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Chesapeake Making Shift to Oily Plays
Chesapeake Energy Corp., long one of the most active natural gas drillers and producers in North America, is stealthily making a land grab to secure domestic oilfields, part of a long-range plan to rebalance a portfolio that now is 93% weighted to gas, CEO Aubrey McClendon said last week.
The Oklahoma City-based producer issued its operational performance report on Tuesday and its earnings numbers Wednesday, ahead of a conference call with financial analysts Thursday, which was helmed by McClendon.
“Clearly, every producer in America is looking at how to increase their oil production,” said the CEO. “Our success in finding oil in the U.S. does not affect global oil prices, but more gas negatively affects gas prices. Sometimes producers are accused of not being rational, but we think we’re more rational than people give us credit for. We’re responding to price signals.”
“Whether its gas-to-liquids or if there’s a big increase in the transportation sector’s demand for natural gas, either directly through CNG [compressed natural gas] or gas for electricity, that is obviously the Holy Grail for industry — to have gas achieve oil parity in the U.S. Around the world, as we talk to our partners, Statoil, Total, BP and other people, as they see the world and LNG [liquefied natural gas] balances, the emerging view is that beyond 2012, 2013, we’re likely to get back into a scenario in the world where gas prices approach oil and prices, and we’re likely to be short gas on a worldwide basis,” said McClendon.
“We learned last year that the world is not going to be awash in shale gas in the next five to 10 years,” he told analysts. “The success of that proposition is unique to North America and it will be many years before there’s any impact on worldwide gas balances.”
It may appear to some that Chesapeake is not following that plan, with its relentless gas drilling in the onshore. But there’s a method to the seeming madness. Chesapeake wants to get as much drilling as it can so that it’s held by production (HBP), and it then can slow the pace and take its time to develop the gas when prices are right, said McClendon.
Chesapeake will boost its capital spending a “little bit” in 2010 and 2011, but gas production will be falling as its oil and natural gas liquids (NGL) output “greatly increases,” said the CEO. “That transition is under way. We’re using the maximum number of rigs to get to HBP status before the leases start to expire; it’s different for every play.”
Once the company reaches the level “where the shale acreage is HBP, then we’ll be ramping down and allocating to the oil areas,” he said. “We’ve got 20 rigs in the Haynesville, and it will be pretty much HBP by the end of 2010, and we’ll cut the rig count in half. A lot of drilling today doesn’t seem supported by pricing, and that’s probably true, but the secondary driver is to get the acreage HBP. Except for the Marcellus, that will happen in the next 12-24 months” across all of Chesapeake’s gas shale plays.
Asked whether Chesapeake may have a problem in pulling back on gas shale drilling in those areas where it has joint venture agreements in place, McClendon said the company is required to earn carries in the Barnett and Marcellus plays, and “obviously, we’ll maintain a level of carries…We’ll also talk to our partners to make sure our go-forward plans are consistent with their go-forward plans. We have plans to drop in the Haynesville and the Fayetteville once we reach HBP status.”
Current gas prices aren’t economic to develop gas shale, said McClendon.
At New York Mercantile Exchange (Nymex) gas prices, “when you include basis differentials and gathering and compression, $5 Nymex is $3.50 at the wellhead,” he said. “Despite the success we’ve had, $3.50 does not create enough cash flow in the industry to maintain drilling even at today’s drilling pace. $5 is not a sustainable gas price for even the best shale plays.”
Chesapeake’s view, according to McClendon, is that gas prices “will be set by the gas price required to incentivize another couple hundred rigs, and we stand by our conclusion on that number, which is somewhere between $6-8. We’ve seen nothing in the industry to persuade us that we’re wrong. So far, for the industry in the fourth quarter, more companies were showing sequential production declines than increases.
“We think [Energy Information Administration] 914 data is likely to reflect what we’re likely to see. You’ve got to remember that 50% of the production is the production we see in public company reports; it’s the best production in the U.S. We’re not seeing the worst 50%, and we think that’s probably in fairly substantial decline.”
The producer now has 10 rigs in the Fayetteville Shale; 11 in Haynesville; 12 in the Barnett; and it’s in the “midteens” in the Marcellus play, said McClendon. “We’re transitioning in our budget, which we budget internally out to 2012, and that shift from gas to oil is already under way. We’re know more obviously on production and the reserve numbers going forward.”
For the short-term, Chesapeake remains all about gas. Production in the last three months of 2009 averaged 2.618 Bcfe/d, which was 13% higher than production in the year-ago period and up 5% sequentially from 3Q2009. Adjusted for voluntary production curtailments because of low natural gas prices (around 26 MMcfe/d), volumetric production payment transactions (96 MMcfe/d), and the estimated impact from various divestitures (around 49 MMcfe/d), Chesapeake’s sequential and year-over-year production growth rates would have been 5% and 17%, respectively, in 4Q2009, after making similar adjustments to prior quarters.
Output in the final quarter totaled 2.44 Bcf/d of natural gas and 29,750 b/d of oil and NGL. Average prices realized were $6.05/Mcf and $71.61/bbl, for a realized natural gas equivalent price of $6.45/Mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to Nymex in 4Q2009 were a negative 53 cents/Mcf and a negative $5.27/bbl.
Last year Chesapeake drilled 1,148 gross operated wells (831 net wells with an average working interest of 72%) and participated in another 1,126 gross wells operated by other companies (99 net wells with an average working interest of 9%). Also last year Chesapeake invested $2.94 billion in operated wells (using an average of 104 operated rigs) and $439 million in nonoperated wells (using an average of 60 nonoperated rigs) for total drilling, completing and equipping costs of $3.38 billion.
The producer now has one of the largest combined inventories of onshore leasehold (13.7 million net acres) and 3-D seismic (23.6 million acres) in the United States and the largest inventory of U.S. “big six” shale play leasehold in the Barnett, Fayetteville, Marcellus, Haynesville, Bossier and Eagle Ford (2.9 million net acres). Chesapeake also has 190,000 net acres in the emerging Anadarko Basin Granite Wash leasehold.
At year’s end, Chesapeake had identified an estimated 14.6 Tcfe of proved reserves and 65 Tcfe of risked unproved resources (177 Tcfe of unrisked unproved resources), based on the year-end 2009 10-year average Nymex strip prices. The company is currently using 118 operated drilling rigs to further develop its inventory of 35,750 net drill sites, which represents more than a 10-year inventory of drilling projects, it said.
Because of hedging losses and impairment charges related to the carrying value of its assets, Chesapeake reported a net loss in 4Q2009 of $530 million (minus 84 cents/share) and operating cash flow of $1.212 billion on revenue of $2.222 billion. Excluding one-time charges Chesapeake earned $490 million (77 cents/share).
The one-time charges in the most recent quarterly report included a mark-to-market hedging loss of $126 million; $875 million related to the carrying value of gas and oil properties under the full-cost method of accounting; $5 million related to some of the company’s midstream assets contributed to its newly formed midstream joint venture with Global Infrastructure Partners; $14 million on exchanges of senior notes for stock; and a combined charge of $45 million for the full year related to restructuring and relocation costs in the Eastern Division, workforce reduction costs and the loss of some gathering systems.
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