016.
The Dale Station consists of four units with a total of 199 MW. Unit 1 and Unit 2 had a combined capacity of 50 MW and were permanently taken out of service on April 15, 2015. Unit 3 and Unit 4 have a combined capacity of 149 MW and are scheduled to be placed in inactive status on April 15, 2016, under a one-year compliance deadline extension under MATS.
The need for capacity was recognized several years ago and has been the source of a Request for Proposal (RFP) issued in 2012 and one prior commission proceeding. To address this shortfall of capacity, EKPC retained The Brattle Group in May 2012 to assist with an RFP and to provide independent analysis of the power supply offers submitted in response to the RFP.
EKPC stated that the 2012 RFP was structured to compare the costs required to bring the Dale Station and Cooper Station Unit 1 into compliance with the Mercury and Air Toxics Standards, with the costs of alternative power supply options available in the market.
Brattle concluded that the reconfiguration of Cooper Station Unit 1 to flow its air emissions through the existing air quality control system servicing Cooper Station Unit 2 was the highest value-added option available to EKPC. The commission approved that project in February 2014.
By retrofitting Cooper Station Unit 1, EKPC was able to retain 116 MW of its existing generation that otherwise would have been lost as a result of MATS. However, EKPC still needed to replace the loss of about 199 MW of capacity from the retirement of the Dale Station, as well as plan for future load growth and increases in load factor.
EKPC sought a fresh set of the competitive bids from the 2012 RFP during the summer of 2014 (called the “RFP Refresh”) to address its continued need for capacity, particularly in light of the imminent closure of the Dale Station.
Brattle was again engaged to provide independent analysis of the bids received. EKPC asked Brattle to invite firms that had proposed conventional power supply resources in response to the 2012 RFP to submit updated or new proposals, which resulted in the Bluegrass deal.
Bluegrass leases and operates three natural gas-fired SCCT units at the Bluegrass Station pursuant to a lease agreement from 2000 with Oldham County, Kentucky. The Bluegrass Station units were constructed by Dynegy and went into commercial operation in 2002 when LG&E/KU were members of the Midcontinent Independent System Operator market.
At that time, Dynegy could sell the output of the plant directly into MISO and had a liquid market for the asset. After LG&E/KU left MISO, Dynegy had to purchase transmission rights into MISO and/or PJM, in addition to transmission across the LG&E/KU system.
The cost of this transmission service was enough to generally keep the peaking units out of the market on an economic basis, the PSC noted. The inability to sell energy and make profit from those sales severely limited the value of the plant to Dynegy and later to LS Power, which purchased the units from Dynegy. The units have operated at low capacity due to these transmission costs and Dynegy’s not being able to compete in the markets on an economic basis.
The units are 14 years old and are assumed to have a depreciable life of 35 years; thus, the units have a remaining depreciable life of 21 years. In conjunction with the negotiations between EKPC and Bluegrass for the proposed acquisition, EKPC undertook extensive efforts to investigate the condition of the Bluegrass Station units, transmission availability, fuel deliverability and pricing, environmental aspects of the transaction, and other related issues.
As part of its evaluation of the responses to its 2012 RFP, EKPC retained Burns & McDonnell to perform an inspection of the Bluegrass Station. Although the Burns & McDonnell inspection did not uncover any fatal flaws, it did note a concern regarding a cracked row-four diaphragm on the Unit 3 compressor, which was originally identified in a 2009 borescope inspection by Siemens.
In response to PSC staff’s post-hearing request, EKPC stated that Bluegrass informed EKPC on Nov. 5, 2015, that during a routine combustion inspection, damage was found in the Unit 3 compressor station. Bluegrass is repairing the compressor damage and will also repair the cracked row-four diaphragm. EKPC stated that the estimated cost to repair the diaphragm is not available, but that it is EKPC’s understanding that the repair cost will not affect the purchase price of the facility.
Siemens also recommended inspection of the rotor winding pole crossovers on the generator rotors, noting that it has found cracking in the generator pole crossovers on the other units with a higher number of start/stop cycles. The maintenance is currently scheduled in the 2018/19 timeframe. The estimated cost of these repairs is $275,000 per unit. EKPC states that the costs have been included in its financial forecasts for Bluegrass Station. EKPC testified that the condition of the units and any issues identified in the Burns & McDonnell Due Diligence Report were consistent with normal operations of SCCTs.
EKPC intends to move forward with transmission agreements specified by LG&E/KU to ensure that it can deliver any excess output from Bluegrass Station to the EKPC transmission system when needed. EKPC stated that it could also build a transmission line to deliver the output from Bluegrass Station to its existing transmission facilities in order to avoid the point-to-point transmission costs that LG&E states would be required. Whether EKPC pays the point-to-point transmission costs to LG&E/KU or builds a new transmission line, the proposed acquisition of Bluegrass Station is still the lowest-cost option for procuring the needed capacity, the PSC wrote.
Because the Bluegrass Station is currently leased by Bluegrass from Oldham County as part of a complex financing plan put in place as part of the development of the plant, EKPC will take an assignment of the Lease Agreement between Bluegrass and Oldham County and related agreements.
EKPC intends to finance the proposed acquisition through funds currently available from its $500 million unsecured credit facility established with the National Rural Utilities Cooperative Finance Corp. and other banks, and then replace that short-term financing with long-term financing pursuant to the terms of its trust indenture with the U.S. Bank National Association.
EKPC plans to secure that long-term financing through a Rural Utilities Service loan; however, in the event that RUS financing is not timely available, EKPC will pursue long-term financing of the acquisition through a private placement debt offering.
Bluegrass Station is currently operated by North American Energy Services under an O&M Agreement with Port River, an affiliate of Bluegrass. EKPC testified that the O&M Agreement would be assigned to it and it would retain the contract with NAES. EKPC also plans to create five new, skilled, well-compensated full-time equivalent positions in addition to the current five FTE positions due to the increased usage of Bluegrass Station.
Currently, energy generated at Bluegrass Station is marketed and sold by EDF Trading North America. EKPC testified that it would internally administer this function subsequent to the consummation of the transaction.