The Virginia State Corporation Commission on Nov. 26 approved a rate case for the Appalachian Power unit of American Electric Power (NYSE: AEP), and in it gave APCo a pass on coal stockpiles that had built up beyond a 35-day burn target the commission had set in a 2011 decision.
On March 31, Appalachian Power had filed an application with the State Corporation Commission for a biennial review of the company’s rates, terms and conditions for the provision of generation, distribution and transmission services. The commission held evidentiary hearings in the case in September. This case covered the 2012-2013 historical two-year period. APCo’s first biennial review was for the 2009-2010 period, which resulted in the 2011 order about a 35-day coal stockpile target.
Commission staff and the state Consumer Counsel argued that in setting APCo’s rates in 2011, the commission limited the amount of coal inventory in rate base to a 35 day supply of coal at average burn rates. The commission agreed with Consumer Counsel’s explanation that “only a reasonable coal inventory amount should be included in rate base for regulatory purposes.” Whether or not the coal inventory is reasonable for determining earned return must be based on the reasonableness of the company’s actions, not on the unforeseen vagaries of the market or the weather, the commission added. It found that the company acted “reasonably” in managing its coal inventory and that no party has identified even a single unreasonable action (or lack of action) on the company’s behalf in this matter.
“Based on the evidence in this record, we find that the Company’s management of its coal inventory was reasonable and, as a result, that its actual 2012-2013 coal inventory amount is reasonable for purposes of determining earned return in this biennial review,” the commissioned rule. “The Company has also shown that its actions were reasonable and necessary to provide reliable service to its customers, which also complies with our explicit directive in the 2011 rate case. Specifically, although the Commission found that APCo had not shown that the thirty-five day coal inventory built into rates would ‘expose the Company or its customers to risks of plant curtailments or shut downs due to a lack of coal,’ the Commission further directed that ‘we expect that the Company shall continue to meet its public service obligations in this regard.’ In this instance, the Company showed that it met its public service obligations by reasonably managing its coal procurement based on the information available at the time decisions were made, and that the unprecedented drop in the demand for its coal-fired generation was not reasonably foreseeable and was driven by facts beyond its control. While not determinative we also note that due to coal supply and transportation disruptions in early 2014, the Company’s coal inventory was needed to such a great extent – in order to meet its public service obligations and keep its coal units operating – that its coal inventory was reduced in a period of months by an amount greater than the entire inventory prospectively approved by the Commission in rates.”
The commission, though, emphasized that the approval of APCo’s coal inventory in this case does not arnount to a “blank check” for a utility to maintain any amount of coal inventory, no matter how excessive. In its next biennial review the company will need to establish that it did not inventory unreasonable amounts of coal in 2014-2015 . For example, APCo will need to show that its actions to manage such inventory were reasonable based on the specific factual circumstances relevant to the next biennium.
Commissioner says APCo goofed up in contracting for coal, and needs to pay for it
In a blistering dissent, Commissioner James Dimitri wrote about the coal inventories in 2012 and 2013: “For this period, APCo’s actual average coal inventory was more than triple the 35-day average daily burn rate this Commission found reasonable in APCo’s 2011 biennial review and more than triple the same 35-day average daily burn rate level this Commission finds reasonable going forward in this proceeding, Stated in tons of coal inventory, for 2012 a 35-day average burn for APCo (what the Commission in 2011 had found reasonable) came to 820,085 tons. APCo’s actual average inventory in 2012 was 2,476,048 tons. In 2013 the 35-day allowance was 701,260 tons, while the actual level was 2,385,747 tons. Even the Company’s witness acknowledged that ‘we had too much’ when testifying about APCo’s earnings test coal inventory. … The Commission set a 35-day standard in 2011 and sets a 35-day level going forward for 2015. The majority ruling ignores the overwhelming evidence of abnormal levels in 2012 and 2013 and requires customers to pay a return on these excessive amounts and simply declares it “reasonable.'”
Dimitri added: “The record shows that APCo’s excessive earnings test period coal inventory was a direct result of actions or decisions made by the Company. Specifically, APCo failed to forecast demand for coal-fired generation accurately, and executed coal purchase contracts that required APCo to take coal shipments regardless of APCo’s need or its existing inventory level. These were analyses and decisions within the Company’s control that turned out to be wrong. Moreover, the monthly balances in 2012 and 2013 show no significant progress in reducing the excessive levels. Based on the record in this case, APCo should not be rewarded with additional earnings through an inflated rate base for such decisions.
“While the majority makes much of the ultimate use of some of the high inventory levels during the cold weather of the winter of 2014 as a result of the Polar Vortex, those circumstances actually demonstrate the opposite – that APCo’s earnings test period coal inventories were in fact excessive. Even after the unusually high winter coal bum rates, coupled with only limited coal deliveries from January through March 2014, APCo’s coal inventory only then approached a level near the Company’s own target and a level near what the Commission had found to be reasonable in APCo’s 2011 biennial review and on a going-forward basis in this proceeding. On March 23, 2014, APCo had 1.1 million tons in inventory. In other words, it took an extreme occurrence, after 24 months of greatly excessive inventory levels, to bring the Company’s coal inventory down to a level approaching reasonable, well after the end of the biennial review period.”
Dimitri offered this hearing quote from an AEP fuels official about the inventories: “If you look at – we were above inventory on our coal plants for ’12 and ’13 and it was almost exclusively low-sulfur barge coal that was the high inventory. Again, that was because of that decision we made in 2011.”
There are two other members of the commission, both of whom voted to give APCo a pass on the high inventories: Mark Christie and Judith Williams Jagdmann.
In some other aspects of the Nov. 26 rate order:
- The commission said APCo has not shown that it is reasonable to include the Putnam Coal Terminal, located on the Kanawha River in West Virginia next to the Amos power plant, in rate base and expense for determining 2012-2013 earned return. Putnam was idled in 1998. In March 2013, APCo reclassified Putnam as Plant Held for Future Use (PHFU). In response to discovery, APCo advised that it had not established a timeline for determining whether Putnam will provide utility service during the next four years. On rebuttal, APCo asserted that certain Putnam assets are still in use. At the hearing, APCo testified that part of the March 2013 reclassification to PHFU may have been in error. “We find that the Company has not, however, reasonably established the specific value of Putnam assets that were in use during 2012-2013, are currently in use, or that will be used in the immediate future, as part of its public service obligation,” the commission found. “Thus, for regulatory accounting purposes and to determine earned return under the statute, Putnam should be removed from rate base and expense.”
- APCo has not shown that it is reasonable to double-count the remaining two-thirds of the coal-fired Amos Unit 3 in West Virginia by including it in rate base for December 2013 in determining 2012-2013 earned return. On Dec. 31, 2013, APCo acquired from fellow AEP subsidiary Ohio Power the remaining two-thirds interest in Amos 3. APCo’s capacity payments through the American Electric Power Pool Interconriection Agreement, however, already reflect payments for Ohio Power’s two-thirds ownership of Amos for the entire month of December. “We find the remaining two-thirds of Amos for December 2013 are properly reflected in actual capacity payments under the AEP Pool Interconnection Agreement,” said the commission. “We further conclude that it is not reasonable also to reflect – again – that same two-thirds of Amos in rate base for the same month.”
- Based on the specific facts set forth in this proceeding, the commission approved the company’s proposal to modify its Cogeneration and Small Power Production (Cogen/SPP) rate schedule to be applicable to customers with qualifying cogeneration or small power production facilities that have a net capacity of 5 MW or less (up from 100 kW or less). In addition, the commission noted that “[b] ecause there are currently no customers served by the existing Cogen/SPP rate schedule, the proposed modified Cogen/SPP rate schedule will not have any effect on the Company’s revenues in the near term.”