Whiting says it will begin completing DUCs in Q1 ’17; would start adding rigs at $60 oil
On Whiting Petroleum’s (ticker: WLL) 3Q 2016 conference call, CEO James Volker stated that recoveries from enhanced completions and lower average well costs in the Williston Basin have made the Core Bakken “one of the highest return plays in North America.”
“Our enhanced completions in the Williston Basin range between 900 MBoe and 1.5 MMBoe, based on type curves. We’re getting these done at average well costs of $7.0 million,” said Volker. “Whiting is well positioned with a premier asset base, a strong hedge position, an enhanced balance sheet, and a highly efficient capital plan.”
The company will be ramping its activity in the Williston through the end of the year, increasing rigs running from two to four. Full year production guidance was also increased, with Q4 expected production increasing by 400,000 boe to 10.8 MMboe. Third quarter LOEs were at the low end of guidance at $7.98 per boe.
As shown in the slide below, Whiting’s wells continue to outperform all Bakken peers. Thirteen wells in Central Williston Basin testing at an average rate of 3,727 Boe/d. Three wells from the Bakken formation averaged 3,445 Boe/d and ten wells from the Three Forks averaged 3,812 Boe/d.
WLL Q3 Conference Call Q&A
In the Q&A, Volker further discussed the effects of Whiting’s enhanced completions and how the Bakken compares to the Permian.
Comparing Williston and Permian returns
Q: Can you discuss how returns for Whiting compete versus the Permian Basin? What is the opportunity set in front of you that you think investors might be missing?
A: We sold a fairly large acreage positon in the Permian. We felt that the results we and others were seeing were indicated some variability and that we wanted to focus on the more consistent Williston Basin. If I had to pick right now whether or not to buy down there at the kinds of prices necessary to buy acreage form someone who already owns it, I’d much rather be in the Bakken and Northern Niobrara.
Q: It’s shocking that you are able to get something down in 2.75 days. Will that change dramatically if service costs go up again?
WLL: Under the new design we’re using, after setting about 2,000 feet we’re able to run one string of casing the total depth and that’s really improved our times and cut costs. We would not like to see pressure on prices until oil prices get above $60. Based on the interest we have from major pumping companies as well as a great history of coordination and partnering with them, I don’t expect to see much pressure in pricing in the Bakken or Niobrara, until we get $60. I think these improvements that we’ve made gives us an opportunity to further drop our costs.
Q: Could you talk about the current DUC situation going into 2017? Is it still price dependent?
WLL: We’re going to begin completing them in the first quarter of 2017 and we expect to complete about half of them by year-end.
Q: Can we assume that you’re going to assume full rigs in the Bakken through 2017.
WLL: I would say if oil prices were to get back to $60, you’d see us add some more rigs.
Q: You mentioned it would take $600 million to hold flat from exit next year, has that changed with the improvement in completions along with the DUC backlog?
WLL: I’d like to watch prices to see how volatile they are before I provide guidance on the amount of 2017 Capex. Assuming the current 2017 strip price of $53, we could easily return to double digit production growth based on 2016 to 2017 exit rates and do that by spending near cash flow.
Q: Encouraging to see the uplift from the enhanced completions. Do you have any initiatives next year to test other areas of the Bakken? And are there any areas in your portfolio right now that aren’t amenable to these enhanced completions?
WLL: Virtually all of our Bakken acreage is amenable to these bigger fracs, so we believe that our whole acreage position will benefit. There may be some areas with slightly lower EURs just because of differences in the rock. But we believe in all cases they will be incremental to rate of return and return to investment ratio.
Q: Are you intending to move any rigs east and west in 2017 to test that concept?
WLL: We have the flexibility to do all of the planning that is necessary to stay on track for what I previously mentioned would be double-digit growth next year. So, plenty of flexibility across our acreage position, permitting wise and logistically. We have a number of great rigs up there that are built for purpose and manned by a number of great crews, and frankly overseen by as you can tell from – for example, I’m switching on you from the Bakken down to the Niobrara but as you can tell we have what I think there is some great engineers out there not only doing the drilling, but also the completion operations. We’re optimistic about seeing the length and breadth of our acreage react positively to these bigger fracs.
Q: What sort of returns would you get based on current costs and pricing strips?
WLL: In the 30% – 40% IRR range.
Q: Are you agnostic over whether you transfer the oil by rail or pipe?
A: Obviously the pipe differentials are better for us. We don’t actually determine whether it moves by pipe or rail, we sell prior to that and marketing folks make that decision.
Q: Do you have any concerns from a political standpoint with future pipeline buildout in the region?
A: The Bakken has plenty of capacity to move the oil that we would produce now or in the future between rail and pipe. We think the pipeline in question will ultimately be built, though there may be a little bit of a delay.
Q: How much are you going to be paying in cash taxes going forward?
A: We still have significant non-operated losses and we will again be generating non-operated losses in the future at least where the current projections look. So we don’t think we’re going to be paying any cash taxes for at least three to five years.
Links to the company’s Q3 2016 presentation, webcast, and press release are provided.
