Chesapeake Energy Corp.’s U.S.-focused natural gas production is forecast to drop by 7% in 2013, bringing “to an end our likely unprecedented public company record of 23 consecutive years of gas production growth,” CEO Aubrey McClendon said Tuesday.
Until it is worthwhile to produce its estimable gas reserves, Chesapeake has no intention of turning its attention from more profitable oil and liquids targets, McClendon said during a conference call.
“Chesapeake’s projected 7% downward trend in gas production for 2013 will likely continue beyond that year” and until “gas prices rise to levels that make returns from drilling in our gas plays competitive with returns available from drilling in our liquids plays,” he told analysts. “In fact, by year-end 2013, we expect Chesapeake’s gas production rate to have declined by 430 MMcf/d, or 14% from our peak rate of 3.4 Bcf/d in 2012.”
Including output from working interest partners and royalty owners, the total decline in Chesapeake-operated U.S. gas production “is likely to be around 800-900 MMcf/d,” said the CEO.
“It won’t be long” before the Energy Information Administration’s 914 data “shows U.S. gas production on a confirmed downward trend. We believe this trend of declining gas production could continue as long as gas prices do not permit gas producers to earn an attractive return on the investments necessary.”
The U.S. gas storage overhang “is decreasing by an average of 2-4 Bcf/d, each week. If this trend continues and we experience a normal winter, the U.S. gas market could reverse its 900 Bcf year/year storage surplus, established in April 2012, and lead to a potential gas storage deficit in April 2013 of up to 900 Bcf.”
Combining the potential storage reversal and likely production cuts across the industry, “we expect gas markets to look very different during the next few years than they have looked during the past six months,” said McClendon.
The United States “is likely in a very early stages of a multi-year upcycle in gas markets fundamentals and clear evidence of this new up cycle is readily apparent. Gas prices have bounced strongly upward, from $1.84 level set on April 19, which we believe marks the low in the four-year down cycle that started in 2008.”
The upbeat news was a departure from the past few months for Chesapeake, and particularly for McClendon, who has made few public appearances since he was stripped of his chairman title last spring (see Daily GPI, May 2). An internal investigation continues into some of McClendon’s questionable financial transactions, but legalities prevented the executive team from offering any insight into what has been going on since a reconstituted board of directors and former ConocoPhillips Chairman Archie Dunham took over in June (see Daily GPI, June 22).
McClendon instead kept his comments focused on the company’s solid quarterly operational and financial performance.
Chesapeake’s production averaged 3.808 Bcfe/d in the latest period, which was 25% higher year/year and 4% higher than in 1Q2012. Output included 3.027 Bcf/d of natural gas and 130,200 b/d of liquids, which included 80,500 b/d of oil and 49,700 b/d of natural gas liquids (NGL).
Even though dry gas drilling has been significantly curtailed, output still jumped 18% by around 450 MMcf/d from a year earlier. Liquids output was up 65% from a year ago, or about 51,200 b/d. Oil output rose 88%, or about 37,700 b/d, while NGL production growth was 37%, or 13,500 b/d.
Gas production curtailments averaged an estimated 330 MMcf/d net in both the first and second quarters — versus no curtailments a year ago. If Chesapeake had not curtailed some of its gas output, estimated year/year production growth in 2Q2012 would have been 36%, the company said.
Gas curtailments now have ended and Chesapeake doesn’t expect to implement any more shut ins for the rest of this year.
Because of reduced drilling activity planned through 2013 in dry gas plays, Chesapeake is projecting a 12% decline in 2013 in its natural gas productive capacity, compared with 2012, after adjusting for estimated production curtailments of 60 Bcf in 2012.
The management team and the board of directors are currently reviewing operations for 2013 and beyond, which could result in changes to the company’s drilling activity and production levels in 2013, McClendon said. A drilling update is expected when Chesapeake issues its 3Q2012 earnings.
Chesapeake reported its highest quarterly profits in history for 2Q2012, with earnings up 91% year/year. Net profits totaled $929 million ($1.29/share), almost double year-ago earnings of $510 million (68 cents).
Excluding one-time gains, which included $584 million primarily related to the sale of the midstream business, Chesapeake earned $3 million (6 cents/share) in 2Q2012, which was 2 cents lower than Wall Street estimates. Long-term debt climbed 9.5% year/year to $14.3 billion, but the company said it still is committed to paring debt to $9.5 billion by the end of this year.
Quarterly operating cash flow totaled $895 million, and revenue climbed 2% to $3.389 billion. Low natural gas prices sent cash from operations down 45% to $755 million in 2Q2012. Lower prices reduced the company’s total oil and natural gas reserves by 7%.
In 2Q2012 Chesapeake added 4.2 Tcfe of proved reserves through the drillbit for the equivalent of about 700 million boe at a finding and development cost of $1.14/Mcfe.
Chesapeake’s “drilling machine” is “converting large blocks of undeveloped leasehold in the very large quantities of proved reserves,” said McClendon. “And we believe Chesapeake’s performance can improve even further from this very high level as we progress from operations, designs for new asset identification and capture to a more manufacturing-like operations approach designed to maximize efficiency and returns as we shift more fully in the harvest mode…”
Chesapeake’s planned 2013 capital expenditures (capex) now are expected to be about 45%, or $6 billion, lower than in 2012, said the CEO. “Clearly we have listened to investor feedback on this important topic.”
To ensure it can meet its financial obligations, Chesapeake upped its asset sales plans for 2012 by $1.5 billion and now plans to sell $13 billion in assets.
About $7 billion in onshore assets — mostly in the Permian Basin — are set to be sold by the end of September.
A portion of the company’s 1.5 million acres in the Midland formation of the Permian Basin is being sold to affiliates of Houston’s EnerVest Ltd. for an undisclosed sum. Two more Permian asset packages in the Delaware play are expected to be completed within the month.
Negotiations to sell “substantially all” of Chesapeake’s remaining midstream assets are also under way with Global Infrastructure Partners (GIP), which already has purchased most of the assets (see Daily GPI, June 11). GIP has an exclusive offer right until next Monday (Aug. 13). Chesapeake also expects to close “various other asset sales” before the end of September.
Assuming it completes all of its planned property sales by the end of the year, Chesapeake expects to repay $4 billion in term loans and achieve a 25% two-year debt reduction goal.
“We anticipate a much higher return to our portfolio than you’ve seen in the past,” McClendon told analysts. Chesapeake had completed $4.7 billion in asset sales at the end of June, he said.
“During the third quarter, we anticipate entering an asset sales agreements of approximately $7 billion, which would bring our asset sales to approximately $11.7 billion year-to-date. We continue to identify additional assets to sell during the fourth quarter that will help me in our updated goal of $13 billion to $14 billion in asset sales for 2012.”
Another $4-5 billion in asset sales also are on the table for 2013, said the CEO.
“When we have completed our asset sales, we anticipate Chesapeake will still retain core positions in 10 plays, which we believe will be 10 out of the 15 best plays in the country. In each of those 10 plays, Chesapeake will be either the No. 1 or No. 2 producer.”
The 10 plays in which Chesapeake claims to hold the No. 1 or No. 2 positions are the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin and the Texas Panhandle; the Marcellus Shale in Pennsylvania and West Virginia; the Haynesville Shale in Louisiana; the Barnett Shale in North Texas; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River Basin and the Utica Shale in Ohio.
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