Economics Favor Natural Gas Even as Coal Burn Rebounds

Natural gas–fired generation gave up some ground to coal during the third quarter, and coal producers are optimistic that higher natural gas prices in recent weeks will benefit coal, especially coal sourced from the Powder River Basin in Wyoming. Even so, at least one Midwest utility expects natural gas to power what could be as much as 1,500 MW of new generating capacity it may add over the next several years.

“Overall, our generation from natural gas has increased approximately 50% year-to-date,” said Brian X. Tierney, CFO of American Electric Power (AEP) during the company’s third-quarter earnings conference call. With the addition of the Dresden gas-fired facility to AEP’s existing Waterford and Lawrenceburg plants, the utility’s East combined cycle generation was up 114% for the quarter and 160% for the year-to-date period.

Tierney said that with year-to-date capacity factors for those plants approaching 70% and with the recent increases in forward natural gas prices, the ability for more coal-to-gas switching within the company’s eastern fleet is minimal. “Because of the hot weather, our coal units were in more in the third quarter than in the second quarter,” Tierney said. AEP’s coal inventory fell from 48 days at the end of the second quarter to 45 days at the end of the third quarter. Still, this is higher than AEP would like: The utility’s target is 35 to 40 days.

Jack A. Fusco, CEO and president of Calpine, said that gas futures prices for 2013 suggest some continued coal-to-gas switching in the East, but probably none in Texas. As a result, this year’s strong showing by the company’s natural gas–fired generating assets seems unlikely to be repeated next year.

Greg Boyce, CEO of Peabody Energy, a major coal producer, told an earnings conference call that the company continues to expect a decline of approximately 120 million tons in coal use for power generation this year. “The worst of this impact has already occurred, with the U.S. down some 100 million tons, mostly from coal-to-gas switching that was front-loaded in the first half of the year,” he said.

Boyce said that since last spring, natural gas prices have shown “robust” increases. Weekly gas storage injections remain below average, and prompt gas prices are above $3.50/MMBtu, with the forward strip above $4. He called those factors “favorable” for demand for Powder River Basin and Illinois Basin coal.

Boyce said Powder River Basin plants are at 70 to 80 days burn, with Central Appalachia above 120 days. Peabody projects an increase in domestic coal consumption of some 40 million to 60 million tons in 2013, which Boyce said would help rebalance stockpiles to more normal levels.

Grid stability proved to be an important factor in keeping some coal plants online, despite low natural gas prices. Robert Gaudette, senior VP and chief commercial officer for GenOn Inc., said “we still have very important, very well located coal units in the grid that have got to run. So we can talk coal-to-gas switching as much as we’d like, but some of our very big coal units are essential to grid stability.” Those units are likely to run even in some of the most constrained power generation markets.

Those coal-fired power plants that have installed emissions control equipment also may enjoy a competitive advantage. Robert C. Flexon, CEO and president of Dynegy, said his company’s coal fleet in November completed environmental retrofits to comply with an Illinois environmental consent decree. The retrofits also are expected to enable the Dynegy units to meet requirements under the federal Environmental Protection Agency’s Mercury and Air Toxics Standards rules.

“As shutdowns occur, capacity markets will tighten and our coal fleet should be a beneficiary of this tightening market,” Flexon said. “Continued low natural gas prices serve only to accelerate the pace of competitor plant shutdown.” He pointed to recent announcements of nuclear capacity in the Midwest Independent System Operator (MISO) region being retired in 2013. 

Higher natural gas prices and a return to normal winter weather could reverse the market share loss that coal experienced starting a year ago. John Eaves, president and CEO of Arch Coal, told his company’s earnings conference call that 2011 heating-degree days were nearly 25% below normal, which “dramatically impacted” coal and gas demand. He said a near-normal winter this year could lead to a “sizable step-down in coal stockpiles” and “meaningful gas-to-coal switching.” The St. Louis–based company remains cautious, however, and is taking steps to manage through a “potentially challenging” 2013, he said.

Beyond 2013, Arch expects an improvement in domestic coal markets. Although Arch estimates that 45 GW of coal-generating capacity could be retired by 2018, much of that capacity represents the coal fleet’s smallest and least efficient units, which are already running at low levels. Eaves said those plants likely will burn 40 million tons of coal in 2012, down from 75 million tons in 2010. “Any incremental negative impact from these potential coal plant retirements is likely to be modest,” he said.

Eaves said the lost consumption could be offset by rising utilization at the remaining 280 GW of installed coal-fueled capacity. “Collectively, the remaining coal plants are running below a 60% utilization rate today,” he said. “As U.S. power load grows, it’s reasonable to assume that the underutilized coal units could pick up that incremental burn lost from the retired plants.”

Despite the cautious optimism from the coal industry’s largest producers, at least one Midwest utility said it favors natural gas for expected new generation. John Russell, president and CEO of Michigan-based CMS Energy, said the company expects that with seven of its coal plants mothballed in 2015 or 2016, and with MISO possibly increasing its reserve capacity to 18%, the utility’s capacity shortfall “could be as high as 1,500 MW.” Russell said that gas generation likely will be the fuel of choice for the new capacity, and that the company will make a decision in 2013 on what could amount to an $800 million capital investment.

“It changes our balance of the portfolio a little bit in our fleet, but based on natural gas prices going forward, I think that is the right thing to do which keeps us well balanced but a little heavier on natural gas than we are today,” Russell said.

—David Wagman is POWER’s executive editor.

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