Halcon Resources Corp. continued making gains on drilling and completion efficiencies in the second quarter, mainly in the Williston Basin, where the Bakken/Three Forks Shale accounted for more than half of its record-breaking 42,055 boe/d.
The company beat its quarterly guidance for the second time in a row (see Shale Daily, May 12), producing 15% more oil and gas than in the first quarter. Production was up 44% year-over-year, and the company’s Bakken unit churned out 28,259 Boe/d in the second quarter, up 87% from 2Q2013.
“We ran an average of four rigs during the second quarter, but we recently dropped a rig due to efficiency gains,” said CEO Floyd Wilson of the company’s Bakken program. “We’re drilling the wells more quickly, so we’re getting just as many wells completed with fewer rigs.”
The company’s assets in the Eagle Ford of East Texas, which it calls El Halcon, rounded out second quarter volumes, producing 9,111 boe/d.
Despite its strides in the Williston Basin, financial analysts who joined Halcon for its second quarter earnings call on Thursday were most interested in the company’s nascent Tuscaloosa Marine Shale (TMS) program in Mississippi and Louisiana. Halcon acquired roughly 307,000 net acres there and said in February that it would become a third operational core (see Shale Daily, Feb. 27).
Despite a strong test from its first operated TMS well last quarter, Horseshoe Hill in Wilkinson County, MS, which had a 24-hour peak rate of 1,548 boe/d, Halcon reported Thursday that it hit a snag at its second well, the Black Stone 4H-2. Halcon said the well was drilled with a 5,400-foot lateral and completed with 22 hydraulic fracturing (frack) stages, but during clean-out operations it encountered “fill” on stage 10 that has only been partially removed.
“How long it takes? I’m not positive. You know we’re pretty cautious down there,” Wilson said in response to analyst questions about the issue. “It’s clearly a sign of something we don’t like to find when there’s fill in the casing. That can come through perforations or it can come through casing problems. We’ll figure that out, what we do know is that our job there is to get flow going and we’ll report it as soon as we do. It should be a few days to finish that phase and get to flow, but it’s just complicated at that depth and you decide you need a different tool or another string of pipe.”
Wells Fargo Securities analysts seemed to downplay the incident, saying there remains a “steep learning” curve in the TMS that operators will have to deal with. To be sure, other companies have encountered similar problems in the play. Goodrich Petroleum Corp. said in December that its Huff well in Amite County, MS, became clogged with frack-related debris, and Sanchez Energy Corp. faced an issue at its Dry Fork East well last week with drill pipe defects (see Shale Daily,July 25;Dec. 27, 2013).
“We understand that other operators are looking at increasing rig counts and all this leads to a lot more information about the field,” Wilson said. “If you think about the play — I guess there’s been about 50 wells drilled so far — you know the first larger number of those wells were not so good. Of the few good ones in there, the last 10 wells drilled in the play have been mostly good wells. So it’s a traditional learning curve situation going on there.”
The company said it has signed an agreement with affiliates of Apollo Global Management LLC to invest up to $400 million in its TMS program. Halcon operated two rigs in the play this quarter and Floyd said that could double by next year. For the remainder of this year, it will spud eight operated wells and participate as a non-operated partner in up to 12 others.
The company is also waiting to complete two more TMS wells in Wilkinson County, where its operations are focused for now.
In the Bakken, Halcon spud 14 wells and put another 19 online during the second quarter. It expects to spud 23 wells for the remainder of the year and said it will participate in up to 140 non-operated wells. Downspacing tests in the basin continue to yield positive results, the company said, while faster drilling reduced costs by 8%.
A plan rolled out by North Dakota regulators earlier this month to reduce the amount of flared gas in the state by 2020 (see Shale Daily, July 3), which will go into effect next year, should not impact Halcon, Floyd said.
“Flaring has been a concern for us ever since we got into the play. We’ve been working as hard as we possibly can to get this stuff in pipelines,” he said. “At this time, we don’t believe we’re going to have any shut-in production if our partners in the midstream business up there are able to meet their targets of installation and flow. We’re not in total control of that, but right now, I don’t think we’re planning to be curtailed this year.”
In the Eagle Ford, Floyd said the company is still focused on enhancing its drilling program. The company is testing the length of frack stages, reduced cluster spacing and pumping more resin coated sand to maximize results. Halcon has plans to drill 22 wells by year’s end with three rigs.
Overall, the company produced 85% oil, 7% natural gas liquids and 8% natural gas during the second quarter. Excluding the impact of hedges, Halcon said it realized 91% of the average New York Mercantile Exchange oil price and 113% of the average Nymex natural gas price.
The company reported a net loss of $73.3 million, or 18 cents/share, for the second quarter, compared to net income of $37.3 million, or 3 cents/share, in 2Q2013, mainly on the impact of derivatives and accelerated payments for acquisitions in the TMS.
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