Gas producers in North America including Chesapeake Energy Corp. (CHK) are killing their commodity’s biggest rally in 10 months by opening more wells, putting the U.S. on track to have record gas supplies this year.
After a 44 percent price rise beginning Sept. 10, the fuel began a slide Oct. 30, falling 9.2 percent by Nov. 12 as stockpiles swelled to an all-time high this month, valued at about $15 billion using the current spot price. Gas production in 2013 is expected to match this year’s record level, the U.S. Energy Information Administration forecast this month.
The rebound stalled as Chesapeake, the second-biggest U.S. producer, and rivals added output in areas such as the Marcellus Shale in Pennsylvania. ConocoPhillips and Encana Corp. (ECA) brought back curtailed output. Some producers that struggled when the fuel hit a 10-year low in April are opening new wells, dashing hopes by others that a depressed rig count would boost prices.
“Unfortunately all the players in this game don’t read by the same Bible,” said Peter Howard, chief executive officer of the Canadian Energy Research Institute in Calgary. Producers need to keep gas wells shut and “force the price up,” he said.
Although U.S. prices were hovering for much of the year at about a third of their 2008 level, companies that rely primarily on gas sales to cover costs such as interest on debt began pumping more. Lower prices limit companies’ cash flow and can lead to asset sales and spending cuts.
“As the gas price goes down, it’s almost like they need to produce twice as much to keep their cash flow where it was,” said Edward Kallio, director of gas consulting at Ziff Energy Group in Calgary. “That’s the bind producers that don’t have diversity in their portfolio are in.”
Gas companies had pinned some of their hopes for higher prices on the sliding number of new drilling rigs. Active U.S. gas rigs had plunged 49 percent this year, according to Baker Hughes Inc. (BHI) The count was 413, the company said Nov. 9, compared with 809 in a Dec. 30 report. It was the lowest U.S. gas rig count since June 1999.
Futures for delivery this December settled at $3.739 per million British thermal units yesterday and are heading higher, as traders and buyers are expecting the rally to continue after forecasts for colder weather: The futures are more than $3.80 in all 12 months of next year, according to data compiled by Bloomberg.
The price rises to more than $3.90 in July and more than $4 in November and December of 2013.
“We’re at least 50 cents per million Btu overstated for the forward strip for next year,” Kallio said. “There’s a lot of gas available below that price. The forward strip is way too optimistic for next year and probably into the year after.”
The recent rise in gas prices could mean that drilling re- starts in some basins, while not in others, said Kent Moors, a professor at Duquesne University in Pittsburgh who edits Oil and Energy Investor, a newsletter.
“If we are at $3.70, virtually every well coming in in the Marcellus is profitable, Moors said. “It won’t be in the Barnett, it won’t be in the Haynesville.”
Among analysts surveyed by Bloomberg, the average price for 2013 is $3.58 per million British thermal units. The analysts’ average is at less than $5 through 2016.
Encana idled production when gas prices in New York dropped to less than $2.50, and resumed production at some wells in August. The company, based in Calgary, said on Oct. 24 that volumes were “largely restored.”
At Houston-based ConocoPhillips (COP), gas output in the third quarter from the lower 48 U.S. states rose 3.5 percent from the second quarter. The company had idled gas wells equivalent to a range of 10,000 to 12,000 barrels of oil a day.
“We don’t have any significant volume shut in at all now,” Matthew Fox, an executive vice president at ConocoPhillips, said during an Oct. 25 conference call. “Some of that increase is gas coming back online, but the majority of it is increases in associated gas production with our liquids- rich plays.”
As oil is extracted from dense rock formations, gas produced alongside the crude can enter the market. Companies that drill for petroleum liquids such as propane, ethane and butane also bring more gas online.
“In the Bakken, it’s about one million cubic feet a day of gas for 1,000 barrels of oil, a little over one to one,” Kallio said. “As you blow through the oil, you get gassier.”
The supply could grow, too, if producers capture and sell more of the associated gas from unconventional fields. About 29 percent of the gas produced in North Dakota’s Bakken field is flared because there aren’t enough pipelines to transport it, according to the North Dakota Industrial Commission.
Some of the biggest surges in U.S. gas output are in the Marcellus. The rise in production and the backlog of wells coming online as pipelines are built means gas prices could hover as low as $3 per million Btus for parts of next year, said Howard of the Canadian Energy Research Institute.
Anadarko Petroleum Corp. (APC) of The Woodlands, Texas, said Marcellus gas sales volumes were 333 million cubic feet a day in the third quarter, about 6 percent higher than in the second quarter. The performance was stronger the company expected, particularly in wells owned with Chesapeake.
“We’ve been surprised by just how productive Chesapeake’s been,” Anadarko Chief Executive Officer Al Walker said during an Oct. 30 conference call. “We see them doing things, frankly, that are well outside of what we anticipated.”
Chesapeake, based in Oklahoma City, said Nov. 1 that third- quarter gas production climbed to 302 billion cubic feet, or 9.8 percent more than in the second quarter.
Chesapeake’s shares gained 1.5 percent in the third quarter, while Anadarko rose 5.6 percent in the period, as the Russell Midcap Energy Index climbed 11 percent.
At Southwestern Energy Co. (SWN), a Houston-based company whose production is nearly all gas, production in the third quarter rose 5 percent from the second quarter.
Talisman Energy Inc. (TLM), the Calgary-based producer, will cut spending in the face of lower prices, Chief Executive Officer Hal Kvisle said in an Oct. 30 telephone interview.
“This is a time where big North American producers need to batten down the hatches and let supply and demand come back into balance,” he said.
Rising demand from power generators and other consumers will be able to absorb gas production in 2013, although the balance could be upset by unexpected weather, said Scott Hanold, an analyst with RBC Capital Markets in Minneapolis.
“The weather by itself can do that,” by suppressing the need for gas, Hanold said in an interview.
The increase in gas-fired electric generation, which helped push up prices during the summer, may not last, said Brian Watson, director of research for Steelpath, which invests in pipeline companies. Utility companies will be able to switch back to coal if gas prices climb too high, he said.
Even though many companies have stopped drilling for so- called dry gas, production may not fall because of the backlog of wells that have been drilled and await completion, Raoul LeBlanc, senior director of North American onshore energy at PFC Energy in Houston, said in an interview.
Production in the Haynesville Shale in Louisiana has stayed flat, even though the rig count has fallen to 17 from a high of 105 a year ago, LeBlanc said, citing PFC’s internal estimates.
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