EPAC 2017 Top Junior Producer award sponsored by KPMG.
In its short six-year history, Tamarack Valley Energy has exhibited an enviable growth profile, from 735 boe/d when as a private company it acquired Tango Energy, a gas-focused junior, and began trading on the TSX Venture Exchange.
Today, Tamarack Valley Energy—winner of the 2017 EPAC Award for Top Junior Producer—is pumping out 18,000 boe/d, has a listing on the big board at the TSX, and is a force to be reckoned with in the low-cost, quick-payout Cardium and Viking oil plays of central Alberta and west-central Saskatchewan.
Tamarack got where it is today through a steady diet of acquisitions in its core Cardium and Viking areas, but transformational for the company was its $407-million acquisition of privately held Spur Resources, announced late last year and completed this past January. The purchase brought more than 6,250 boe/d of production (52 per cent liquids) into Tamarack and raised the number of net identified drilling locations that will pay out in 1.5 years at current strip pricing to 681.
“We anticipated that 2016 was going to be a year in which we felt high-quality assets were finally going to come to the market and in which the bid-ask spread was going to narrow,” Brian Schmidt, Tamarack president and chief executive officer, says.
“And that’s what we saw. We picked up some Redwater properties, we acquired the Penny property in southern Alberta—both nice, light oil properties with tremendous opportunity—and then we ended the year with Spur.”
Tamarack cut drilling to zero in the first half of 2015 and focused what cash resources it had on paying down debt. High-graded drilling resumed in the second half of 2015 and continued through 2016. The new wells, plus the Cardium, Penny and Redwater acquisitions, pushed average production in the fourth quarter last year to a record 11,453 boe/d from 8,448 boe/d in 2015.
But Spur was transformative. Tamarack is currently producing more than 18,000 boe/d with the added Viking production and is looking at annual average production this year of close to 20,000 boe/d.
“We went from about 10,000 boe/d to about 18,000 boe/d with these assets, so it’s been a great growth year for us, but like you know, now is the time to put the meat on the table and show what these [assets] can do,” Schmidt says. “This year is going to be one in which we show shareholders that we are going to drive production per share; we’re going to work these assets and deliver what we promise.”
What Tamarack is promising is a $170-million capital program in 2017 that will see it drill about 150 wells, with 60 per cent of the program focused on the new Spur assets, where there is the greatest potential to add new reserves. Legacy Cardium properties will see most of the rest of the capital allocation, but in all cases, only locations that can offer payback in 18 months will be considered, Schmidt says.
“We know that, as long as we drill those 1.5-year payback wells, we can’t destroy the balance sheet,” he says. “We can build production, and we can’t destroy the balance sheet.”
While drilling was suspended in the first half of 2015, Tamarack’s engineers set about re-thinking how they drill their wells, both in the shallow Viking play and in the deeper Cardium. What they settled on for both were longer laterals, tighter frac spacing and a move away from open-hole ball-drop fracking technology.
“When you give engineers some time, and they’re not busy chasing rigs around, they have time to figure out how to do things better, and that was valuable time for us,” Schmidt says. “We were able to get our [initial production] rates up, cut our cost structure. During that juncture, we went away from open-hole ball-drop fracs to sleeves, and that was a big step change for us in terms of driving our rate of return.”
Virtually all of Tamarack’s Viking wells going forward will feature three-quarter-mile laterals as opposed to the traditional half-mile laterals, while Cardium wells will adopt two-mile laterals, which are quickly becoming industry-standard opposed to the older one-mile horizontal legs.
Schmidt also wants to see more eight-well pads in the Viking, which opens the door to pre-set casing and economies of scale and some more experimentation with the number of frac stages and proppant used on Viking frac jobs, which together can drop the cost of a typical well by $50,000 or more—a key consideration for a company with its sights set firmly on the bottom line. It’s even taken to buying used pumpjacks and only a few sets of well controllers, since they’re not needed forever and can be moved around from well to well as required.
“It only takes a couple of days to drill a Viking well, so cost control really comes down to how you manage the logistics of your drilling program,” Schmidt says. “Most of the guys here came from Apache, where we had 1,500 wells a year, and we would make or break our programs on logistics.”
The EPAC 2017 Award Winners
Top Junior Producer: Tamarack Valley Energy