Of all the junior E&P companies in Canada, few have so consistently seized the attention of analysts as DeeThree Exploration.
Through good times and bad, for the company and the industry at large, DeeThree has attracted strong buy recommendations for its results in various Alberta plays, notably in the Southern Alberta Bakken.
Keith Schaefer is one of the most closely followed prognosticators. As editor and publisher of Oil & Gas Investments Bulletin, he tracks emerging growth companies and backs his evaluations by taking positions in the companies.
He is enthusiastic about DeeThree under the leadership of Martin Cheyne, who joined the company more than six years ago after 30 years of founding and leading several companies to the takeover point.
Schaefer says DeeThree has created “fantastic assets” out of its core operations in the Alberta Bakken and the Belly River play in west-central Alberta.
“They were able to read those assets way better than any previous operators and really figure out the geological code that allowed their teams to extract way more production than anybody else,” he said in an interview last year.
He said the deals were “very expensive at the time, (but have since) ended up being very, very cheap because the company managed to successfully develop them.”
Among those companies that have the “highest possible analyst recommendations,” based on an average score, DeeThree topped the list of 17 (all with market capitalizations of at least C$500 million) at 5.0, which represents a “strong buy” assessment.
And it was one of the few from the energy sector at a time when fewer analysts are making “high-conviction” energy calls.
Chad Ellison, an analyst at Dundee Capital Markets told his clients earlier this year that DeeThree “maintains a relatively strong balance sheet and is expected to still grow production spending approximate cash flow, which is becoming a rarity given current commodity prices.”
Conservative capex
Shares in the E&P company immediately rose 11 percent after it announced a conservative C$160 million capital budget for 2015, while aiming to grow production by 18 percent to 13,300 barrels of oil equivalent per day. The company is allocating C$68 million to drill 13 wells in the first half on projections of an average West Texas Intermediate price of US$50 a barrel and C$92 million to drill 16 wells in the second half when it is banking on oil prices averaging US$60.
Shetlander Randhawa, an analyst with RBC Dominion Securities, said the DeeThree program seemed “reasonable,” adding “we remain positive on DeeThree shares for the company’s material unbooked upside and strong per share growth metrics via the drill-bit.”
Alberta Bakken status
For the Alberta Bakken, the focus will be on “building sustainability and maximizing the value and ultimate oil recovery of this very significant defined resource,” DeeThree said.
It indicated that much of its optimism is attached to early results from a gas injection enhanced oil recovery program, which third-party consultants say will boost recovery factors by 200 percent beyond primary drilling.
Since starting a pilot in mid-2013 the company has spent C$7 million installing a built-for-purpose compressor and associated high pressure injection lines which allow it to reinject all currently produced gas.
The injection rate was stepped up in September, with early results pointing to reduced declines over a 9,000 acre area in the heart of the pool.
DeeThree said a horizontal infill well drilled and completed this year has “exceeded expectations and provides additional data which further support the case for gas reinjection.”
The well has tested at various flowing rates of up to 1,800 barrels per day of crude and has continued to flow at a restricted rate of 37 bpd of oil and 450,000 cubic feet per day of gas after 14 days of production.
A second well using monobore technology was drilled into the pool, yielding cost reductions of 25 percent to 30 percent.
Given these results, DeeThree said it is confident the EOR scheme is effective, allowing it to plan for an accelerated transition to full implementation of EOR in the Alberta Bakken.
The company said it is focused on long-term development of the pool, aiming to maximize oil recovery and capital efficiency.
“With an improved decline rate, increasing pressure support, a large drilling inventory and reduced capital costs, the company is expecting to grow production and free cash flow at a sustainable rate even under current commodity pricing,” it said.
Reserves, costs and capex
The reserve engineering firm of Sproule Associates has evaluated DeeThree’s total proved plus probable reserves in the Alberta Bakken, the Brazeau area of west-central Alberta and the Peace River Arch of northwestern Alberta at 51.8 million boe (75 percent oil and natural gas liquids), up 31 percent in 2014, with the additions representing triple 2013 production.
Finding, development and acquisition costs are estimated at C$21.51 per boe on proved plus probable reserves.
Proved plus probable future net capital is earmarked at C$388 million, which represents less than 2.5 years of the company’s forecasted capital budget.
In 2014, DeeThree drilled 47 gross (46.93 net) wells with a 94 percent success rate, including 18 gross (18 net) wells on the Alberta Bakken property.
A deeper look at SAB
In the Southern Alberta Bakken region, DeeThree holds 396,300 net acres of prospective land (400,600 gross acres), with the fairway stretching over 30 miles.
Production from the play is pushing towards 5,000 boe per day (80.5 percent oil and liquids).
The Bakken strategy includes drilling to expand the size of its play to the west where the company recently acquired a 100 percent working interest in 22,000 acres that DeeThree said was the last remaining block available between a 2012 discovery well and the existing core oil pool that exceeds 44,800 acres.
A discovery well was drilled in the third quarter of 2014, testing a 16 foot-thick pay section identified in a vertical strat test well.
The company said the successful horizontal well was a seven-mile step out from its existing Bakken production. About 4,600 feet of Bakken pay was successfully fracture stimulated, placing 155 metric tons of sand over 16 stages using an energized water based system.
The plan now involves modified well lengths, frack size and well placement to “optimize results from the large oil-in-place resource.”
