The Appalachian Power subsidiary of American Electric Power (NYSE: AEP) is burning less coal due to the closure last year of several coal units, and AEP’s Wheeling Power unit is now burning coal due to its relatively recent ownership of half of the Mitchell power plant.
Emily Medine of consulting Energy Ventures Analysis, working on behalf of the Consumer Advocate Division of the Public Service Commission of West Virginia (CAD), supplied May 16 testimony to the commission in the latest yearly Expanded Net Energy Charge (ENEC) case for these two AEP subsidiaries. The ENEC operates like a fuel adjustment clause in other states, allowing utilities to pass along certain volatile costs to ratepayers more quickly than can be done through a full rate case.
The companies has requested a substantial increase in the ENEC related to underrecovery in 2015 and to several In-Period Adjustments including an expansion of the Transmission Investment Cost (TIC) rider and the addition of the Generation Investment Cost (GIC) rider. Medine’s recommendations for changes to the ENEC are:
- The base ENEC amount should be reduced by $8.4 million to reflect expected changes in coal costs due to lower prices since the forecast was made.
- The base ENEC amount should be reduced by $763,369 to reflect a warranted adjustment to the lease cost associated with the construction of the Clinch River gas pipeline lateral.
Medine wrote (her testimony refers to these two utilities as one company: “The requested expansion of the TIC and the addition of the GIC reflect the Company’s desire to receive expedited recovery of these investments instead of triggering a rate case. While there has been some precedent in this regards, in my opinion the circumstances do not warrant expedited recovery. Further, the nature of the riders limits scrutiny of these investments.”
Medine wrote about coal market impacts: “The Company, like other power producers, has been challenged by low and volatile coal demand due primarily to low natural gas prices resulting in the displacement of coal generation with gas generation. In order to better manage the uncertain and volatile level of demand, the Company has increased its short-term purchasing of coal. The results of this approach have been mixed. I am recommending that the Company be tasked with developing and implementing appropriate risk management strategies.
“The coal industry is challenged as a result of a prolonged period of low coal prices. Many coal producers, including several of the Company’s coal suppliers, have filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code, Given that the outcome of restructuring efforts is unknown, the Company is exposed to loss of production and potentially higher prices. I am recommending that the Company should develop contingency planning related to concerns about financial viability of its suppliers.”
APCo down to Amos and Mountaineer coal plants
APCo owns four power plants and is a partial owner of two other plants. The Amos and Mountaineer stations consist of super-critical plants which have been retrofit with scrubbers and other environmental equipment sufficient to make them fully compliant with the federal Mercury and Air Toxics Standard (MATS). Both stations can take coal by rail and barge although the barge unloader at Amos cannot handle full deliveries by river. The plants have considerable fuel flexibility although the scrubber design at Amos limits the sulfur input, Medine noted. The gas capacity consists of the Dresden combined cycle and the Ceredo combustion turbine plants.
In May 2015, these APCo units were retired: Clinch River 3, Glen Lyn 5 and 6, Kanawha River 1 and 2 and Sporn 1 and 3. The other two Clinch River units, 1 and 2, have ceased burning coal and are being converted to natural gas.
APCo reported purchases of 9.8 million tons of coal in 2015. Most of the coal was purchased for Amos, the largest station, and Mountaineer. As the other coal plants were retired in 2015, there were very small purchases for them, Medine added.
Amos uses both low- and high-sulfur coal as the scrubber that was retrofit on the station was not designed for 100% high-sulfur coal. The coal is blended at the station. Mountaineer uses almost exclusively high-sulfur coal as the scrubber was designed to accommodate that quality. The high-sulfur coal comes primarily from Northern Appalachia; the low-sulfur coal comes from Central Appalachia. About 80% of the coal purchased by APCo was reported as contract.
Wheeling Power owns 50% of the 1,560 MW Mitchell station which it acquired from an unregulated AEP subsidiary in 2015. The Mitchell station is operated by AEP’s Kentucky Power subsidiary, which owns the other 50%. The Mitchell station consists of three super-critical units which have been retrofit with scrubbers and other environmental equipment sufficient to make them fully compliant with MATS. Mitchell can take coal by rail, barge and conveyor. Some 2.3 million tons of were purchased for Mitchell in 2015 (100% basis). Like Amos, Mitchell uses both low- and high-sulfur coals to meet the sulfur limitations of the scrubber. Only about 12% of the coal purchased for Mitchell was on a spot basis and all of the spot coal was low-sulfur coal from Central Appalachia. The high-sulfur coal was from the McElroy longwall mine, which is now owned by Murray Energy. The McElroy coal is delivered by belt.
As for coal industry bankruptcies, including top U.S. coal producer Peabody Energy, Medine said the percent of production of publicly-traded coal companies that has been in bankruptcy in the last 12 months exceeds 40%. “While some of these bankruptcies have not been directly related to coal prices, all of these bankruptcies have been indirectly related. For example, the decline in the financial condition of Alpha Natural Resources (ANR) resulted in ANR no longer being eligible for self-bonding their reclamation liabilities at their mines in West Virginia and Wyoming. The requirement to post reclamation bonds in Wyoming is what triggered the filing.
“The major bankruptcies to date have largely been voluntary petitions under Chapter 11 of the Bankruptcy Code which means that the debtors (a) continue to operate with debtor-in-possession (DIP) financing, as needed, and (b) there is an expectation that the debtor can reorganize and emerge from bankruptcy. Many of the companies in bankruptcy are looking to separate core and non-core assets, effectively creating companies for which there is the expectation of future survival and companies for which the primary goal is divesting of properties and completing reclamation. While this model proved to be a great success in the 2004 bankruptcy of Horizon Natural Resources, the circumstances are radically different today due to reduced investor interest in this space, making DIP financing and required capitalization expenses more difficult to obtain. It is possible that some of the companies in bankruptcy may ultimately be liquidated through Chapter 7, potentially leaving a number of properties idled.”