Current AMZG Stock Info

Bakken/Three Forks Producer Exceeds Production Guidance for Q3 by 40%

American Eagle Energy (ticker: AMZG) found a way to navigate around some backwash from last spring/early summer’s closed county roads in Divide County, North Dakota. At that time the company was forced to shut in producing wells because trucks weren’t allowed to collect crude on site due to county-wide road closures, impacting the company’s production.

Management initially estimated net production would come in between 2,100 to 2,200 BOEPD for Q3’14 because of the addition of a new 4-well pad approximately a month into the quarter. Instead, the pad took production past 3,000 BOEPD by the end of September, putting production at the high end of the estimated 2014 exit rate a full quarter early.

“We learned some things last winter,” Marty Beskow, VP capital markets and strategy for American Eagle, told Oil & Gas 360® in an exclusive interview Monday. “We have a plan in place now that helps us work in the severe climate. We are doing more pad development. We’ll try to go in and frac all the wells on the pads before the coldest part of the winter,” Bestow said. “The area where we operate is slated to get electrical power beginning in Q4 through mid-2015, which will eliminate problems like diesel generator fuel lines freezing up and having to endure downtime to get frozen engines running.”

Cold winter-wet spring or not, American Eagle has been plowing through its 2014 drill plan in the Spyglass project of Divide County, North Dakota. The company added 7 gross (3.0 net) operated wells in the first quarter, 8 gross (4.0 net) operated wells in the second quarter and 7 gross (5.2 net) operated wells to production in the third quarter 2014, according to its Sept. 24 operations update. The Q3 wells include the 4-well pad (3.5 net wells) recently placed on production.

“A lot of operators in the Bakken and Three Forks are tweaking the completion formula, trying to find the best techniques,” Beskow said. “We are totally focused on keeping costs under control, but we will tweak a few things to improve production rates. Our wells are shallower, and there’s no overpressure so we don’t have to use ceramic proppant to prevent crushing, for instance. We’ve gone from 2 million pounds of sand to 2.5 million, and we will be testing more wells with more sand. We’re doing 30-40 stage fracs with 2.5 million pounds of proppant.”

American Eagle’s Ely 8-1E well, a long lateral in the Bakken formation, produced an average of approximately 400 BOEPD during the first 30 days. The Ely 8-1E is the first well in the field with a full slickwater stimulation. “Those results are above our normal type curve on a Middle Bakken well,” Beskow said. Up where we are in Divide County, the wells generally have a lower IP rate than the rest of the basin, but they present a flatter decline curve.”

The shallower wells lead to lower drilling and completion costs relative to AMZG’s peers, who are drilling deeper than 10,000 feet. The 4-well development pad (3.5 net wells) that was drilled in June cost an average of $5.8 million to drill, complete and equip each well. “After one or two years, when you take into account the lower well costs, the wells in Divide County produce really good IRRs. It just takes more time to realize what the true IRRs were.”

The majority of AMZG’s wells are currently connected to disposal and takeaway pipelines, and the liquid condensate “is sold in bulk,” Beskow said. USG Midstream estimates an additional gas line to the Tioga processing facility will be operational this month. “If operational, the company could achieve full gas sales from connected operated wells during Q4 2014,” according to the company’s operational update.

Bestow estimates a six-year drilling inventory at the company’s present budget and rate from nearly 300 locations in total with 120 locations in the company’s “proved” area; i.e., where the company’s current wells are producing. On its October investor presentation, American Eagle is targeting 30 operated gross wells (20 planned operated net wells) and ten non-operated wells with a total budget of $122 million.

“Everything we do now is driven by efficiency,” said Beskow. “A perfect example if you look throughout the basin is the reduction in drill time of 55%, from spud to release, since 2012. We are focused on execution, developing efficiencies to bring down costs even further, tweaking the completion technique and increasing returns.”

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