Chesapeake Energy Corp. began flowing a Marcellus Shale well last week and after six days, it reached a peak rate of 61 MMcf/d of natural gas, making it the company’s highest-rated operated well in the play and possibly the highest ever in northeastern Pennsylvania, management said Thursday.
The McGavin well began flowing back last Friday, CEO Doug Lawler said during a conference call initially to discuss second quarter results.
“In the Marcellus,” he said, “we began testing different completion designs with flow capacity” during the second quarter. McGavin results “are nothing short of outstanding.”
Chesapeake plans to test and enhance completion designs in many of the 40 or so remaining wells to be placed on production from the Marcellus by year’s end, Lawler said.
Exploration and production chief Frank Patterson said the Marcellus team’s challenge was to figure out how to optimize and make the “best” completions possible.
“We had to basically redesign the surface facilities,” Patterson said of the Marcellus operations. “As you can imagine, we’re not used to bringing on 60 MMcf/d wells in the Marcellus…
“As far as the Marcellus, as we see it today, we’ve been producing pretty steady in the 2 Bcf/d to 2.2 Bcf/d range. That’s our capacity as far as being able to get gas out of the field. We are still looking for a more opportunities, because this is a great rock and we can step on the accelerator.
“But I think the more important thing about the big well is, it tells you first, how good the rock is because this is in a developed portion of the field. It’s not an outlier, it’s kind of in the heart of the field. Secondly, as we push these better completions of longer laterals, it’s going to speak to the capital efficiency.”
Patterson said Chesapeake in the Marcellus should have “less capital in the ground or the same amount of gas, which is pretty substantial. And then, the third and probably the most important thing for the future is, this is in the core of the field.”
As Chesapeake has done in the Haynesville Shale, the updated Marcellus completions design could be moved into less prospective areas outside the core, which could “actually change what the core is in this field,” Patterson said. “And our footprint in really high quality gas now probably could be expanded substantially.”
The McGavin well has been more expensive than other wells Chesapeake has drilled in Marcellus, Lawler said. With a 10,500-foot lateral and a “relatively aggressive” fracture (frack) stimulation, the well cost an estimated $8.5 million.
“These are early numbers, of course, because we’ve only been on for about six days or seven days, but we believe that we can get that cost down as we go forward,” Lawler said.
Operations chief Jason Pigott said the Marcellus team had been trying to figure out how to get 60 MMcf/d from the wells, “and they actually call it the ”Rambo frack’ because they needed to attack that…formation like a Rambo in a POW camp.
“So they increased the cluster efficiency and stacked it with 32 million pounds” of proppant, ensuring they could “set the captive gas molecules free,” Pigott said.
Chesapeake should deliver a 2017 overall target of 10% production growth year/year and should exceed a goal of 1,000 boe/d, Lawler said.
“We expect our total production to move higher throughout the year, driven by large turn-in-line projects underway in the Eagle Ford, Utica and Powder River Basin operating areas. This has already started, as we averaged approximately 548,300 boe/d, including a peak rate of 90,400 b/d of oil production, for the month of July.”
Production in 2Q2017 averaged more than 528,000 boe/d, flat sequentially.
“We expect our production will accelerate further beginning in August as we plan to place on production approximately 60 wells in this month alone,” Lawler said. “The second half of 2017, we expect to turn in line approximately 250 wells, representing more than half of our total turn in line wells for the year.”
In the Eagle Ford Shale, Chesapeake is in the process of bringing online 20 wells in western Dimmit County.
“Our oil growth trajectory for the company for the remainder of 2017 is primarily driven by the Eagle Ford,” Lawler said. “The second half of 2017 we expect to place roughly 100 wells online in South Texas, compared to 61 wells turned in-line during the first half of 2017.”
Meanwhile, Chesapeake plans to raise another rig in October in the Powder River Basin (PRB), bringing the total count to three.
“We are very encouraged by the results we have seen from our first Turner department wells along with the early results from our first Mowry well,” the CEO said of the PRB. “We plan to dedicate the third rig exclusively to additional Turner development and place another four wells on production in the Turner this year. Our first Mowry wells provide confirmation of what we estimate to be a significant resource.”
And in the Haynesville, Chesapeake recently completed a 7,500-foot lateral well in DeSoto Parish, LA, with a peak rate of more than 38 MMcf/d or nearly 5.15 MMcf per 1,000 lateral feet.
“This result is particularly important,” Lawler said, “because this well is located outside of the Springridge area, where the majority of our recent success has taken place. This well’s performance gives us additional encouragement as we prove the concept of long laterals and enhanced completions across our entire acreage position.”
Chesapeake also performed its first Haynesville recompletion using a new production liner, with the refrack reaching almost 9 MMcf/d from a lateral of only 2,990 feet, Lawler said. “This is the encouraging result that we look forward to doing more refracks in 2018.”
The company today is using 18 rigs across the U.S. onshore; it expects to drop to 14 by year’s end.
Chesapeake now is projecting an improvement in oil basis by 30 cents/bbl in part on “strengthening market conditions in the U.S. Gulf Coast and a flatter contango oil curve, along with several successful marketing development initiatives across all four oil bases in our portfolio,” CFO Nick Dell’Osso said.
Gathering, processing and transportation expenses were $7.44/boe in 2Q2017, a decrease of 7% from a year ago.
Year-to-date, Chesapeake has sold around $360 million of assets, which has helped reduce debt, improve its working capital deficit “and improved our profitability on a go-forward basis,” the CFO said. “We expect approximately $265 million of the signed asset sale agreements to close in the third quarter. The production impact of the assets sold to-date in 2017 is minimal, about 16 Bcf of gas.
“Since we have not adjusted our total gas production guidance for the year, it’s also a reflection of the productive power of our remaining gas assets.”
Other assets are up for sale, particularly in the Midcontinent area, along with “larger assets as we work toward our goal of removing $2 billion to $3 billion of debt from our balance sheet.”
Chesapeake has about 74% of its remaining projected 2017 gas production hedged at $3.09/Mcf and 60% of projected oil production hedged at $50.32/bbl. Using the midpoints of production guidance, it also has hedged a “meaningful portion” of 2018 gas production at $3.09/Mcf and added to 2018 oil hedges, which have an average price of around $49.87/bbl.
Net income was $470 million (47 cents/share) in 2Q2017, up from year-ago profits of $75 million (8 cents). Operating cash flow was $303 million, reversing a year-ago loss of $14 million. Revenue increased 41%.
At the end of June, Chesapeake’s principal debt balance was $9.7 billion with $13 million in cash on hand, compared to $10 billion with $882 million in cash on hand at the end of 2016. Total liquidity at the end of June was $3.1 billion.
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