Current QEP Stock Info

QEP Resources, Inc. (ticker: QEP) reported a net loss of $53.6 million, or $(0.22) per diluted share for the first quarter of 2018, compared to Q1 2017 when the company had a net income of $76.9 million, or $0.32 per diluted share.

QEP delivered net oil equivalent production in the Permian Basin of 30.9 MBOEPD, including oil production of 24.0 MBOPD. The company reported net gas equivalent production of 286.0 MMcfe/d in Haynesville/Cotton Valley, a 110% year-over-year increase.

“During the first quarter we delivered strong production growth in the Permian Basin, driven by the continued success of our ‘tank-style’ completions and operational efficiency gains in both drilling and completion activities,” commented Chuck Stanley, chairman, president and CEO of QEP.

“We accelerated the well delivery cadence in the Permian through faster drill times and a step-change in the number of frac stages completed each month by each of our two completion crews. As a direct result of these efficiencies, we were able to put 31 net wells on production during the quarter in the Permian Basin, compared to our original plan of 18 net wells. We now expect to complete and put on production nine more net wells than originally forecasted during 2018, resulting in an increase in Permian oil volumes and an associated increase in capital expenditures.”

“As we continue to focus on balancing capital investments and cash flow, we have reduced capital allocated to our Williston Basin and Haynesville/Cotton Valley assets for the remainder of 2018 to support additional investment in the Permian Basin,” Stanley said. “We have delineated and refined our tank-style completion methodology over the past year and are now in full development mode on our Permian assets, giving us confidence in our ability to deliver the results set forth in our revised guidance.”

“We also made great progress on our strategic and financial initiatives announced in February, which will result in QEP becoming a pure-play Permian Basin company. Data rooms for the Williston and Uinta basin assets are open and we expect to have these asset sales completed during the second half of 2018. We also began executing our share repurchase program by opportunistically repurchasing over 6.2 million shares of common stock in March,” concluded Stanley.

Oil barrels keep on rolling

Oil equivalent production was 11.7 MMBOE for the first quarter of 2018, compared with 13.1 MMBOE for the first quarter 2017, an 11% decrease.

First quarter 2018 equivalent production was positively impacted by increased drilling and completion activity in the Permian Basin and Haynesville/Cotton Valley, QEP said. However, the increase was offset by lower production resulting from decreased drilling activity in the Williston Basin and the loss of 3.5 MMBOE of production in Pinedale, as a result of the Pinedale divestiture.


Capital investment, excluding property acquisitions, was $418.8 million (on an accrual basis) for the first quarter of 2018, compared with $214.3 million for the first quarter of 2017. Approximately $400.2 million of the capital expenditures was related to the drilling, completion and equipping of wells and $17.9 million was related to infrastructure investment.

The increase in capital expenditures was primarily related to increased drilling and completion activity in the Permian Basin and Haynesville/Cotton Valley and significant improvements in drilling and completion efficiency primarily in the Permian Basin, which have accelerated the well delivery schedule for 2018.

During the first quarter of 2018, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage in the Permian Basin, for an aggregate purchase price of $36.2 million.

Repurchases, divestitures

During March 2018, the company repurchased and retired 5,621,540 shares at a weighted average price of $9.37 per share, for $52.8 million. Additionally, the company entered into trades to repurchase an additional 592,310 shares at a weighted average price of $9.37 per share, for $5.6 million in late March 2018. The shares purchased in late March 2018 were settled and retired in April 2018.

QEP closed on the sale of several non-core assets for total proceeds of approximately $33.3 million during the first quarter of 2018. In addition, in April 2018, the company has provided data for potential buyers to evaluate for the divestiture of the company’s Williston and Uinta Basin assets.


QEP’s board plans to execute the following initiatives:

  • Divest the Williston and Uinta Basin assets
  • Market remaining non-Permian assets, including the Haynesville/Cotton Valley, in the second half of 2018
    • Use proceeds from asset sales to fund the Permian Basin development program until the program reaches operating cash flow neutrality in 2019, reduce debt and return cash to shareholders through share repurchases
  • $1.25 billion share repurchase program authorized

According to QEP, the company’s updated guidance assumes no additional property acquisitions or divestitures, other than those executed in the first quarter 2018. It also assumes that QEP will elect to reject ethane from its produced gas for the entire year where QEP has the right to make such an election, except in the Permian Basin, where processing economics support ethane recovery.

Rig count:

  • Permian Basin (average of four and one-half rigs) – expected to drop to four rigs in May 2018 for balance of year
  • Williston Basin (average of one-quarter rig) – rig released on April 9, 2018
  • Haynesville/Cotton Valley (average of one-half rig) — rig expected to be released mid-May 2018

Wells put on production:

  • Company – approximately 120 net operated wells
  • Permian Basin – approximately 104 net operated wells

As for refracs, QEP said it plans approximately 28 net refracs between the Williston Basin and Haynesville/Cotton Valley.

Conference call Q&A excerpts

Q: Could you talk a little bit about what the efficiency gains mean for the rig count moving forward into 2019? Should we think about it as staying at 4, and then in terms of a turn-in line cadence kind of expect about 16 per quarter, similar to the 4Q number?

Chairman, President and CEO Chuck Stanley: I think we’re being conservative on the number of wells we think we can get online. We continue to see improvements not only on drill times, but also as we continue to perfect our completion cadence, we expect that our guidance is going to be a little soft or a little conservative relative to what we ultimately put online.

It’s continued to – this – what’s happening in the Permian reminds me of what happened in the mid-2000s at Pinedale as we made significant operational gains on both the drilling and completion front, and it resulted in step changes in the productivity of an individual rig or the productivity of an individual frac crew.

In fact, we think we can probably drop down to one frac crew and four rigs here as we go through the year, as we continue to perfect our completion operations and drive efficiency. So, I wouldn’t get hung up on the normal sort of math you do around wells delivered per rig and wells delivered per frac crew because we’re making what I think is industry leading and significant progress on efficiency. It’s in part the individual well operations, but it’s also, again, the benefit of a compact contiguous acreage footprint and tank-style development, where we’re minimizing rig moves and we’re minimizing rig up and rig down of frac crews as we continue to prosecute development inside the tank.

Q: I also wanted to ask, do you have any more color you can give on the productivity of some of the recent tanks and what you assume in the budget for this year – I think last quarter, the 16 wells on the Thomas pad were still cleaning up. Is there maybe any update on that that you can point to?

Stanley: Sure. So, the Thomas pad wells were 7,500-foot laterals, and the IP-30 on those wells is roughly 800-850 barrels a day on average across all the zones.

The most recent set of wells have not yet hit peak rates. They’re mostly 10,000-foot wells, 9,900-foot wells. 22 of those wells are in a basically a cube of rock that is roughly – it’s 2,500-feet wide, half a mile wide, half a mile tall and two miles long. And there’s 22 well bores in that.

That’s testing what we think is the highest potential density across our acreage, which would be 44 wells per mile. And a couple of things there, one, we’re seeing what we expected, which is delayed cleanup of those wells because of the large volume of fluid we put in the ground.

So, just to give you a little more color around that, each of those wells is receiving about 300,000 barrels of frac fluid and mostly water and sand. And so that 6.6 million barrels of water in that half mile wide by half mile tall cube of rock, that’s 2-miles long.

So, the clean-up times are significantly longer as a result. But we think that by developing a block of rock inside the tank, we’re maximizing the stimulated rock volume, we’re eliminating the parent/child or well – the well interference issues that you observe, if you come back and try to infill acreage.

Ultimately, we think we’re maximizing recovery of oil. So, the cleanup times are protracted. The other thing is because of the total fluid, the total water volume and total frac fluid volume that we need to recover, we’ll see suppressed IPs on these wells relative to a single well or two or three wells that aren’t having to recover the large volume of frac fluid. What we’ve seen in other wells that have been online longer is a shallower, flatter, longer term decline.

So, as we develop more of these blocks, we get more history on them, we’ll share with you individual well performance or cumulative group well performance, but we just don’t at this point have enough history to show you a meaningful data set, statistically meaningful data set on these wells at this point.

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