QEP Resources Inc (QEP) Q3 2018 Earnings Conference Call Transcript

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QEP Resources Inc  (NYSE:QEP)
Q3 2018 Earnings Conference Call
Nov. 08, 2018, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

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. (Operator Instructions)

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

William I. KentDirector of Investor Relations

Thank you, Stacey, and good morning, everyone. Thank you for joining us for 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. DoleshekExecutive Vice President and Chief Financial Officer

Hey, good morning, everyone. On Tuesday, we signed a 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 activity. 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 the third quarter of 2017. From an adjusted EBITDA standpoint, this was our best quarter since 2014. Production in the third quarter was 14.4 million barrels of oil equivalent, 294,000 Boe higher than the 14.1 million Boe reported in the second quarter of the year.

Oil volumes were a record 6.64 million barrels, up 73,000 barrels from the 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. Haynesville volumes were down about 1.1 Bcf in 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 2,000 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 fee level revenues, which was about 3% lower than 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 are 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 $0.20 per Boe — $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 cost in the field, we have lowered our guidance for combined adjusted lease operating and transportation expenses including the transportation expenses there net 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 unrealized loss on our derivative portfolio was $36 million higher than 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 acquisition and divestiture activity for full year 2018 from our previous guidance to include additional refrac activity in the Williston Basin, increased outside operated activity in the Williston and Haynesville, additional put on production wells in the Permian Basin in the fourth quarter of the year, such as 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 and 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.

The 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 StanleyChairman of the Board, President, Chief Executive Officer

Thanks, Richard. Good morning, everyone. In late February, we announced 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 non-core 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 had 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 or 20 consecutive trading days, an additional tranche of $25 million under consideration also delivered as shares, that would be 1.67 million shares of the purchasing 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 are entitled to the equity consideration if the share price thresholds are met at anytime during 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 an another important milestone in simplifying our asset portfolio, as we continue on our path to become a pure-play Permian Basin oil company. Given the 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 headcount 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 are 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 — 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 being dropped 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 very 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 a highly accurate placement of horizontal laterals. Also on our area, we had approximately two barrels of water for every barrel of crude oil and condensate production. We think the Northern Midland Basin exhibits a relatively low produced water to oil ratio compared to other parts of the Permian, which we believe should help lower our operating cost 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 they 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 sub-surface. As you can see on Slide 7 and 8 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 cost for new wells and to drive down LOE. We have minimal drilling obligations 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 non-core assets, the announced Williston divestiture and continued progress on our Haynesville Cotton Valley divestiture 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 are 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 with the new well delivering 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 a mile wide area and as we mentioned in our release, were variable well densities to honor lease line setback and other constraints as we reached the Western edge of our Mustang Springs block and turn the corner to start back to the East in our tank development front.

Of the 21 wells we put on production, four had reached an average peak 24 hour IP of 198 barrels of oil equivalent per thousand lateral feet by the end of the quarter, while the remaining 17 we are 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 source profit, 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 source profit.

The efficiency gains on drilling and completion of individual wells facilitated by tank-style development, which we are 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 in into our portfolio, driven production growth with new horizontal development wells, plugged lower rate higher LOE vertical wells and captured operating efficiencies through our in-field 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 awaiting on completion, four wells were undergoing completion by our frac crews and seven 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 we’re in various stages of flowback and clean up at the end of last quarter. They 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 about 82% oil at 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 IPs, 24-hour IPs, of 152 barrels of oil equivalent per day per 1,000 feet at an average peak 30-day IP of 118 barrels of oil equivalent per day per 1,000 feet, from an average lateral length of 7,433.

You can see the location of these wells in the summary results along with other information over 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. There is slightly higher relevant proportion of gas as a direct result of higher gas capture beginning in late August as we completed tie-in work on our gas gathering 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 use 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 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 this year than we had anticipated last quarter, which should serve 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’ve posted across our portfolio in the third quarter. Particularly, the ongoing cost improvements and outstanding results that we delivered 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 additional non-core 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 your path to delivering on those initiatives.

With that, Stacey, let’s open the lines for questions.

Questions and Answers:

Operator

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

Kashy HarrisonSimmons Piper Jaffray — Analyst

Good morning, everyone, and thanks for taking my question. 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 flushed 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 others SMID names to build scale or maybe taking some of the parts strategy through its 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 StanleyChairman of the Board, President, Chief Executive Officer

Well, that’s the most impressive multi-part question, Kashy, that I think I’ve 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 to fund 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 and 2 times, 2 times on the high side. And so then you can do the subtraction exercise for the remainder, which is use the remainder of the cash to opportunistically buyback stock and, of course, that’s subject to marketing conditions and, obviously, subject to our 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 the sort of core, the core acreage position, a very well established derisk the portfolio of development opportunities that gives us a substantial runway. ROE subscale, we don’t think so. We think that you need to think about Permian Basin acreage and the multiple stacked horizons a little differently than you do, a single reservoir or two reservoir play in other basins. So acreage numbers are somewhat different, and I’m not going to do the extra reservoirs times our acreage to tell you what the effective number of acres 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 have felt needed 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 the different parts of the acreage to maximize operational efficiencies, all of those things are arguments for getting bigger. And an M&A transaction is that certainly something that we talk to our Board about and it’s something that we’re open to. So I think I covered off all the multiple choice questions there, but if I missed any, help me.

Kashy HarrisonSimmons Piper Jaffray — Analyst

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 StanleyChairman of the Board, President, Chief Executive Officer

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 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 relationships. And you know parent-child relationships not only exists 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 and 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 horizon, which in our area is about 2,500 ft of vertical section.

Kashy HarrisonSimmons Piper Jaffray — Analyst

Got you. And then just if I could 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.

Charles StanleyChairman of the Board, President, Chief Executive Officer

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 — Mustamg Springs was focused almost exclusively on 7,500 foot laterals. Now we’re adding another 2,500 ft 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 drilled 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 border, western part of Martin County and Eastern Andrews County. So that’s why we presented the statistics on costs and dollars per thousand 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. So, does that help?

Kashy HarrisonSimmons Piper Jaffray — Analyst

Yeah. That helps a lot. And that’s it from me. Congratulations on a strong quarter.

Charles StanleyChairman of the Board, President, Chief Executive Officer

Thanks, Kashy.

Operator

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

Derrick WhitfieldStifel — Analyst

Good morning all and congrats on a strong quarter and update as well. Charles, 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 the optimization variables for both County Line and Mustang Springs at this time or said differently, would it be reasonable to assume that we’re generally in cost optimization mode at present?

Charles StanleyChairman of the Board, President, Chief Executive Officer

I think in Mustang Springs because of the well densities we’ve drilled and because of the sort of continuous data collection optimization, we’re there, we’re driving down cost 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 are well on 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 Roberson 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 of the sale.

Derrick WhitfieldStifel — Analyst

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

Charles StanleyChairman of the Board, President, Chief Executive Officer

I believe it’s going to be nearly 100% 10,000 foot, and some actual 12,500 footers in the latter part of the year.

Derrick WhitfieldStifel — Analyst

It’s very helpful. Thanks for your time guys.

Charles StanleyChairman of the Board, President, Chief Executive Officer

Thank you.

Operator

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

Neal DingmannSunTrust — Analyst

Good morning, congrats on the sale, Chuck. My question is in the Bakken, you mentioned this a little bit in the prepared remarks. I am 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 StanleyChairman of the Board, President, Chief Executive Officer

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 a rig, but also doing some additional refracs, as Richard mentioned in his comments about the capital increase. We’ve done four refracs there, actually the completion work is done. I think that we’re in the stage, bottom stage of drilling out the frac loads in those wells. So they will be coming online shortly. We talk 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, we got to secure a rig first, we’ve got a location built we had already built earlier this summer. So dirt work is already done, so it’s likely to come in over the year end more likely or very early next year.

Neal DingmannSunTrust — Analyst

Okay and then just to make sure I heard that right. I know the purchase price was $1.65 billion and there’s some ability to receive your $50 million there, $25 million in stock, and then I guess by the time it closes, make sure I’ve got this right, it’s a sort of pre-dated. But then if it closes in 2019, you back up the cash flow, I just want to make sure I’ve got the numbers right there.

Charles StanleyChairman of the Board, President, Chief Executive Officer

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

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

Hi, Neal. 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 through a late first quarter close date, about a $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, yeah, we’ll enjoy the benefit of that production and revenue uplift. But we’ll also get reimbursed for that capital as well as what we spent in the first quarter on the drilling side. So think about $25 million with the activity level that Chuck just described with regard to refracs in the rig shown up in the first quarter.

Neal DingmannSunTrust — Analyst

But that’s how it’s getting on, Richard, you won’t basically get the benefit of that until the actual sale then right?

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

I think if you focused on just the net proceeds at closing, you 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 $75 million of equity earn out.

Neal DingmannSunTrust — Analyst

Okay, and then a 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 ’18, it looks like obviously since second quarter you’ve come down a little bit, can you maybe — I know you don’t have full 2019 out yet, but just maybe talk about 2018 or it looks like the number of POPs were as high as 36 and 18 going down to 17 this quarter, and maybe how you see that sort of transition into 2019 a bit on a broader basis.

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

So, Neal, that feels like a, well, 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 two 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 80 to 90. We’ll give you guidance when we get there in the first quarter.

Charles StanleyChairman of the Board, President, Chief Executive Officer

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 Sprayberrys and one in the Wolfcamp interval, it’s 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 the cadence without giving anything other than soft guidance. The second two quarters the last half of the years are 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 DingmannSunTrust — Analyst

Helps a lot. Thanks, guys.

Charles StanleyChairman of the Board, President, Chief Executive Officer

Thank you.

Operator

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

Tim RezvanOppenheimer & Company — Analyst

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

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

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 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 without trying to give you guidance that we don’t see quite as much infrastructure spend in 2019 as we had in 2018.

Tim RezvanOppenheimer & Company — Analyst

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 toward the sale? What are your thoughts on that?

Charles StanleyChairman of the Board, President, Chief Executive Officer

Well, we had no activity in the quarter, in the third quarter. And at this juncture none planned, we are receiving, as Richard mentioned, we’ve had a number of well proposals from offset operators in which we have a working interest that we’re participating in, so that would 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.

Tim RezvanOppenheimer & Company — Analyst

Okay, thank you.

Operator

(Operator Instructions) Our next question comes from John Nelson with Goldman Sachs. Please go ahead.

John NelsonGoldman Sachs & Co. LLC — Analyst

Good morning and thank you for taking my questions. Congrats on the (inaudible) done as well.

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

Thank you, John.

John NelsonGoldman Sachs & Co. LLC — Analyst

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. DoleshekExecutive Vice President and Chief Financial Officer

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 the quarter-to-quarter basis, we actually recovered more NGLs in the third quarter, in the the 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 StanleyChairman of the Board, President, Chief Executive Officer

Oone of the problems we have, John, just in forecasting NGLs, as you’re aware, there’s tightness in Bellevue, 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 what’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 NelsonGoldman Sachs & Co. LLC — Analyst

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

Charles StanleyChairman of the Board, President, Chief Executive Officer

We haven’t seen it but we suspect we will.

John NelsonGoldman Sachs & Co. LLC — Analyst

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

Charles StanleyChairman of the Board, President, Chief Executive Officer

It’s been mostly in the Bakken, that’s where we’re seeing 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 well, and 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 hammering home that nothing’s changed in the reservoir. It’s just that we’re capturing more gas and with that, obviously we get more NGLs. We are 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 this, 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 we’re trying to anticipate but the biggest delta has been in the Williston, where we’ve seen processor swing from ethane rejection to ethane recovery multiple times for various operational reasons as well as I think some downstream reasons.

John NelsonGoldman Sachs & Co. LLC — Analyst

That’s helpful and then for 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 bring it back to the what is optimal leverage comment from before if we’re — the bogey is 1.5 to 2 times. I’m just trying to under 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. DoleshekExecutive Vice President and Chief Financial Officer

Yes, John, I think, again, without giving hard guidance for 2019, I think the goal in 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 to deploy that cash assuming the sale closes, the Williston Basin sale closes, but the guidance to the team as they develop their 2019 budgets is live inside cash flow.

John NelsonGoldman Sachs & Co. LLC — Analyst

Perfect. And if I could sneak one more and certainly understand the variation in kind of POPs and not wanting to necessarily — that was 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 StanleyChairman of the Board, President, Chief Executive Officer

I don’t have that number off the top of my head, but obviously it’s going to go up, because we are 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 NelsonGoldman Sachs & Co. LLC — Analyst

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

Charles StanleyChairman of the Board, President, Chief Executive Officer

Thanks.

Operator

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

Kevin Moreland MaccurdyHeikkinen Energy Advisors LLC — Analyst

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 need to double rigs or is there another option?

Charles StanleyChairman of the Board, President, Chief Executive Officer

That’s a great question. Obviously, what we’ve done is optimize the rig count to the frac crew efficiency. If you add, or 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 had 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 in 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, obviously, when we’re drilling a longer lateral, the lateral drills relatively quick. So we are not likely to need another rig to keep feeding the frac crews. It probably logically takes a minimum of two additional rigs, 2.5 rigs to start thinking about another frac crew and then 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 today.

Kevin Moreland MaccurdyHeikkinen Energy Advisors LLC — Analyst

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 StanleyChairman of the Board, President, Chief Executive Officer

Thank you very much for dialing in today. Obviously, a great quarter and some significant accomplishments with the closing of our Uinta Basin sale, the additional assets that we sold, the entry into a definitive agreement to sell our Williston Basin assets and continued progress on our Haynesville divestiture. 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 also want to thank our employees for their patience and professionalism as we’ve transitioned these assets and continue to transition these assets through 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.

Duration: 50 minutes

Call participants:

William I. KentDirector of Investor Relations

Richard J. DoleshekExecutive Vice President and Chief Financial Officer

Charles StanleyChairman of the Board, President, Chief Executive Officer

Kashy HarrisonSimmons Piper Jaffray — Analyst

Derrick WhitfieldStifel — Analyst

Neal DingmannSunTrust — Analyst

Tim RezvanOppenheimer & Company — Analyst

John NelsonGoldman Sachs & Co. LLC — Analyst

Kevin Moreland MaccurdyHeikkinen Energy Advisors LLC — Analyst

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