U.S. utilities led by Southern Co. are burning a record amount of natural gas to generate electricity without triggering a forecasted boost to the fuel’s price from near 10-year lows.
The power companies used 34 percent more gas in February than a year earlier, Energy Department data show. Even Atlanta-based Southern, historically one of the largest U.S. coal-plant operators, is on pace to consume more of the cleaner burning fuel than coal in 2012 for the first time in its 100-year history. Utilities are the nation’s biggest gas consumers.
The historic switch to gas is set to peak this year without fulfilling industry predictions that it would eat up inventory and drive up gas prices. That’s because unparalleled output from new shale fields is oversupplying the $95 billion U.S. gas market, postponing relief for hundreds of producers.
Record gas use “may not be the panacea that people think” it will be, Jason Schenker, president of Austin, Texas-based Prestige Economics LLC, said in a telephone interview. Schenker was the fourth-best predictor of gas prices in the first quarter, according to data compiled by Bloomberg.
The difficulty of forecasting fuel prices led managers of two energy funds to close in the last four weeks, including John Arnold’s Centaurus Energy Master Fund.
While benchmark U.S. gas prices have gained 43 cents from a 10-year intraday low of $1.902 per million British thermal units on April 19, most analysts are not calling the bottom of the price cycle for a fuel that traded above $13 in 2008.
No Bottom Yet
“I’m not expecting a lot of upside through summer” for gas prices, Tim Evans, energy analyst with Citi Futures Perspective, said in a phone interview. “We’re still sitting on a massive inventory of storage.”
Bulging gas stocks are also being sustained by a combination of unusual weather that’s depressing electricity sales and decisions by power company executives to avoid becoming over-reliant on the historically volatile fuel.
Marketed gas production reached a record 66.22 billion cubic feet a day in 2011 and may rise another 4.5 percent this year, according to Energy Information Administration estimates. Inventories rose to 2.576 trillion cubic feet the week ended April 27, 50 percent above the five-year average for the week, the agency reported May 3.
Instead of helping power producers like Southern and Exelon Corp., cheap gas cuts revenue because it drives down wholesale electricity prices, squeezing margins for plants that run on nuclear, renewable and coal power. The utilities are close to their limit of shifting the mix toward gas.
“You have stretched the rubber band in terms of coal-to-gas switching as much as you can,” Arun Jayaram, an analyst with Credit Suisse Group AG in New York, said in an interview.
Meteorologists say the winter that just ended was the fourth-warmest on record and will be followed by a cooler summer for much of the U.S. compared with a year ago. If the weather remains mild, total power consumption will be 1.8 percent lower from July through September from a year earlier, the Energy Department said.
Daily gas consumption averaged 5 billion cubic feet more at power plants this year through April 10 compared to year-ago levels, Credit Suisse’s Jayaram said. He predicts increases will ultimately slow to an average of 3 billion cubic feet a day this year as generators manage abundant inventories of both coal and gas.
To make a dent in gas inventories, the power industry will need to burn at least 4.5 billion cubic feet more each day on average this year from 2011 levels, according to data compiled by Bloomberg New Energy Finance.
That is “absolutely unprecedented, but not out of the question,” Charles Blanchard, fossil fuels analyst for Bloomberg New Energy Finance, said in an e-mail.
The power sector is predicted to account for 35 percent of total U.S. gas demand this year, up from 31 percent last year, Energy Department data show. The trend has accelerated as gas prices fell in much of the country below coal, traditionally the second-cheapest source of power behind nuclear energy.
Gas at the Henry Hub in Louisiana, the delivery point for New York futures, averaged $2.60 per million British thermal units in February, while Central Appalachian coal averaged $3.06 per million Btu, according to the Energy Department.
Coal remains the leading source of power in the U.S., but fell to an average of 37 percent of electricity generated during January and February from 46 percent a year ago, Energy Department show.
Coal’s Share Drops
“For the first time since the 1970s, we’ve seen coal’s share of energy production fall below 40 percent,” David Herr, leader of Duff & Phelps’ energy and mining practice, said during a March 28 webcast. In 2010, “coal was sitting at 50 percent, where it had been for the last decade.”
Duke Energy Corp., Dominion Resources Inc. and Southern already had been increasing their reliance on gas in anticipation of tougher federal pollution standards and as prices began falling from a three-year peak on July 2, 2008 of $13.69 per million Btu.
Falling wholesale electricity prices also spurred the switch by making it uneconomical for power producers to retrofit older, smaller coal-fired plants to comply with tougher emissions standards, Herr said.
As gas became the preferred fuel source, Southern and other power producers fired up generation capacity built after the last gas price plunge a decade ago.
Near Record Capacity
Southern ran its combined-cycle gas turbine fleet at a near record 70 percent of capacity during the first quarter, doubling the plants’ typical use, Thomas Fanning, Southern’s chairman and chief executive officer, said in an April 25 phone interview.
Southern, which produces almost as much power as Australia, expects to derive 47 percent of its electricity from gas this year and 35 percent from coal. Five years ago, the company produced 70 percent of its power from coal and 16 percent from gas, Fanning said.
Southern has tried to balance its power-plant fleet with a mix of nuclear energy, coal, gas and plants that can run on either fuel “so we can respond to the changing fuel market,” Fanning said. “That’s exactly what we’re doing.”
Gas output in the lower-48 states has grown because of hydraulic fracturing, or fracking, and other improved drilling techniques that make it economic to extract fossil fuels from shale rock like the Marcellus in the U.S. Northeast. Drilling in oil-rich reserves, such as in North Dakota and Texas, often also yields gas.
If weather patterns return to the norm this fall, PPL Corp. expects to run its coal-fired plants longer than during the first quarter, when its gas units ran at as much as 92 percent of capacity, William Spence, CEO of the Allentown, Pennsylvania-based utility owner, told analysts during a May 4 conference call.
Public Service Enterprise Group Inc., New Jersey’s largest utility owner, ran its New Jersey and Connecticut coal-fired plants at just 2 percent of capacity during the first quarter as nuclear reactors and the gas plants handled the weather-diminished power load.
Executives worry their industry’s headlong embrace of a notoriously unstable commodity may contribute to a price spike later in the decade when the U.S. begins exporting liquefied natural gas, William Levis, president and chief operating officer of PSEG Power, the Newark, New Jersey-based company’s merchant power unit, said in a phone interview.
“We like to keep as many options available for us as we can,” said Levis, “It wasn’t that long ago that the price of gas was high.”
Whether prices begin to rise in the near term will depend largely on how much U.S. consumers run their air conditioners this summer, Stephen Schork, president of Schork Group Inc., a consulting group in Villanova, Pennsylvania, said in a phone interview.
The U.S. probably won’t experience the extreme heat that scorched Texas and neighboring states last year, Joe Bastardi, chief meteorologist with WeatherBell Analytics LLC of Boalsburg, Pennsylvania, said in a phone interview.