Chesapeake Energy Corp. continued to slash onshore exploration costs — and capital spending — during the third quarter, while production continued to rise. However, as the company burns through its cash, CEO Doug Lawler said the focus going forward is to uncover value, not volumes.
Production overall, adjusted for asset sales, averaged 667,000 boe/d, about 3% higher than a year ago. Natural gas, which is 72% of total output, averaged 2% higher at 2.9 Bcf/d. Oil production rose 4% to 114,100 b/d, while natural gas liquids output climbed 7% to 76,200 b/d. The gains came despite continued production curtailments, which averaged 51,000 boe/d — all from the Utica and Marcellus shales (see Shale Daily, Aug. 5).
Enhanced completions paid dividends across the board, considered important as the No. 2 U.S. gas producer expects no relief for commodity prices next year.
“The flexibility and the options that we have in the portfolio give us a lot of strength,” Lawler said. “As we look to next year, we are looking to meaningfully reduce our capital.” Natural gas prices, “when you look at the strip, you see some sort of recovery but we’re not designing this business around increasing prices. The drive for efficiency, the quality of the rock, the quality of these assets [mean] we have got to find a way to be competitive. I can assure you that the capital spend and investment next year will be directed at how we can capture from this strong portfolio the greatest value.
“With our program we have significantly ramped down our activity, and we continue to take it down. As we look forward to 2016, we’ll maintain that flexibility to make further adjustments based on prices, based on capital efficiency and based on performance.”
The company reported a $4.695 billion net loss (minus $7.06/share) after writing down the value of its portfolio. Nearly all of the losses — $4.612 billion — were for impairments to the value of the portfolio. In 3Q2014, profits were $169 million net (26 cents/share). Adjusted net losses totaled $83 million (minus 5 cents/share) versus profits of $251 million (38 cents).
Operating cash flow sunk to $476 million from $1.293 billion, while revenue plunged 49% to $2.89 billion.
Chesapeake today concentrates its exploration and production efforts in six onshore regions: the Eagle Ford Shale, Haynesville/Bossier shales, Oklahoma, Powder River Basin (PRB) and in Appalachia. The decline in activity was evident.
On average, Chesapeake operated only 18 rigs during 3Q2015, versus 26 in 2Q2015 and 69 a year ago. Eighty-four wells were completed, down from 121 sequentially and 309 in 3Q2014. Gross wells spud fell to 84 from 109 sequentially and 296 a year ago. And gross wells connected was down to 112 from 173 in 2Q2015 and 311 in 3Q2015.
In the Marcellus, which Chesapeake has considered for sale, Northern Pennsylvania output averaged 809 MMcf/d net, down 1% sequentially. Voluntarily curtailments began early this year and are to continue, with output “actively managed” through the winter months.
Well costs are falling, with completed wells averaging $6.4 million year-to-date in the Marcellus, versus full-year 2014 costs of $7.5 million. Average completed lateral lengths and fracture stages are rising, at about 6,800 feet with 29 stages, versus 6,000 feet and 27 fractures a year ago. Recent well results include two tests of the Upper Marcellus formation in Bradford County, PA, with one having a lateral length of 5,600 feet and peak 24-hour production rate of 19 MMcf/d. The second well had a lateral length of 4,800 feet and a rate of 170 MMcf/d. One operated rig is expected to keep running through the rest of the year.
Utica net production averaged 106,000 boe/d in 3Q2015 down 15% sequentially because of the shuttered wells. Average completed well costs fell to $7.7 million from $7.2 million in 2014, while laterals averaged 7,900 feet with 40 fracture stages, versus 2014’s average lateral of 6,200 feet and 29 fractures. In the latest period, Chesapeake set a new record lateral length of 12,976 feet. Additionally, the average cycle time for the wells drilled was 9.9 days, with a record cycle time of 6.8 days. The operated rig count averaged two, which is expected to be maintained through December.
In the Eagle Ford, net production averaged 108,000 boe/d, 3% higher sequentially. Completed well costs have fallen to an average $5.3 million, with laterals of 6,000 feet and 21 fracture stages, versus 2014 well costs of $5.9 million, laterals of 5,850 feet and 18 fracture stages. Thirty wells were placed on production during the quarter, versus 89 a year ago. The operated rig count of three is expected to hold through the end of the year.
Haynesville’s gassy output fell 5% from the second quarter, averaging 636 MMcf/d net. Well costs have fallen to $7.7 million from $8.4 million in 2014, with laterals averaging 5,000 feet and 14 fractures, versus year-ago laterals of 4,900 feet and also 14 fractures. Seven Haynesville wells were tied to sales, half the number from a year ago. Six operated rigs ran during the quarter, and six are to run through the end of the year.
Northern Oklahoma’s Mississippian Lime output averaged 31,000 boe/d net, off 1% sequentially. Completions this year have averaged $2.8 million with laterals of 4,500 feet and nine fracture stages, down from 2014 well costs of $3.0 million, laterals of 4,450 feet and nine fractures. Thirteen wells were placed on production in the latest period, versus 44 in 3Q2014. Three operated rigs were running during 3Q2015m but all of them have since been released.
In Northwest and Central Oklahoma, the company drilled its first two wells targeting the Meramec formation and it currently is drilling a third. The company intends to keep one operated rig to the end of the year.
The PRB, where the operator is working in the Niobrara formation, output averaged 21,000 boe/d, an increase of 5% sequentially. Average completed well costs to date are $10.6 million with an average completed lateral length of 5,900 feet and 22 fracture stages, versus full-year 2014 average well cost of $10.6 million, lateral length of 5,400 feet and 20 fracture stages. Chesapeake no longer has any rigs running in the play after running one during the quarter.
In part because of enhanced completions, capital expenditures have been trimmed for 2015 by $100 million to $3.4-3.9 billion. Total capital spending in 3Q2015 was about one third less sequentially and less than half that of a year ago at $623 million.
Production expenses were $4.09/boe, while general and administrative expenses were 79 cents/boe. In addition to optimizing base production and generating efficiencies in the field, Chesapeake was able to eliminate almost “$200 million of annualized, controllable production and general and administrative expenses,” said Lawler.
Chesapeake expects to sell $200-300 million worth of assets by the end of the year, which likely won’t make a dent in spending or plans, CFO Nick Del’Osso acknowledged during the conference call.
“Given the continued volatility in the market due to commodity prices and the better clarity around our forward liquidity position, we have been happy to be patient when it comes to any assets we evaluate for sale,” the CFO said. “However, we are making solid progress on the sale of noncore, nonoperated positions where we are in the process of contracting several deals that we believe will bring in $200 million to $300 million between the fourth quarter of this year and the first quarter of 2016. This does not include some potential larger asset sales that we are evaluating.”
BMO Capital Markets analyst Dan McSpirit questioned why Chesapeake doesn’t turn to the equity markets instead to raise capital.
Potential asset sales are a “step in the right direction, in our view, but does little to move the needle in terms of leverage/debt load, even on lower spending levels next year as we have it modeled…
“We say ”just raise equity’ somewhat in jest, appreciating it’s not a decision that’s taken lightly, but not ignoring the multiple at which the shares trade and the commodity price that’s discounted. Our point is that it’s hard to see a way for the company to get out from underneath its debt-heavy balance sheet without doing so or, at least, without having to monetize core assets such as the Eagle Ford Shale, for example. For now we’ll forget the Stack…a play whose resource potential the market is unlikely to ascribe much value in this tape, at least until the economic limit is made more certain, in our view.”
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