AEP shuts in coal capacity due to cheap gas, but is about maxed out on doing that

The capacity factors at American Electric Power’s (NYSE: AEP) coal-fired power plants have decreased on a quarterly and year-to-date basis, while the capacity factors for its natural gas-fired facilities have jumped, AEP officials said during a July 20 earnings call for the second quarter.

Said Brian Tierney, CFO and Executive Vice President: “For both quarterly and annual periods, our generation from natural gas has increased approximately 80%. For our eastern combined cycle units, the increase in capacity factors and generation is even more pronounced. With the addition of the Dresden generation facility to our Waterford and Warrensburg plants, East combined cycle generation has increased 250% for the quarter and 181% for the year-to-date period. With year-to-date capacity factors for these plants approaching 70%, the ability to realize incremental coal-to-gas switching within our eastern fleet is reduced.”

East combined cycle statistics include the addition of the Dresden 580-MW combined-cycle natural gas plant in Ohio, which came on line in February of this year. In the second quarter of this year, the average capacity factor for the eastern coal units was 44.8%, down from 55.1% in the same quarter last year. Average capacity factor for the West coal units in the second quarter was 70%, down from 81.5% in the year-ago quarter.

This switching and the general pricing environment for coal, natural gas and electricity has led to an increase in AEP’s coal inventory from 45 days at the end of the first quarter to 48 days at the end of the second quarter. This is about six days more inventory than at the end of the second quarter of last year. “Our coal needs for 2012 are fully hedged and our needs for 2013 are about 90% hedged with many units fully hedged,” Tierney noted.

Nicholas Akins, AEP CEO and President, told analysts that AEP has budgeted $6bn for largely clean-air compliance programs, then was asked if cheap gas and a dynamic U.S. Environmental Protection Agency regulatory situation will change that spending plan. “[I]t changes as we get new information and it changes as a result of discussions we have with the states and with the EPA,” he responded. “And of course, we continue to work, as I said, on the legislative side because EPRI has done an independent analysis showing that it costs one-third less if you wind up with a two-year extension if you’re able to optimize that. But I think it’s important for us to go through the process in concert with the states, and it really focuses on that operating company model where we’re working with them to determine what the proper solution is. [W]e continue to search and as you see some of the changes that have been made, such as with the Big Sandy scrubber proposal being pulled at this point, we’re reevaluating that, we have some activity in Oklahoma around coal-fired generation as well that we’ve adjusted to do.”

AEP’s Kentucky Power subsidiary earlier this year pulled a plan to add a scrubber on the 800-MW Unit 2 at Big Sandy, saying the situation needed reevaulation.

Akins continued: “You’ll continue to see those kinds of adjustments because what we’re trying to get to is, number one, a portfolio that each of our operating jurisdictions support, and then secondly, a portfolio that provides some risk management around a balanced portfolio going forward. So for us, it’s a relatively high hurdle for us to be putting scrubbers on our facilities. In many cases, it’s already done. In some cases, it continues to be an evaluation, even for units such as the 1,300-MW units at Rockport. Paul Chodak over at [Indiana Michigan Power] is working with the regulators to determine what the proper opportunities are for that so that we can meet the emission reduction guidelines, and that’s being discussed in all of our jurisdictions. So you bring up a great point, and that’s something that we’re very focused on. And we’ll continue to try to optimize. Matter of fact, when we first started this process, we were looking at $8 billion, and it’s come down to just over $6 billion, and we expect it to continue to be refined as we go forward in concert with the states.”

Akins said AEP is concerned about the reliability implications of what the EPA is doing because one thing AEP hasn’t talked about is the capacity factors of those small, older coal-fired units that AEP is dependent upon during the peak demand times. “As we had last year, these units are being called on and connected to the system 54% of the time and are running in the order of 30% capacity factor during these peak months,” he added. “So they’re still needed. And we’re going to have to work through that process. And even with those committed to provide the peak, and obviously they have minimum run time obligations and minimum load obligations, we still achieved almost 80% capacity factor on the gas units. So that pretty well tells you we’re really switching back and forth based upon what the peak requirements are but utilizing the energy component through the natural gas as much as we can.”

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.