Cabot Oil & Gas Corp. announced Friday that it has identified two new exploratory areas that could eventually compete with its core acreage in the Marcellus and Eagle Ford shales.
Management did not disclose where those areas are or what formations are being targeted, but executives said there could be enough data by the end of this year to determine if the plays will be viable. Cabot has increased its 2017 budget by $125 million to cover the costs of exploratory leasing and testing. More than half of that, or $66 million, has already been spent on those efforts.
“We have identified two new areas that we believe warrant further testing,” CEO Dan Dinges said during a conference call on Friday to discuss first quarter results. “These are areas where we have a direct line of sight towards building sizeable, contiguous acreage positions that allow for efficient operations at — most importantly — a low cost of entry. I would define a sizeable position as one that has the potential to provide over a decade of high quality drilling inventory.”
Responding to several questions from analysts about the wildcatting, Dinges said the company was “indifferent regarding the commodity diversity” when it set out to find new growth opportunities, adding that the company looked at areas that “are not necessarily in the fairways of the key basins.” Based on the company’s information so far, Dinges said it’s “looking like our focus is going to be oil.”
“We have seismic. We do plan on shooting additional seismic. We do have control points, subsurface control points that we’ve incorporated into our interpretation,” he said of the exploratory areas. “And the initial process would involve a combination of both verticals to gather core data and then probably a short lateral to evaluate the section a little bit more thoroughly. All of that is included within our capital program.”
While its Marcellus program was built from grassroots, the company’s exploration efforts have not always been successful. Over the years, it’s analyzed the Tyler Formation in Montana; the Chainman Shale in Nevada, the Pearsall Shale in Texas and the Rogersville Shale in West Virginia, among others.
More recently, about two years ago, Dinges acknowledged the company was undertaking exploration efforts south of Wood County, WV, in the western part of the state in an area where it was known to have drilled one of the first modern Rogersville Shale wells. The company holds more than one million noncore acres across the United States.
“I think these are new projects outside of what they’ve tested in the Rogersville and the Utica,” Williams Capital Group analyst Gabriele Sorbara told NGI’s Shale Daily. “…I don’t think it’s going to be a gas play. If I had to put money down, I’d say it’s going to be an oil play so they can kind of diversify.”
Sorbara added that at a few hundred dollars per acre, or even at $1,000/acre, the company’s latest leasing and testing efforts are a way to reinvest cash flow at a lower cost than, say, a multi-billion dollar acquisition in the Permian Basin.
“What this says is essentially, ‘hey, we’ve got all this free cash flow and we can’t find a merger or acquisition (M&A) that fits and makes economic sense’ where you can generate full-cycle returns,” Sorbara said. “ ‘We’re going to go out and do it organically, or attempt to do it organically.'”
Dinges did say there’s a “high degree of risk associated with a grassroots leasing exploration effort” but added that “compared to our evaluation of the acquisitions made in the M&A space, and the implied economics of those actions, we are comfortable with the risk profile and the potential project returns of our ideas to support this grassroots effort.”
The $125 million dedicated to the exploration projects is a “drop in the bucket” and shouldn’t concern investors for now, Sorbara added.
Increased activity in the Eagle Ford Shale and outperforming Marcellus wells that were aided by better natural gas prices allowed the company to increase its exploration and production budget to $775 million from the previously announced budget of $650 million. It was the second time this year that the company has increased spending. While its drilling and completion schedule remains unchanged, Cabot also increased its 2017 production guidance from 5-10% growth to 8-12% growth.
The company produced 170.1 Bcfe in the first quarter, up from 160.3 Bcfe in the year-ago period and 164.2 Bcfe in 4Q2016. Cabot has seen improvement in pre-hedge price realizations over the last four quarters. Including derivatives, the company earned $2.64/Mcf for its natural gas during the first quarter, up 77% from a year ago and 36% from 4Q2016.
“Realizations for April and May will likely be about 25 cents lower than the first quarter average,” Dinges said. “However, this implies that our average natural gas price realizations for the first five months of the year will be about 70% higher than the same period in 2016, highlighting the significant improvements in cash margins we are realizing to date.”
Improved prices helped revenue during the quarter, which went from $281.9 million in 1Q2016 to $517.8 million. Cabot reported net income of $105.7 million (23 cents/share), compared to a net loss of $51.2 million (minus 12 cents) in the year-ago period.
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