Given a mandate to optimize metrics across the board, Chesapeake Energy Corp.’s operations teams grabbed their axes and took to chopping, a task so well performed over the past year that CEO Doug Lawler on Wednesday declared them “weapons-grade.”
Lawler helmed a conference call with his senior management team to discuss third quarter results, which across the board proved to be a solid success. The Oklahoma City-based independent generated production, adjusted for asset sales, that was 11% higher year/year and 5% higher sequentially, with double-digit sequential gains in the Eagle Ford, Haynesville and Utica shales, and from the Powder River Basin.
“Quarter-over-quarter for the last four quarters we have met or exceeded our production targets, met or reduced our capital expenditure budget and consecutively reduced our cash cost,” Lawler said. The improvements have positioned the company “to be highly competitive even in a reduced commodity price environment.”
Production averaged 726,000 boe/d, 11% higher than in 3Q2013. Average production consisted of 118,900 b/d of oil, 95,900 b/d of natural gas liquids (NGL) and 3.1 Bcf/d of natural gas. Sequentially, 3Q2014 average NGL production increased 14% and average gas production increased 3%, adjusted for sales.
The overall production gains led Chesapeake to increase the low-end of its 2014 production guidance by 10,000 boe/d. It now expects year-end output to be between 730,000 and 750,000 boe/d. The production gains came despite an 8% reduction in capital expenditures year/year to $1.35 billion.
“I just have been super impressed with the focus of the leadership and employees inside of Chesapeake,” said Lawler, a former Anadarko Petroleum Corp. executive. “I’m not kidding you. It’s like weapons-grade, attacking costs and driving value that is unlike anything I’ve ever seen before…The best way to look at 2015 is to look at how the company has performed in 2014.”
The cost reductions have been reinvested in improved completion designs, “ultimately showing higher well performance in nearly every play,” said CFO Nick Dell’Osso. That in turn drives even “higher returns, not just reduced costs, in every play.”
Senior Vice President (SVP) Chris Doyle, who runs the northern division, and SVP Jason Pigott, the southern division chief, are former Anadarko executives who came aboard last year.
“Jason and I sit down with the teams every quarter…in post appraise, and I think what has been really gratifying for both of us to see is sequential improvement across the board and in almost every play, continually redefining what efficiency means,” Doyle said. He pointed to an operation in the northern Marcellus Shale, where a 30 MMcf/d well recently was completed for “under $8 million, something that the company hadn’t been able to do to-date.” Most of the wells have cost $10 million-plus.
However, “the team, just like a lot of teams across the board, have continued to not only drive efficiency, not only drive cost down but also re-think completions, re-think how we’re investing those dollars and it is evident across the entire portfolio,” Doyle said.
Rates of returns (ROR) on each of the wells are going up on the cost reductions, and the performance from the wells is higher too, Pigott said. Operations teams are looking at ways to optimize completions and get the estimated ultimate recovery side of the equation up, to drive up the “value on a per-well basis and increase the ROR,” which in turn, “gets more out of the wells in inventory.”
For instance, using cross-unit laterals in the gas-heavy Haynesville Shale has proven to be an efficient way to go. Chesapeake next year now plans to drill up to 70% of its wells there as cross-unit laterals.
“We’ll spend about $500,000 extra and gain $2 million of NPV [net present value] for every well that we can drill cross-unit lateral,” said Pigott. “It’s the little things that tend to make a big difference for us…”
Drilling and completion capital expenditures totaled $1.24 billion, nearly flat from a year ago and 10% higher from the second quarter on an increased number of wells and completions. Chesapeake spud a total of 296 gross wells and connected 311 to sales in the period, quarter, compared to the previous three months of April through June, when it spud 324 wells and connected 275 to sales.
In the Eagle Ford, net production averaged 102,200 boe/d, up 12% sequentially, with average well costs of $6.4 million/well, versus $6.9 million in 2013. Lateral lengths in 3Q2014 were 6,300 feet with 20 fracture stages, compared to an average completed lateral length of 5,850 feet and 18 fracture stages year ago. Wells in various stages of completion or waiting on pipeline have increased to 152 as of Sept. 30, versus 109 wells at the end of 2013 on increased activity and pad drilling efficiencies, “however, the time spent in inventory is markedly shrinking.”
Haynesville net production averaged 562 MMcfe/d, up 11% sequentially. Average completed well costs are $8.2 million with an average completed lateral length of 5,050 feet and 20 fracture stages, compared with an average of $8.9 million in 2013 with an average completed lateral length of 4,400 feet and 18 fracture stages.
Utica net production averaged 85,500 boe/d in the quarter, 27% higher sequentially. Average completed well costs are around $6.5 million with an average completed lateral length of 6,300 feet and 32 fracture stages, compared with an average of $6.7 million in 2013 with an average completed lateral length of 5,150 feet and 17 fracture stages.
“The average of completed well costs is already significantly below the year-end 2014 target of $7.1 million per well despite incurring additional capital reinvestment in completions,” Chesapeake noted. Wells in various stages of completion or waiting on pipeline in the area decreased to 172 as of Sept. 30, compared to 195 at year-end 2013. The average peak production rate of the 77 wells that commenced first production in 3Q2014 was 1,175 boe/d.
In Northern Pennsylvania, net output averaged 882 MMcfe/d in the quarter, up 1% from 2Q2014, with average well completion costs of $7 million, an average completed lateral length of 6,300 feet and 32 fracture stages. That compares with an average of $7.9 million in 2013 well costs with an average completed lateral length of 5,400 feet and 13 fracture stages. Laterals have increased 17%, the number of fracture stages has nearly tripled and proppant per lateral foot has measurably increased all while total well costs have declined 11%.
Wells in various stages of completion or waiting on pipeline in the area increased to 125 at the end of September, versus 112 at the end of 2013 on increased pad drilling. Cycle times have continued to fall and “the company anticipates significant reduction to inventory over the next 12 months. The average peak production rate of the 23 wells that commenced first production in the northern Marcellus during the 2014 third quarter was approximately 13.4 MMcfe/d.”
There isn’t a lot the company can do about commodity prices, except to lay down rigs. And that may happen in the dry gas area of the Northeast, where basis differentials remain a problem. Chesapeake’s gas pricing differentials in parts of the Marcellus during the second quarter into July weakened relative to Henry Hub benchmark and were significantly lower than forecast (see Daily GPI, July 29).
The Northeast’s gas pricing issues are expected to continue in the next few months.
“To address our outlook on commodity prices for the rest of the year we increased our expected natural gas differentials by 5 cents due to the continuation of low regional prices we saw in October in the Northeast,” he told analysts. “We want to remind everyone that differentials consist of two components, basis, which is typically a field price discount to Henry Hub pricing and non-basis items such as gathering, transportation, processing and marketing costs. The increase in our basis outlook for the fourth quarter is primarily related to the former in the Northeast part of the country, reflecting the low field pricing in Pennsylvania.
“The prices…received for the Marcellus production have been particularly low over the past six months due to the abundant supply of gas volumes and lack of regional demand in the summer and fall. However, we do expect those local and regional prices to improve over the next four to five months with the onset of increased demand due to winter weather.”
Into 2015, Chesapeake expects basis, particularly in the Northeast, “to remain challenged as we come out of the winter months, and we will likely reduce our activity in our northern Marcellus play accordingly. From a hedging perspective, we have relatively significant position of 2Q2015 gas hedges at attractive prices averaging $4.51/Mcf. We also have had substantial amount of oil at just under $95/bbl and we’ll continue to look to add both positions should prices justify doing so.”
Chesapeake reported net income of $169 million (26 cents/share) versus $145 million (22 cents) in the year-ago period. Operating cash flow was $1.29 billion, down from $1.41 billion.
On the report, BMO Capital Markets revised its estimates on the operating efficiencies, “maybe more a function of picking the low-hanging fruit rather than true operating innovations. (That’s the ‘weapons-grade’ attack on costs management labeled on the call.) That may not matter…The uncertainty sits with whether that rate of change decelerates, or whether more capital efficiency gains can be achieved in a lower commodity price environment. This last point speaks to any oilfield service cost deflation being more than offset by lower commodity prices. At $80.00/$3.50 pricing held constant, we see the shares trading at about 5.5 times in each of 2015 and 2016 (little compression of multiple; company unhedged in 2016). Leverage sits below 2.0 times in each of those periods, a reduction of debt owing to proceeds from the recent asset divestiture ($5.4 billion).”
Wells Fargo Securities analysts said the company had posted “solid improvements on costs across the portfolio” and “has shown the ability to hit its production and cost targets — price realizations were one of the only weak points in 3Q2014, however, and are likely to remain headwinds through this time next year. Net/net, solid quarter on the heels of continued progress on portfolio optimization.”
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