QEP Resources (QEP) Q3 2018 Results - Earnings Call Transcript

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About: QEP Resources, Inc. (QEP)
by: SA Transcripts

QEP Resources, Inc. (NYSE:QEP) Q3 2018 Earnings Call November 8, 2018 9:00 AM ET

Executives

William I. Kent - QEP Resources, Inc.

Richard J. Doleshek - QEP Resources, Inc.

Charles B. Stanley - QEP Resources, Inc.

Analysts

Kashy Harrison - Simmons Piper Jaffray

Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Timothy Rezvan - Oppenheimer & Co. Inc.

John Nelson - Goldman Sachs & Co. LLC

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Operator

Greetings and welcome to the QEP Resources Third Quarter 2018 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, William Kent, Director of Investor Relations. Please go ahead.

William I. Kent - QEP Resources, Inc.

Thank you, Stacy, and good morning, everyone. Thank you for joining us to the QEP Resources third quarter 2018 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Richard Doleshek, Executive Vice President and Chief Financial Officer; and Jim Torgerson, Executive Vice President and Head of our E&P business.

If you've not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables with our financial results, along with the slide presentation, with maps and other supporting materials.

In today's conference call, we'll use certain non-GAAP measures including EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings, adjusted transportation and processing costs, discretionary cash flow and discretionary cash flow in excess of capital expenditures. These measures are reconciled to the most comparable GAAP measures in the earnings release and SEC filings.

In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control. We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks facing our business in our earnings release and SEC filings.

With that, I'd like to turn the call over to Richard.

Richard J. Doleshek - QEP Resources, Inc.

Hey. Good morning, everyone. On Tuesday, we signed the PSA to sell our Williston Basin assets. So, I'll quickly cover the third quarter results and then Chuck will discuss the transaction and highlight some of our third quarter operating activities. Third quarter was a good quarter for QEP. Adjusted EBITDA was $326 million, which compares to $283 million in the second quarter of 2018 and $193 million in third quarter of 2017.

From an adjusted EBITDA standpoint, this is our best quarter since 2014. Production in the third quarter was 14.4 million barrels of oil equivalent, 294,000 Boes higher than the 14.1 million Boes we reported in the second quarter of the year. Oil volumes were record 6.64 million barrels, up 73,000 barrels from second quarter levels.

Permian Basin oil volumes were a record 3.5 million barrels, up 319,000 barrels from the second quarter, while the Williston Basin oil volumes were 3 million barrels, down 198,000 barrels. Natural gas volumes were 38.1 Bcf, down 0.2 Bcf from the second quarter. NGL volumes were down about 1.1 Bcf from the second quarter. And Uinta Basin volumes were down 1 Bcf from the second quarter, reflective of the divestiture that closed in early September.

NGL volumes were 1.4 million barrels, up about 263,000 barrels from the second quarter. Crude oil comprised 46% of our total equivalent production in the third quarter, which was down slightly from the second quarter of the year, but 12% higher than the third quarter of 2017. We revised our guidance for full-year 2018 production such that the midpoint for oil production is 24 million barrels, 0.5 million barrel increase from our previous guidance. We've revised our gas production guidance down by 2 Bcf as a result of the Uinta Basin divestiture. Recall that the Uinta Basin produced about 3.7 Bcf of gas in the second quarter.

Midpoint for gas production is now 138 Bcf, and we increased the midpoint of NGL guidance to 4.5 million barrels, an increase of 250,000 barrels. QEP Energy's net realized equivalent price, which includes a settlement of our commodity derivatives, averaged $36.21 per Boe in the third quarter, which was $1.67 per Boe higher than we realized in the second quarter and $8.41 per Boe higher than we realized in the third quarter of 2017.

The weighted average field level equivalent price in the third quarter was $38.87 per Boe, which was 3% higher than we realized in the second quarter. The equivalent price reflects field-level crude oil prices that were $62.65 per barrel, natural gas prices that were $2.67 per Mcf, and field-level NGL prices that were $29.65 per barrel. Field-level crude oil revenues account for 74% of total field-level revenues, which was about 3% lower than in the second quarter, but 17% higher than a year ago.

Derivative settlements were an outflow of $38.4 million resulting in a loss of about $2.66 per Boe in the quarter compared to an outflow of $45.6 million or $3.23 per Boe in the second quarter. Combined adjusted operating expense and transportation expense, including $15.8 million of transportation expenses that were netted against revenue, were $108 million in the quarter, down from $110 million in the second quarter and down from $136 million in the third quarter of 2017. On a per unit basis, lease operating expenses were $4.49 per Boe, which is $0.22 per Boe lower than the second quarter.

Transportation expense was $3.04 per Boe, which was down $0.05 per Boe from the second quarter. This is the third quarter in a row in which absolute and per unit operating and transportation expense is lower than the immediately preceding quarter.

Reflective of our success this year in driving down costs in the field, we have lowered our guidance for combined adjusted lease operating and transportation expenses, including the transportation expenses that are netted in revenue, for full year 2018 to a range of $8 to $9 per Boe, the midpoint of which is $0.50 per Boe lower than our previous guidance.

G&A expenses were $48.3 million in the quarter, down $7.5 million from the second quarter. Share-based compensation was down $11 million from the second quarter. Legal and miscellaneous G&A was down $3 million, while outside professional services was up about $4 million. Included in the quarter was $12.8 million of restructuring-related expenses, which compares to $9.5 million in the second quarter. We increased the midpoint of our guidance for G&A expenses for full year 2018 by $5 million, reflective of the additional restructuring expenses we incurred in the third quarter.

For the third quarter, we reported net income of $7 million. Contributing to our net income was $27 million of gain on sales related to the various divestitures that closed in the quarter. In addition, DD&A expense was $7 million lower in the quarter, and the unrealized loss on our derivative portfolio was $36 million higher than in the second quarter, driven by higher forward curves for commodity prices.

Capital expenditures on an accrual basis in the third quarter were $204 million, of which $191 million was directed to the Permian Basin, $7 million to the Williston Basin, and $4 million to Haynesville. In addition, we also reported $3 million of acquisitions in the quarter.

We revised our guidance for capital expenditures, excluding the acquisition and divestiture activity for full-year 2018 from our previous guidance to include additional refrac activity in the Williston Basin, increased outside operating activity in the Williston and Haynesville, and additional put on production wells in the Permian Basin in the fourth quarter of the year, such that the midpoint of the range is now $1.65 billion.

With regard to the balance sheet, at the end of the quarter, total assets were $7.2 billion. Shareholder equity was $3.4 billion. Total debt was approximately $2.475 billion, of which $2.1 billion were our senior notes and $375 million was borrowed under our revolving credit facility. A combination of $169 million of proceeds from the various divestitures and discretionary cash flow in excess of capital expenditures drove the $200 million reduction in debt during the quarter.

I'll now turn the call over to Chuck.

Charles B. Stanley - QEP Resources, Inc.

Thanks, Richard. Good morning, everyone. In late February, we announced that our board of directors approved certain strategic initiatives that are designed to transition QEP to a pure-play Permian Basin oil company. Since that announcement, we've engaged advisors to market our Uinta and Williston Basin assets. We closed on the Uinta Basin assets in early September for net cash proceeds of $153 million that are, of course, subject to post-closing price adjustments. In addition to the Uinta divestiture, through the first nine months of this year, we've also sold noncore assets, primarily located in our northern region for net cash proceeds of approximately $64.5 million.

As I'm sure you saw, yesterday, we announced that we've entered into a definitive agreement to sell our Williston Basin assets for a purchase price of up to $1.725 billion comprised of $1.65 billion of cash, which is subject to purchase price adjustments, plus $50 million of additional consideration, delivered as approximately 4.17 million shares of the purchaser, which is Vantage's common stock, when the daily VWAP of the share price exceeds $12 per share for 10 of 20 consecutive trading days and an additional tranche of $25 million of consideration also delivered as shares that would be 1.67 million shares of purchaser's stock, when the daily VWAP of the share price exceeds $15 per share for 10 of 20 consecutive trading days, that just meets or exceeds the $15 per share price.

We're entitled to the equity consideration if the share price thresholds are met at any time during a five-year period, following the closing of the transaction. Additionally, the transaction is subject to certain conditions, including but not limited to Vantage's shareholders' approval of the transaction and regulatory approvals. The effective date is July 1, 2018 and we anticipate that the transaction should close late in the first quarter of next year or early in the second quarter.

Regarding the Haynesville, in response to inbound inquiries that we received, we entered into confidentiality agreements and we provided data to multiple interested parties who expressed an interest in the assets, and we continue to progress discussions. As we sell assets, we'll use proceeds to fund our ongoing development of our core Permian Basin assets, to pay down debt and to return cash to shareholders through a share repurchase program. By applying proceeds from asset sales and excess cash from operations, our net debt at the end of the third quarter was $2.475 billion compared to $2.675 billion on June 30.

To-date, we've repurchased approximately 6.2 million shares of QEP stock at an average price of $9.37 per share for a total of approximately $58.4 million in share buybacks. The execution of a definitive agreement to sell our Williston Basin assets is another important milestone in simplifying our asset portfolio, as we continue on our path to become a pure-play Permian Basin oil company. Given this significant step, I think it's important to remind you why we've embarked on this strategy.

First, we think for a company our size, being a single-basin producer makes sense because it allows us to focus our technical and our commercial efforts on a single high-return asset, while streamlining our organization to drive down costs and maximize efficiency. Since March, we've already reduced our head count by approximately 30% and we'll continue to right-size the organization as we close on additional asset sales and transition the properties to new owners.

We're convinced that crude oil is the right commodity upon which to focus our efforts. And we think the Permian and, more specifically, the Midland Basin is the ideal place to be. We chose the northern portion of the Permian Basin – of Midland Basin, rather, centered around Martin County, Texas for a number of technical and commercial reasons.

First, the area is a true black oil province with typical post-processing production comprised of about 71%, 39 to 40 API gravity, extremely low sulfur, highly desirable crude oil. In addition to crude oil, condensate averages about 3% of our production stream on an annual basis. Most of it then drop out in our gas gathering systems for a total of approximately 74% oil and condensate in our Permian well stream.

The area that we're focused in contains about 300 million barrels of estimated oil in place per square mile, which is contained in multiple stacked, relatively continuous unconventional reservoir targets that lie in a 2,500-foot thick interval that are really amenable, extremely amenable to long lateral horizontal well manufacturing from large pads using our tank-style development method.

Our assets are also located in an area that has very low structural complexity. There's not a lot of faulting, not a lot of folding, which allows for highly accurate placement of horizontal laterals. Also in our area, we had approximately 2 barrels of water for every barrel of crude oil and condensate production. We think the northern Midland Basin exhibits a relatively low produced water/oil ratio compared to other parts of the Permian, which we believe should help lower operating costs and increase oil recovery over the life of the assets.

We targeted acreage that was configured in large contiguous blocks that maximize horizontal lateral length and that also allow for pad-based development with shared surface infrastructure, including oil and gas gathering and water handling, while facilitating simultaneous development of multiple target horizons in the subsurface.

As you can see on slide 7 and 9 in our current investor presentation that we posted on our website yesterday, we've demonstrated that we can leverage our concentrated footprint to maximize efficiency to drive down costs for new wells and to drive down LOE. We have minimal drilling obligation to hold our leases, which allows us to develop them in an orderly fashion across our entire acreage block, which should maximize efficiency and minimize creation of pressure sinks and parent/child well interference issues inherent in less orderly acreage development.

Finally, the northern Midland Basin in Martin County has well-developed infrastructure, including housing, roads and highways, an electric power grid, existing oil and gas gathering, transmission infrastructure and access via an expanding network of regional pipelines to global crude oil markets via the Gulf Coast.

In summary, we are convinced that we are in the right place and we're on the right path to maximize shareholder value through execution of our strategic initiatives. With the closing of the Uinta transaction, the sale of additional noncore assets, the announced Williston divestiture, and continued progress on our Haynesville/Cotton Valley divesture efforts, we are well on our way to delivering on these initiatives. Slide 5 in our deck summarizes our progress on our strategic initiatives. And slide 6 gives you some of these key attributes that I just went over on our Permian Basin acreage.

Now, let me turn to the third quarter. We're very pleased with the strong results we posted. As we continue our transition to a pure-play Permian Basin oil company, our activity was concentrated on those assets during the quarter. Activity in the basin included four rigs, one completion crew, and there was no drilling or completion or refrac activity in either the Williston Basin or the Haynesville/Cotton Valley during the quarter. You can see a summary of some of our key accomplishments during the third quarter on slide 3 and our updated guidance on slide 4.

In the Permian, our operations team delivered another impressive quarter as they continue to advance our tank-style development. In addition to delivering a new quarterly Permian Basin net production record of 52,100 barrels of oil equivalent per day, which was up 18% from the second quarter, we continue to achieve additional operational efficiencies on both the new well delivery and operations front.

Thanks to ongoing drilling and completion efficiency gains, we put on production a total of 21 gross wells in the Permian during the quarter, all at Mustang Springs, which was four more than we had forecasted last quarter. The 21 wells that we put on production during the quarter were located in three discrete drilling and spacing units, which together represent 1 mile wider, and as we mentioned in our release, we're at variable well densities to honor lease line setback and other constraints as we reached the Western edge of our Mustang Springs block and turned the corner to start back to the east in our tank development front.

Of the 21 wells we put on production, 4 had reached an average peak 24-hour IP of 198 barrels of oil equivalent per 1,000 lateral feet by the end of the quarter, while our remaining 17 were still cleaning up. The increased pace of completed well delivery was a direct result of our continued productivity gains of the frac crew we have working for us. During the quarter, we also completed our transition to full utilization of in-basin sourced proppant, up from about 55% at the end of the second quarter, which should yield a total savings on a 10,000-foot lateral of approximately $300,000 per well compared to the full utilization of outer basin sourced product.

The efficiency gains on drilling and completion of individual wells facilitated by tank-style development, which we're absolutely convinced is the right approach to advance development over our 44,000 net acres in the core Midland Basin. You can see how the continuous improvements in well construction translate into lower drill complete and equip cost per lateral foot and the remarkable efficiency of our completion operations on slide 7.

And on slide 8, you can see our continued progress in driving down Permian Basin lease operating expense as we have acquired new acreage, folded it into our portfolio, driven production growth with new horizontal development wells, plugged lower-rate, higher-LOE vertical wells, and captured operating efficiencies through our infield infrastructure.

At the end of the third quarter of 2018 in the Permian Basin, we had a total of 21 gross operated horizontal wells that were in the process of being drilled. And of that 21, only 13 had only surface casing set, but had no drilling rig present. 16 wells were waiting on completion. 4 wells were undergoing completion by our frac crews. And 7 were fully completed, waiting on production, which were part of what we call our pressure wall in our Mustang Springs tank development program.

In our release yesterday, we also provided an update on 37 wells we placed on production in the second quarter that were in various stages of flowback and cleanup at the end of last quarter. The eight wells that we placed on production in County Line reached an average peak 24-hour IP rate of 150 barrels of oil equivalent per 1,000 lateral feet, and that was comprised of about 82% oil, and an average peak 30-day IP of 138 barrels of oil equivalent per day per 1,000 lateral feet from an average lateral length of 7,244 feet.

At Mustang Springs, the 29 wells achieved average peak 24-hour IPs of 152 barrels of oil equivalent per day per 1,000 feet and average peak 30-day IP of 118 barrels of oil equivalent per day per 1,000 feet from an average lateral length of 7,430 feet. You can see the locations of these wells in the summary results along with other information on our Permian assets on slides 10 through 14 in our slide deck.

One thing I wanted to draw to your attention. You might notice a slight increase in Permian gas volumes during the quarter compared to oil sales. Their slightly higher relative proportion of gas is a direct result of higher gas capture beginning in late August as we completed tie-in work on our gas gathering and compression systems and it's not a reflection of any change in reservoir performance. As a reminder, we may still see some variation in gas capture rate and in fuel gas used going forward, but we think the gas/oil ratios we're reporting should stabilize around the current levels from this quarter.

With the first three quarters of the year in the books, I'd draw your attention to the guidance table that we included in yesterday's release. Thanks to continuous improvements in efficiency of operations, we now expect to complete five more wells and turn three more wells to sales in the fourth quarter of this year than we anticipated last quarter, which should set us up very nicely for the end of this year and to lay a great foundation for 20% to 25% year-over-year oil production growth from our Permian assets in 2019.

In summary, we're extremely pleased with the very strong results and continued operational efficiency gains that we posted across our portfolio in the third quarter, particularly the ongoing cost improvements and outstanding results that we deliver from our core Permian Basin assets. Regarding the strategic initiatives that we announced in February, QEP's board and management remain committed to the strategy of becoming a pure-play Permian Basin oil company.

With the closing of our Uinta Basin divestiture in September, the sale of approximately $64.5 million of additional noncore assets through the end of the third quarter, the entry of a definitive agreement to sell our Williston Basin assets, and continued progress on our Haynesville/Cotton Valley asset divestiture, we are well on our path to delivering on those initiatives.

With that, Stacy, let's open the line for questions.

Question-and-Answer Session

Operator

Thank you. We will now be conducting a question-and-answer session. Our first question comes from Kashy Harrison with Simmons Piper Jaffray. Please go ahead.

Kashy Harrison - Simmons Piper Jaffray

Good morning, everyone, and thanks for taking my question.

Charles B. Stanley - QEP Resources, Inc.

Good morning, Kashy.

Kashy Harrison - Simmons Piper Jaffray

So, Chuck and Richard, you and the team, you're entering the final innings of the portfolio transformation process. Assuming Vantage shareholders approve the Bakken deal and you get your Haynesville transaction through the finish line, you could be flush with a lot of cash. And even after paying down the debt to right-size the balance sheet, you'll probably still have quite a bit of cash remaining, perhaps up to 50% of your market cap.

And so, really, my question is, what's the post-transformation strategy for QEP and all that cash? Are we looking at aggressively buying back shares? Are we thinking about buying more acreage in the Permian to achieve critical mass similar to other SMID names? Or perhaps, are we thinking about merging with other SMID names to build scale or maybe taking the sum-of-the-parts strategies with final conclusion distributing all that cash flow to the shareholders and, perhaps, selling the company for equity in a larger organization? Just some thoughts on what's the next step for QEP.

Charles B. Stanley - QEP Resources, Inc.

Wow, that's the most impressive multipart question, Kashy, that I think I have received in a long time. Let's start sort of from the back and work forward. So, with respect to use of proceeds, as I articulated in my prepared remarks, the sort of merit order of use of cash, fund the ongoing development of our core Permian Basin assets, pay down debt. And when we think about appropriate leverage for a SMID-cap pure-play Permian Basin operator, I think Richard and I would say it's somewhere between 1.5 times and 2 times – 2 times on the high side.

And so, then you can do the subtraction exercise for the remainder, which is using remainder of the cash to opportunistically buy back stock. And of course, this is subject to marketing condition and obviously subject to having cash available to do so. But your math is right. And as you recall, in February, our board authorized a substantial – meaningful share buyback program. We've done a little bit on that, but we're waiting to get cash in the door before we initiate the aggressive share buyback. So, that's the sort of merit order of use of proceeds.

And then, with regard to your question around Permian Basin acreage, we feel like we have, based on sort of core of the core acreage position, a very well-established derisked portfolio of development opportunities that gives us a substantial runway. Are we subscale? We don't think so. We think that you need to think about Permian Basin acreage in the multiple-stacked horizons a little differently than you do single reservoir or two-reservoir play in other basin. So, acreage numbers are somewhat different. And I'm not going to do the X reservoirs times our acreage to tell you what the effective number of acreage are. You can do that math yourself.

But as to scale, we think we have sufficient inventory and sufficient quality of acreage that we don't – haven't felt need to go out and buy additional acreage tomorrow. As for M&A activity, look, larger companies, an investment-grade balance sheet, the flexibility to move around to different parts of the acreage, to maximize operational efficiencies, all of those things are arguments for getting bigger. And M&A transactions to do, that's certainly something that we talk to our board about and it's something that we're open to. So, I think I've covered all the multiple choice questions there. But if I missed any, help me.

Kashy Harrison - Simmons Piper Jaffray

No. You covered all the multiple choice questions, Chuck. And maybe switching gears a little bit from strategy, 2017, exceedingly challenging year on multiple fronts. But 2018, the tank-style appears to be – it's yielding dividends. You guys have been performing extremely well in the Permian. And so, just a question on tank-style in terms of what it does for the recovery factor of the reservoir. So, if standard shale development recovers, let's say, 8% of the resource potential, what do you think the tank-style completion approach does in terms of resource recovery factors?

Charles B. Stanley - QEP Resources, Inc.

Well, intuitively, we think it's more, but I would be speculating wildly at this point to give you a number. Why do we think it's more? Because we think by developing all of the target horizons simultaneously that you maximize the stimulated rock volume inside the tank, which should result in more effective drainage of the oil in place. Is it going to double it? Probably not. But we think that we're going to capture more of the oil in place by simultaneously developing all of the horizons than we would doing single-zone development.

The other problem is, with single-zone development, we think that you run a significant risk of sterilizing or significantly degrading the overlying and underlying horizons by creating pressure sinks and ultimately the dreaded parent/child relationship. And parent/child relationships not only exist in the same horizon laterally, but they also exist vertically through the section by creating pressure sinks and connecting up wells drilled above and below the existing producing horizon. That's what I mean by sterilizing. So, we think that's also an integral part of the tank-style development, is to simultaneously harvest the oil across the entire prospective horizons, which in our area is about 2,500 feet of vertical section.

Kashy Harrison - Simmons Piper Jaffray

Got you. And then just if I can just sneak one last one in there. You're seeing a lot of efficiency on the completions front as highlighted on the page showing the footage, the frac efficiencies in the presentation deck. How should we think about the number of wells per rig per year as we move into 2019 and as we transition to laterals exceeding 9,500 feet?

Charles B. Stanley - QEP Resources, Inc.

So, obviously, we're trying to start thinking about things and talk about things in terms of lateral feet rather than well count, because as you know, Kashy, our initial development was focused – in Mustang Springs was focused almost exclusively on 7,500-foot laterals. Now, we're adding another 2,500 feet to them. So, the absolute well count going into next year will likely go down by 20%, 25%, but we'll be drilling more lateral feet during the year as we drill 10,000-plus-foot laterals across the acreage as we come back from west to east across Mustang Springs and work on the County Line acreage over on the western part of Martin County and eastern Andrews County. So, that's why we presented the statistics on costs and dollars per 1,000 feet, because we're starting to transition our thought process and, obviously, our planning and forecasting process based on lateral feet drilled and completed, and not on absolute well count. Does that help?

Kashy Harrison - Simmons Piper Jaffray

Yeah, that helps a lot. And that's it from me. Congratulations on a strong quarter.

Charles B. Stanley - QEP Resources, Inc.

Thanks, Kashy.

Operator

Our next question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

Good morning, all, and congrats on a strong quarter and update as well.

Charles B. Stanley - QEP Resources, Inc.

Thanks, Derrick.

Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

Chuck, as you step back and assess the progress you've made to date with tank-style development, do you feel like you've locked in all of the optimization variables for both County Line and Mustang Springs at this time? Or said differently, would it be reasonable to assume that you – we're generally in cost optimization mode at present?

Charles B. Stanley - QEP Resources, Inc.

I think at Mustang Springs, because of the well densities we've drilled and because of the sort of continuous data collection and optimization, we're there, we're driving down costs, increasing efficiency. At County Line, we're still working on testing and maximizing, or improving and optimizing well placement within the section, within the vertical targets. But we're well along our way there as well. And we think that as we look at Robertson Ranch – what we call Robertson Ranch, which is morphing over time as we continue to do acreage trades that the Mustang Springs' geologic model is very applicable to the acreage that we acquired to the south that we call Robertson Ranch. So, we should be able to just march across that acreage using the same ultimate tank design that we've perfected at Mustang Springs. So, very well along the way at Mustang Springs, catching up quickly on County Line, and we think the applicability of Mustang Springs is direct to the acreage to the south.

Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

Very good. And as my follow-up, in your press release you noted 40% of the wells put on production in 2018 have laterals of over 10,000 feet. How does that project into 2019?

Charles B. Stanley - QEP Resources, Inc.

I believe it's going to be nearly 100%, 10,000-footer and some actually 12,500 footers in the latter part of the year.

Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

It's very helpful. Thanks for your time, guys.

Charles B. Stanley - QEP Resources, Inc.

Thank you.

Operator

Our next question comes from Neal Dingmann with SunTrust. Please go ahead.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning. Congrats on the sale, Chuck. My question is in the Bakken, you mentioned this a little bit in the prepared remarks. I'm just trying to get a sense of how much activity until you sell this. I think you mentioned a few refracs, and then I think Vantage had mentioned yesterday about possibly bringing a rig in early next year. So, I'm just trying to get a sense of how we should see it, how we should envision activity until the sale?

Charles B. Stanley - QEP Resources, Inc.

Well, we've been talking to Roger and his team about their plans. Obviously, they'd like to get started on drilling and we're working with them on finalizing timing not only on bringing in rig, but also doing some additional refracs. As Richard mentioned in his comments about the capital increase, we've done four refracs. They're actually – the completion work is done. I think that we're in the final stage of drilling out the frac closing those wells, so they'll be coming online shortly. We talked about potentially doing more refracs as well as standing up a rig. And the rig would probably be stood up on the eastern side of South Antelope sometime over year-end, early next year. But we've got to secure a rig first. We've got a location built that we had already built earlier this summer. So, dirt work is already done. So, it's likely to come in over year end or more likely very early next year.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. And then just to make sure I had that right, I know that purchase price was $1.65 billion and there was some ability to receive $50 million to $25 million in stock. And then I guess, by the time it closes – because I know – make sure I've got this right, it's sort of predated, but then if it closes in 2019, you back out the cash flow. I just want to make sure I've got the numbers right there.

Charles B. Stanley - QEP Resources, Inc.

So, effective date of the transaction was July 1. And Richard can walk you through the math there.

Richard J. Doleshek - QEP Resources, Inc.

Yeah. What we get to do is net against the purchase price the cash flows, so it's revenues minus operating expenses, minus CapEx. And we think that that number, as we run to a late first quarter close date's about $0.25 billion of reduction in price. But again, we're capturing those cash flows and getting reimbursed for the capital. So, if we spend $30 million in the fourth quarter on refrac activity, we'll enjoy the benefit of that production in revenue uplift, but we'll also get reimbursed for that capital as well as what we spend in the first quarter on the drilling side. So, think about $0.25 billion with the activity level that Chuck just described with regard to refracs and the rig showing up in the first quarter.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

But that's what I was getting at, Richard you don't basically get the benefit of that until the actual sale, is that right?

Richard J. Doleshek - QEP Resources, Inc.

Yeah. I think if you focus on just the net proceeds at closing, you kind of diminish the value of the transaction. I think the right way to look at it is, $1.725 billion with the July 1 effective date and a July 1 close date, we capture those cash flows. So, the net effect to QEP is the $1.725 billion with the $75 million of equity earn-out.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. And then one last one, if I could. Richard, just looking at slide 11, where you talk about – it shows the cadence there between sort of just for 2018. It looks like obviously since second quarter, you've come down a little bit. Could you maybe – I know you don't have full 2019 out yet, but just maybe talk about 2018, where it looks like the number of POPs were as high as 36 in 2018 going down to 17 this quarter, and maybe how you see that sort of transitioning into 2019 a bit on a broader basis.

Richard J. Doleshek - QEP Resources, Inc.

So, Neal, that feels like a veiled give me 2019 guidance question. But as Chuck suggested, we're trying to get away from thinking about the number of wells completed or even the number of POPs, because POP on a 12,500-foot lateral is equal to almost 2 times a POP on a 7,500-foot lateral. So, yeah, the number of POPs are going down as the lateral length increases. And with regard to the activity level, I think you need to listen to Chuck's comments about 20% to 25% oil production growth from 2018 into 2019. We'll give you guidance when we get there in the first quarter.

Charles B. Stanley - QEP Resources, Inc.

And I think as to this year, to 2018's cadence of well delivery, keep in mind that as we swap from thinking we could operate in two discrete tanks, one in the Spraberrys and one in the Wolfcamp interval, to a single tank. We had more rigs active and we had sort of a slingshot effect as we caught up on completion activity and dropped rigs to get to sort of a stabilized four-rig, one frac crew run rate, which led to a front loading this year, 2018, of completions in the first half of the year. So, as you think about a cadence, without giving anything other than soft guidance, the second two quarters or the last half of the year is a more appropriate sort of cadence going forward with the caveat that I made earlier around completed lateral feet rather than gross wells put on production.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. That helps a lot. Thanks, guys.

Charles B. Stanley - QEP Resources, Inc.

Thank you.

Operator

Our next question comes from Tim Rezvan with Oppenheimer & Company. Please go ahead.

Timothy Rezvan - Oppenheimer & Co. Inc.

Hey. Good morning, folks. I was hoping to pick up on Neal's question on the Permian outlook because you've sort of put some guideposts out there on 2019 with that 20% to 25% growth. If we look at kind of the 2018 CapEx on the DC&E, you're around $850 million. Should we think of that as sort of a baseline then for 2019, or are there a lot of onetime items that you had to spend on in 2018?

Richard J. Doleshek - QEP Resources, Inc.

Well, Tim, it's Richard. Sorry. The $800 million round number spend for Permian included a fairly substantial spend for water infrastructure. Well, that's freshwater salt well – freshwater source wells, saltwater disposal wells water infrastructure that rolls – as we present now, that rolls up into the DC&E buckets. We don't expect that level of spend in 2019 as well as on the gathering side. So, I think, again without trying to give you guidance, that we don't see quite as much infrastructure spend in 2019 as we had in 2018.

Timothy Rezvan - Oppenheimer & Co. Inc.

Okay. Okay. That's helpful. And then, on the asset sale side, thinking about the Haynesville Shale, you had a modest decline in 3Q. It sounds like no activity planned. I mean, how do you think about keeping that production flat, especially from kind of midstream EBITDA outlook as you kind of progress towards a sale? What are your thoughts on that?

Charles B. Stanley - QEP Resources, Inc.

Well, we had no activity in the quarter, in the third quarter, and at this juncture, none planned. We are receiving – Richard mentioned, we had a number of well proposals from offset operators in which we have a working interest that we're participating in. So, that will help some. But obviously, our focus right now is on the transaction. And we hope to be able to get that across the finish line.

Timothy Rezvan - Oppenheimer & Co. Inc.

Okay. Thank you.

Operator

Our next question comes from John Nelson with Goldman Sachs. Please go ahead.

John Nelson - Goldman Sachs & Co. LLC

Good morning, and thank you for taking questions. Congrats on getting those transactions done as well?

Charles B. Stanley - QEP Resources, Inc.

Thank you, John.

John Nelson - Goldman Sachs & Co. LLC

My first question is, I'm just curious NGL guidance sequentially is pointing to be down about 30%. I'm just curious is that because you anticipate some downstream fractionation constraints in the quarter or should we view that as more conservatism?

Richard J. Doleshek - QEP Resources, Inc.

John, I'm sorry, you said we were down sequentially. We're actually raising guidance from where we were in the third quarter. And the NGL side is a little challenging to forecast. Seasonality has a lot to do with the gas capture. When you have higher gas capture, obviously, you have higher NGL recovery. And on a quarter-to-quarter basis, we actually recovered more NGLs in the third quarter than second quarter. And hence, the bump in full-year NGL guidance. So, maybe I misunderstood your question, but I think we actually see rising NGL volumes.

Charles B. Stanley - QEP Resources, Inc.

One of the problems we have, John, just in forecasting NGLs, as you're aware, there's tightness in Belvieu in fractionation capacity, and some of the gas processors that process our gas – we don't have an election on ethane rejection or recovery, and some of them are cutting back on ethane recovery as fractionation capacity fills up. So, we're trying to anticipate some of that. We don't know for sure if it's going to happen, but there's a lot of volatility as we look – have looked historically at ethane recovery on those, what I would call, non-elective gas processing agreements.

John Nelson - Goldman Sachs & Co. LLC

That's helpful. And so, is it fair to say you're not seeing those impacts necessarily today, but because it's kind of what you're seeing in the market, you've just practically baked some conservatism into guidance or are you kind of already seeing that today?

Charles B. Stanley - QEP Resources, Inc.

We haven't seen it, but we suspect we will.

John Nelson - Goldman Sachs & Co. LLC

That's helpful. And is that across both Permian and Bakken, or is it more concentrated in kind of one versus the other?

Charles B. Stanley - QEP Resources, Inc.

It's been mostly in the Bakken. That's where we've seen the variability. In the Permian, it's been more about gas capture. As I mentioned in my prepared remarks, we had a lot of tie-ins during the summer as we continue to finish building out our gas gathering system in Mustang Springs. So, we had a fair amount of flaring that went on as we tied in wells and as we added compression there. Gas capture rates were up in the third quarter and that's one of the reasons why I hammered home the point that nothing's changed in the reservoir, it's just that we're capturing more gas. And with it, obviously, we get more NGLs. We're going to have some tie-in work in the fourth quarter, so we may fall back a bit on our gas capture rate in the Permian. So, that's a little bit of the softness and uncertainty. We just don't know exactly how many days we're going to be down and not capturing the full volume.

So, there's some moving parts there that we're trying to anticipate. But the biggest delta has been in the Williston where we've seen processors swing from ethane rejection to ethane recovery multiple times for various operational reasons as well as, I think, some downstream reasons.

John Nelson - Goldman Sachs & Co. LLC

That's helpful. And then, my second question, as we think about 2019 CapEx levels, do you anticipate to live within cash flow or is the plan to redeploy some of the asset sale proceeds to get back to a higher EBITDA run rate and kind of bringing it back to what is optimal leverage comment from before, if we're – the bogey is 1.5 times to 2 times, I'm just trying to better understand if we're getting there just through straight debt retirement or if there's also some combination of kind of growth that gets you to the optimal level.

Richard J. Doleshek - QEP Resources, Inc.

Yeah, John. I think, again, without giving hard guidance for 2019, I think the goal and what we've tasked the teams to do with their planning for 2019 is to live inside cash flow. Clearly, we'll have cash and we can choose it to deploy that cash, assuming the sale closes, the Williston Basin sale closes. But the guidance to the team as they developed their 2019 budgets is live inside cash flow.

John Nelson - Goldman Sachs & Co. LLC

Perfect. And if I can sneak one more in. Certainly, understand the variation in kind of POPs and not wanting to necessarily – that is not being as indicative as we think about 2019. Would you care to give just ballpark how we should think about net lateral feet increasing year-on-year?

Charles B. Stanley - QEP Resources, Inc.

I don't have that number off the top of my head, but obviously, it's going to go up because we're forecasting sort of 20%, 25% production growth. So, productivity per lateral foot being constant, we're going to put more wells – effective wells on next year. I just don't have the exact number in my head, John. Sorry.

John Nelson - Goldman Sachs & Co. LLC

Fair enough. Worth a shot. Thanks, again, guys, and congrats on getting the Bakken deal done.

Charles B. Stanley - QEP Resources, Inc.

Thanks.

Operator

Our next question comes from Kevin Maccurdy with Heikkinen Energy Advisors. Please go ahead.

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Hey, guys. Just thinking about your acceleration options in the Permian, you have an impressive rig-to-frac crew ratio. But does that mean, to accelerate, you would need to double rigs or is there another option?

Charles B. Stanley - QEP Resources, Inc.

That's a great question. Obviously, what we've done is optimized to the rig count to the frac crew efficiency. If you just add an incremental rig, you don't really do anything other than move the drilled and cased front out – in front of the frac crew. We still have some downtime throughout the quarter with the frac crew. It hasn't run constantly for the full 90 days. So, there's still a little bit of cushion there, but we're probably going to get most of that absorbed just with drilling longer laterals and being able to manufacture more holes, because we're not – obviously, when we're drilling a longer lateral, the lateral drills relatively quick. So, we're not likely to need another rig to keep feeding the frac crew. It probably logically takes a minimum of two additional rigs, 2.5 rigs to start thinking about another frac crew, and it's not full time. So, that's one of the challenges in ramping up, is exactly how you ramp up to maintain the completion efficiencies that we've been able to capture to-date.

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

That's great color. Thanks, guys.

Operator

There are no further questions. I would like to turn the floor over to Chuck for closing comments.

Charles B. Stanley - QEP Resources, Inc.

Thank you very much for dialing in today. Obviously, a great quarter and some significant accomplishments with the closing of our Uinta Basin sale, additional assets that we sold, the entry into definitive agreement to sell our Williston Basin assets and continued progress on our Haynesville divesture. We're well along the pathway that we articulated back in February to becoming a pure-play Permian Basin company.

We certainly appreciate the interest of our investors and patience in us – in our efforts to get to that in state. And I also want to thank our employees for their patience and professionalism as we've transitioned these assets and continue to transition these assets to their new owners.

Thank you all for calling in today. Look forward to seeing you all soon at upcoming conferences.

Operator

This concludes today's teleconference. You may disconnect your lines at this time. And thank you for your participation.