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Edited Transcript of WPX earnings conference call or presentation 6-Aug-19 2:00pm GMT

Q2 2019 WPX Energy Inc Earnings Call

Tulsa Aug 8, 2019 (Thomson StreetEvents) -- Edited Transcript of WPX Energy Inc earnings conference call or presentation Tuesday, August 6, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Clay M. Gaspar

WPX Energy, Inc. - President & COO

* David Sullivan

WPX Energy, Inc. - Director of IR

* J. Kevin Vann

WPX Energy, Inc. - Executive VP & CFO

* Richard E. Muncrief

WPX Energy, Inc. - CEO & Chairman of the Board

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Conference Call Participants

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* Asit Kumar Sen

BofA Merrill Lynch, Research Division - Research Analyst

* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* Brian Arthur Singer

Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst

* Brian Kevin Downey

Citigroup Inc, Research Division - Director

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Gail Amanda Nicholson Dodds

Stephens Inc., Research Division - MD & Analyst

* Jeffrey Scott Grampp

Northland Capital Markets, Research Division - MD & Senior Research Analyst

* Kashy Oladipo Harrison

Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P

* Leo Paul Mariani

KeyBanc Capital Markets Inc., Research Division - Analyst

* Michael Dugan Kelly

Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Wei Jiang

Crédit Suisse AG, Research Division - Research Analyst

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Presentation

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Operator [1]

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Good morning. My name is Sylvyne, and I'll be your conference operator today. At this time, I would like to welcome everyone to the WPX Energy Second Quarter Earnings Call. (Operator Instructions) I would now like to turn the conference over to your host, Mr. David Sullivan, Director of Investor Relations. Please go ahead.

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David Sullivan, WPX Energy, Inc. - Director of IR [2]

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Thank you. Good morning, everybody. Welcome to the WPX Energy second quarter 2019 call. We appreciate your interest in WPX Energy. Rick Muncrief, our CEO; Clay Gaspar, our COO; and Kevin Vann, our CFO, will review the prepared slide presentation this morning. Along with Rick, Clay and Kevin, other members of the management team are available for questions after the presentation.

On our website, wpxenergy.com, you will find today's presentation and the press release that was issued after the market closed yesterday. Also, our Q will be filed later today. Please review the forward-looking statement and disclaimer on oil and gas reserves at the end of the presentation. They are important and integral to our remarks, so please review them. So with that, Rick, I'll turn it over to you.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [3]

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Thank you, David. I appreciate everyone who's joining us today. Thank you for your interest in our company, our results and our plans. All of them are coming together quite nicely, just as we've expected. We've wrapped up another strong quarter here at WPX and look forward to visiting with you today.

Everything we're accomplishing starts with our people. They're delivering incredible things, many of which never make a press release, but are essential and foundational to our business nonetheless. Let me give you 2 examples. Up in the Williston Basin, we just celebrated 5 straight years without an employee lost time accident. I've worked out on the front lines and I know first-hand how much there is to manage, not to mention the extreme winter weather that's common in North Dakota.

Congrats to our team up north for staying safe and keeping our operations top tier. That track record has kept a lot of barrels moving and a lot of revenues flowing, especially when you think about the record production volumes we are now producing in the Bakken.

Secondly, out in the Permian, our midstream investments are continuing to pay off in numerous ways as we're rapidly building a solid midstream business with our crude, gas gathering and processing, and our water systems. In early July, we cut our flaring percentage to an all-time low, all the way down to nearly 2.5%. We look forward to even further improvements.

That supports revenues too, but also speaks to how deeply we care about capturing value, doing the right thing and working through whatever challenges come our way. In our case, increasing our gas capture has involved a complex mix of planning, contracts, pipes, processing capacity, a very key partnership and a series of timely strategic investments.

It's certainly paying off, considering the strength of our price realizations in the Permian. That simply didn't happen by accident. It happened because our people got ahead of the game and started assembling the right road map for our volumes.

The same can be said for our Permian technical team as we strive to simply be the best there is amongst some very strong peer companies. That's who we are here at WPX, and it shows in how we get things done. And that's not all, we're working on a lot of things for our shareholders, just like we said we'd do.

Now let's turn to Page 2 and examine our progress. Back in February we discussed our desire to return additional capital to shareholders beginning in 2021. And then in April, after accelerating the monetization of our Oryx system, we said we'd look at the feasibility of adjusting our timetable. All along, we said that could involve continued debt retirements, dividends and/or stock repurchases.

Yesterday, we followed through on our word and announced the decision to implement a share repurchase program. This is the next step in our efforts to return capital to shareholders. As you saw in our news, our Board of Directors has approved a program to buy up to $400 million worth of WPX shares over the next 24 months.

The market's current sentiment about our sector has created favorable circumstances for an action like this, and if the market remains irrational, we will be opportunistic. Doing so will not impact our development cadence in 2020 or our ability to continue to grow production. We are generating free cash flow today, and expect to generate $100 million to $150 million in free cash flow in the back half of the year, which will help support our repurchase program.

The company is showing strength in other key metrics as well. We've increased our cash flow by 48% in the first half of the year, have seen outstanding outcomes in our price realizations in the Permian, received $350 million from the sale of our interest in our Oryx pipeline project and doubled the capacity of our joint venture processing plant in the Permian. And we see more momentum ahead in the next few months. We're raising our full year oil guidance by 4% and our full year volume guidance by 5%, all while keeping our capital plan unchanged. I am very pleased with our execution, our outlook and what we're accomplishing for shareholders. We're confident, bullish and undaunted in our belief in our people, our plans and the future of the company.

Let's turn to Page 3. There's definitely an underlying success story here at WPX that underpins where we're at today. We've made a number of decisions over the past 5 years to transform the company, and none more important than our entry into the Permian Basin. We never doubted the assets for a second or whether we could execute, but doing so put significant pressure on our financial metrics.

But, however, we saw a very compelling course for the company and what it could ultimately allow us to do for shareholders. Today, we're reaping the benefits of acting on those convictions. This slide shows how far we've come once we got the assets in house and started unlocking their potential. Now, tapping all the potential is an ongoing process that continues to this day and it will for some time.

So far we've reduced leverage dramatically, completely turned around our ability to generate free cash flow and sizably increased production in both physical barrels and on a debt-adjusted per share basis. Would I do it all over again? Absolutely. It punctuated our switch from gas to oil and our ability to drive our margins higher. And with that, I'll turn it over to Clay Gaspar, our COO.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [4]

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Thanks, Rick, and good morning, everyone. Yesterday we announced a firm reiteration of our 2019 capital guidance, and at the same time significant performance beats on all of our critical quarterly metrics, and bumped annual guidance on all 3 commodity streams.

We also posted some very impressive price realizations that are the product of years of work focused on staying ahead of the midstream bottlenecks. I've heard our peers talk -- peers talk about the challenges of how this low commodity price environment can be. I can tell you, we consider today's environment mid cycle. Our plan is built on $50 oil. With our assets and with our team, we can do quite well in a $50 to $55 world. We just stay focused on driving our costs [down] (added by company after the call), performance up and ultimately generating full cycle returns to the bottom line.

Since our company-making acquisition of RKI in 2015, we've been working hard to get our balance sheet rock solid and then make the very significant turn to generate free cash flow. As Rick said, we are there now. This is a major milestone for WPX and we're incredibly proud of this achievement.

Now let's turn to Slide 5 and talk about how we are creating value from our groundbreaking Pecos State project.

On the third quarter call last year, I discussed the technical work we're doing in the Pecos State pad in the Delaware. You might recall, I described it as one of the most successful tests I've ever seen in creating real-time tangible value. Just to remind everyone, on this 6 well pad, which included the Upper and Lower Wolfcamp A and the X/Y interval, we utilized fiberoptics, microseismic, chemical tracers, geophones and external temperature and pressure gauges, which allowed us to monitor the effectiveness of our stimulation in real time and watch how the changes in the frac design impacted each perforation along the lateral, ultimately leading us to more effective frac designs. Also, we've continued to monitor the production of these wells to further understand the impacts of the design changes. In the case of the well with the fiberoptic cable, we're still continuously watching the pressure and temperature for every inch of that lateral.

The learnings from this project have significantly contributed to the 22% reduction in Delaware costs. We've also been able to apply some of the changes to the Williston Basin. The Minot Grady and the Delores are the first 2 Williston pads which have incorporated the learnings from the Pecos State to the Williston Basin. We've been able to lower well costs and improve early time production.

I'll be talking more about the Minot Grady in more detail in a few slides. During the quarter, we took a 1,200-foot core in the Third Bone Spring interval in the Stateline. This now gives us over 2,000 feet of core in the Stateline from the base of the Second Bone Spring to the base of the Wolfcamp B. These cores are giving us invaluable data, which allows us to target the optimal landing zones, development cadence and horizontal and vertical spacing as we develop this vast world-class resource.

I should also point out that the improvements in well costs and drilling times are not theoretical or projections. These are actual costs that include drilling, completion, facilities, artificial lift as well as any trouble time that these wells experienced.

The drilling times are averages from spud to rig release and also include any associated trouble time. This is not the best of or just record wells; these are averages that include all the wells for these periods. While these improvements are very impressive, we believe we have more to come in the coming quarters and years ahead.

Now let's turn to Slide 6, and talk about the 2019 Delaware activity. This slide is a summary of our activity comparing the first half to the second half of the year. Remember, we entered the year with 7 rigs running in the Delaware and dropped 2 rigs during the first quarter to average about 5.6 rigs for the first half of the year.

The second half of the year, we will continue to hold 5 rigs flat. For the first half, we benefited from higher average rig count and efficiency gains and put 47 gross wells on first sales. We spread out our locations to better understand the inventory quality and to meet some CDC obligations. We also landed in 8 different landing zones in the first half of the year.

In the second half, we will be putting 31 gross wells on sales with over 2/3 of our -- of those in the core Stateline acreage position, with 100% of the first sales coming from the Third Bone Spring or the Upper Wolfcamp.

The more focused second half of the year will yield more predictable development-type activity and will also drive lower LOE costs by predictable and lower water costs.

Let's turn to Slide 7, and I'll discuss Delaware realizations. We've been publicly discussing the importance of our midstream and marketing strategy in the Delaware for 2 years, and quietly working on it a year ahead of that. On the second quarter 2017 earnings call, I presented a slide titled "Staying Ahead and Securing Infrastructure in the Delaware." It spelled out our basic strategy on oil, gas and NGLs for the gathering, regional and end markets. It didn't get much airtime on the call, but it is the foundation of our price realizations today.

Everything from our takeaway capacity -- excuse me, takeaway agreements with Atmos, WhiteWater and Oryx to our buy/sell agreements out of Midland and our catalyst JV with Howard Energy Partners are all important components to a much bigger strategy to avoid bottlenecks and create value where we are able to identify pinch points in the system way ahead of the market.

As you can see in the realized prices we received for oil and natural gas in the Delaware, they both exceeded WTI and NYMEX for the quarter. On the oil side, we received $60.12 per barrel including basis swaps. As we mentioned in the previous call, our capacity on Gray Oak comes on later this year. It will allow us to get our barrels to Corpus Christi and realize international pricing, which could further enhance our oil realizations.

Our realized natural gas price was $2.04 including basis swaps. When you include the positive impact of commodity management of $0.95, our total realized price for the quarter is $2.99. This is despite Waha gas being worthless -- basically worthless during the quarter. The positive impact of commodity management relates to the physical hedge we have on our Atmos transport to offset the dedication to sell some of the gas into Waha through February 1, 2020.

Our excess transport on Atmos allows us to purchase gas at Waha prices and then ship that gas to receive Gulf Coast prices.

Realizing $60 and $3 in this environment is a pretty impressive print, and reflects the hard work and forward thinking of our midstream and marketing team. We've created very significant value in the monetizations of some of these assets, and they are still creating value through superior price realizations going forward.

Now let's turn to Slide 8, and I'll provide some updates on the Williston Basin. Williston continues to exceed our own high expectations. As I discussed on our last call, we slowed down our activity in the basin late in the first quarter due to some extreme weather and safety concerns related to that weather. I said at that time Williston would decline in the second quarter, but I was confident that it would quickly get back on track. As it's worked out, the team has significantly recovered from the second quarter production slowdown and will show a very impressive rebound in the third quarter.

I'm happy to report that we've met and continue to meet the North Dakota Industrial Commission gas capture rules every month since it's been in place.

This year, we've captured over 90% every month. As the NDIC ramps the gas capture requirements next year to 91%, we're confident in our ability to stay compliant and not be production-constrained.

The Minot Grady and Delores Sand pads are 2 recent examples of why my confidence regarding Williston's getting back on track was so high. Both these pads are exceeding our initial type curve and the Minot Grady HY set a company daily production record of 5,862 barrels of oil equivalent per day, with nearly 5,000 of those barrels being oil.

The Minot Grady and Delores Sand pads were the first wells using the modified completion designs from the technical work we did in the Pecos State pad in the Delaware. We continue to drive costs down, productivity up, and this is just old-fashioned value creation. Now let me turn it to Kevin for his CFO update. Kevin?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [5]

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Thank you, Clay, and thank you to your entire team for producing the results that are driving free cash flow, which enables us to accelerate a return of value to our shareholders. From those of us here in Tulsa to those in the field who are on the front lines making it happen every day, to our midstream and marketing teams who are leading the industry and optimizing the realized prices on what we produce and sell, you give me options that a lot of CFOs don't have.

The WPX team understands the need to execute in a disciplined fashion, always with an eye on value creation and being opportunistic when the markets give us the chance to do so.

That spirit of exploring for opportunities has really made us who we are today, from the timely entry into the Delaware to our midstream partnership and our marketing strategy around oil and gas. Now we are going to take advantage of an irrational market.

As Rick indicated earlier, our leverage was at nearly 4.5 turns in 2016. Now our trajectory by the end of this year puts us below 1.5 turns. In 2016 we were outspending our operating cash flows by nearly $200 million and our trajectory this year puts us at $100 million of cash flow above our capital spend.

We, as a company, know how to take advantage of the market conditions and to manage the risks to continue this trajectory for years to come.

Now let's turn to Slide 10. Our capital spending is exactly where we communicated it would be halfway through the year. We had indicated initially that approximately 55% of our capital would occur in the first half of the year as we were transitioning from a higher rig count in 2018 to our current level.

As you all know, our activity in spending is not a linear formula across every month of the year and can be a little higher or lower from month-to-month depending on how wells fall within that particular quarter. So for the full year, our capital guidance remains unchanged at $1.1 billion to $1.275 billion. Further, we expect approximately $260 million to $275 million of the remaining activity to occur during the third quarter and $260 million to $270 million in the fourth.

Now as far as full year production guidance, we expect full year total production of 160,000 to 165,000 barrels of oil equivalent per day, up from the original 149,000 to 161,000 per day or 5% increase midpoint to midpoint.

We're also raising our full year oil guidance -- production guidance to 101,000 to 103,000 barrels per day, up from the previous 96,000 to 100,000 per day. As Clay mentioned earlier, our third quarter production is already trending materially above our initial expectations as many of the wells that were completed late in the second quarter or early in July come online. This level would moderate slightly as we get into the winter months.

Turning to Slide 11. For the quarter, we are reporting oil production of nearly 98,000 barrels per day, which is 21% higher than the second quarter of last year. Both basins drove this increase from last year; however, our sequential quarterly growth from the first quarter was driven by the Delaware.

Natural gas volumes were 35% higher than last year and were primarily driven by the Delaware, as Clay -- and as Clay discussed, our cash realizations on both oil and gas were industry-leading.

Our second quarter NGL production was 46% higher, again driven by the Delaware. Our realizations per barrel were impacted by higher-than-planned ethane recoveries, which also drove volumes higher.

For the second quarter, we are reporting an adjusted EBITDAX of $339 million, which is $51 million higher than the second quarter of the prior year. This increase is primarily driven by higher oil revenues. With the higher volumes from the 21% increase, we realized $99 million in higher oil sales. However, with the quarter-over-quarter decrease in oil price, revenues were negatively impacted by $55 million.

Lease operating expenses were higher than last year, primarily resulting from higher volumes, but also from an increase in water handling costs as we drilled in some fairly remote areas in the Williston. In addition, we incurred some unplanned workover expenses related to electrical service interruptions in the Delaware.

For the quarter, we are reporting adjusted net income of $37 million versus $23 million in 2018. The improvement was driven by the same factors impacting adjusted EBITDAX; however, our DD&A was $24 million higher than last year and was driven by our increased production volumes.

Despite this absolute increase, our DD&A rate improved by a little over $2 per barrel as we continue to drill better wells at lower cost. Capital -- our capital expenditures incurred for the second quarter totaled $341 million versus $355 million last year. Our second quarter activity reflects a $42 million increase in in-process development activities, primarily driven by the timing of 24 wells that went on first sales in July, which again is driving our current production rate as well as some midstream spend that allows us to get ahead of our development activity in the back half of the year. As I mentioned earlier, this is exactly where we thought we'd be on capital for the first 6 months of the year.

From the CFO seat, we had a very solid quarter, and we are nearly cash -- and we are nearly cash flow positive for the period. As you think about our current production rate, the way we are executing operationally and how we are managing the commodity risk and optimizing our price realizations, it's hard not to be excited as we transition to generating excess cash flow and beginning -- begin returning some of that back to our shareholders.

Returning value to our shareholders starts with this repurchase program due to our view that buying our stock currently represents substantial value. But we will consider other forms of capital return in the future if we determine them to be effective methods of driving stockholder value.

With that, I'll turn it back to Rick for some closing comments.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [6]

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Thank you, Kevin. You know, I can't think of another time when WPX has been better positioned financially or strategically. We plan to remain opportunistic as we continue to shape a company that is known for generating healthy margins, attractive returns and flexing our creative muscles. And you can see all of this in our discipline, our execution, how we protect pricing for our production and how we're returning capital to shareholders ahead of schedule. WPX has never been content with the status quo and we never will. We've come this far by taking advantage of times where market conditions unwittingly worked in our favor.

Where others see challenges, we see opportunity and it's how we keep creating value. Now at this time we can open the lines for questions, and I'll turn it back to the operator.

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Questions and Answers

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Operator [1]

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(Operator Instructions) The first question comes from the line of Asit Sen with Bank of America Merrill Lynch.

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Asit Kumar Sen, BofA Merrill Lynch, Research Division - Research Analyst [2]

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I have one for Clay, and then one for Rick. Clay, Williston Basin has been somewhat lumpy this year. As we think about 2020, should we expect a much more level-loaded program? And also any early thoughts on completion cadence in Delaware next year?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [3]

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Yes, so the lumpiness of Williston. It's interesting, as you look back -- and I think I referenced this 2 or 3 quarters ago -- if you look back probably the last 10 quarters, WPX posted a big gain one quarter, production gain, and then it's kind of a mild gain the next, and then a big one and then a mild. We only had once where that cadence fell out and we had 2 kind of mild gains, I think first -- fourth quarter to first quarter, first to second because of the Williston slowdown in completion activity related to some winter weather.

If you take that one anomaly out, you basically have a big quarter and then a quieter quarter. In the background, Permian is just steadily increasing every quarter, okay? Every quarter, every quarter. Williston comes in with a big splashy pad, really drives the numbers, and then it kind of is quiet the next quarter. So I think what we're seeing this quarter, we are talking about kind of a relatively mild quarter for second quarter for Williston, big quarter in the third, relatively mild quarter in the fourth. I think it stays with the same cadence. I think as long as we are running 3 rigs, as long as we're drilling these super high-quality wells, that's just kind of what gives -- what Williston gives to the bottom line of the company.

I'm sorry, your second question for me or that was a part B of the first question?

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Asit Kumar Sen, BofA Merrill Lynch, Research Division - Research Analyst [4]

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No. It's just the completion cadence in the Delaware for next year, you kind of answered that.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [5]

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Okay. Yes. On the Delaware side, it's kind of steady. You have the economies of scale, 5 rigs running is probably relatively low end of where we've been in the last 18 months. But even with that, we're steadily running 1 frac crew, and then at times a spot second frac crew to kind of catch us up. But it's a little bit more predictable quarter-to-quarter.

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Asit Kumar Sen, BofA Merrill Lynch, Research Division - Research Analyst [6]

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Great. So Rick, you mentioned multiple times, and in the press release as well, if the market remains irrational, you will be -- you will become more opportunistic. Could you elaborate your thoughts on the irrationality as you see it? Based on your track record, your experience with multiple cycles, your conversation with current investors, what is the market missing, in your mind?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [7]

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Well, I think irrationality, in my mind, is when we haven't reported a good quarter yet but some of your peers report maybe some less than favorable results, and you see your equity trade down dramatically. And when that happens time and time again and there's really no basis for your performance to tie to that, we think that that's -- that sets up a great opportunity and -- for us. And so we will be rational in our thinking and address that.

I think the market is missing several things. If you look at our oil growth, we've actually doubled our oil growth in the Bakken and the Permian Basins in the last 24 months. I think that execution has been top-tier. And then you think about the balance sheet improvement through the creativity of our teams here. So I think that just a fundamental, really, lapse in judgment, if you will, in the market. And I don't want to be overly harsh, but we just think it sets us up real nicely and so we are prepared to take full advantage of that.

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Operator [8]

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Your next question comes from the line of Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [9]

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Congrats on your strong quarter and update. Perhaps for Clay, I know you referenced steady growth for the Delaware in your earlier comments just now. However, when I think about Slide 6, to me it would seem fair to say that your capital efficiency should materially improve in the second half as your completions shift to more oil prolific formations in the Third Bone Spring and Upper Wolfcamp intervals. Is that a fair assumption?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [10]

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Yes, Derrick. Yes, I would say -- you know, what I was talking about is kind of little bit more historic in the prior question, thinking about kind of the big quarter, quiet quarter of cadence that we've had. That's really on the Williston side. Permian is nice and steady quarter-to-quarter adds, every quarter it's improved, short of one, I think fourth to the first quarter this year. I think you will see that continue to ramp. Two things are happening in the Delaware. One, what you're talking about, the quality of assets moving more into development mode right in the middle of Stateline. The second thing is we're benefiting from a flatter base decline in both Williston and in Permian, but especially in the Permian side, as we've seen this tremendous growth that Rick just referenced. Obviously, the flip side of that is a significant base decline. That's not -- it's not a bad thing, it's just kind of a factual basis of the shape of the type curve of these kind of wells from resource plays. But what happens in year 2 and year 3 as these things materially flatten, you're building off of a flatter base decline, and so your growth continues to improve year-over-year right along with your capital efficiency from drilling these better and better wells. So yes, I'm very bullish on where we're headed on the Delaware side.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [11]

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Very helpful. And then staying on the Delaware, given the increased attention on spacing and parent-child issues, how would you characterize your approach to co-development in the second half?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [12]

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Yes. We are unwavering in our opinion that co-development is the right approach. I'd say all of our peers are at different stages. I think we are probably a little further along than most. We -- I'll reference back Section 22 that we talked about, it must have been 2.5 years ago that we were talking about the first fully developed spacing test. We've tested tight, we've tested loose. On purpose, we've tested places where it's going to be too tight of spacing. You have to cross the line to know where the line is. We're not ashamed to say that. What we're chasing now and really excited about with the amazing amount of inventory we have, you can think about things like not just maximizing PV-10, because you may get more inventory but you may push yourself into lower returning wells, but pushing that into higher returning wells, thinking about the spacing that really drives significant bottom line -- full cycle returns to the corporate bottom line. So in today's commodity price, with that kind of value creation mindset, things continue to evolve. On the contrary, that is decreasing well costs -- man, sand costs, all these things, very significant components. But we think the most important is the number of landing zones, the thickness of the interval, the timing in which the revisits happen, because you can't develop all of this in one visit. If you wait too long to come back, that well interference from that prior test can negatively impact your second visit. So we're very thoughtful about that as well. Much more to come on this, but we are excited about our understanding and how we're driving value to the bottom line and an amazing amount of quality inventory.

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Operator [13]

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Your next question comes from the line of Mike Kelly with Seaport.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [14]

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Great quarter. Rick, I was hoping to kind of check in on your 2020 priorities. So just hoping maybe you could discuss the strategy headed into next year, maybe just give us an idea -- a ballpark idea of how you're thinking about growth and the general activity levels?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [15]

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You bet. Mike, I think that growth is still going to be important. We're going to be working on our -- finalized our 2020 plan. Every year we have a strategy session in September with our Board, and we pressure test all of our assumptions. We try to stay current on the -- all the data that we can get our hands on and all the perspectives we can get our hands on. And then we'll be ready to roll out, toward year-end, a final 2020 plan. But we think that growth is still very important. We think that generating free cash is very important. And so those really are the 2 foundations -- foundational things if you -- from a platform perspective if you think about it that way.

We want to make sure that we maintain a strong balance sheet, and so I think as we look at the second half, and Clay and Kevin have talked about our results, we've got a lot of momentum in the second half of this year, and I think it's going to really bode well for 2020. And so we feel really nice about how it's setting up for us.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [16]

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Great. Appreciate that. And if I flip over to the Bakken, Clay, just be curious in your thoughts here? I think last year, the market maybe concerned that your North Sunday Island wells, while spectacular, weren't going to be repeatable. And you've kind of answered the call here with the Minot Grady Delores Sand looking as good, if not better. Just curious on if you think that's kind of the new base case going forward, if you have running room in inventory that can look as good as what you put up this quarter?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [17]

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Mike, I know it's a setup question, and Rick's giving me the eye. We've had this call -- this question on this call a number of times over the years. How far are we going to push our type curve for Williston? We're going to hold this at the 1 million barrel mark that we have today. We think in type curves as kind of the next couple of years or so of inventory what we can repeatably deliver. And knowing that stuff happens, we have operational upsets, the reality of weather or whatever comes our way, we want to be able to make sure we can deliver for that. I'm as excited as anyone else on the well performance. There's some real questions as we stepped away from the North Sunday Island epicenter of the Williston Basin. Can we continue to deliver these well results? The team has stepped up. The completion guys have been very creative. As I mentioned, we're bringing in ideas. We're not ashamed to look across the fence and learn from our peers. We look from other basins. Anything and everything is fair game. Therefore, the performance has been great. Also, I'll point out that sub-$7 million well cost fully baked. On the reservation, a lot of my peers are kind of throwing in the towel and don't want to fight the good fight to work on the reservation.

I think that is pretty industry-leading. So we're pretty excited about where we're at. I think it's repeatable going forward. I would still hesitate to shift your type curve up to any group of wells, subset of wells, but we hope to continue to consistently deliver and beat on our type curve expectations.

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Operator [18]

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Your next question comes from the line of Brian Downey with Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [19]

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Nice quarter. I noticed on Slide 5 that the Delaware well costs are down 22% from 2018 average levels, which I believe is a 5% greater decline than was shown in last quarter's deck. Could you give any additional color on what's driving that incremental cost decrease and any additional runway you see on efficiencies on well cost reductions throughout the rest of this year?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [20]

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Yes. Happy to talk about it. Again, that's a 2 mile lateral, including drilling, completions, facilities, artificial lift, and if -- this is look-back numbers, these are actuals, so it includes any kind of issues we might have had with the wells. Sometimes industry tends to talk in, "If everything goes right, we could drill a well for..." That's not this kind of well. This is look back numbers. That 22%, I think the stimulation design is a big component of it. Changes we've made -- I won't go into the details, give all of our secrets away, but I can tell you, some of the design changes that we've made, we're effectively stimulating the entire lateral and doing it in a much more efficient, cost-effective manner. That's the real trick of the trade. I'll also point out the bottom right of the slide shows our improvement in drilling times. Drilling is directly -- the drilling cost is directly proportional to the drilling time. So we tend to use that as a proxy for efficiently getting the well placed in the right position safely. And if we can do that in a quick manner, we're usually money ahead. The drilling team has done a phenomenal job. And again, it's not just a best-of, a one-off well. Our drilling manager here is a repeatable consistent results kind of guy. And he wants to see that average move down consistently over time. And I think that's the right approach. I think you see it yield in the results in these kind of look-back numbers. More to come on that, by the way.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [21]

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Got it. And then going back to Slide 6 and then Derrick's prior co-development question, with Delaware first sales activity concentrated in the Upper Wolfcamp during the second half of the year, directionally how should we think about that mix shift shifting into 2020, if any?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [22]

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No. I think we'll -- I mean, Stateline, let's just be honest, that is our -- the epicenter of our activity. The addition of the Third Bone Spring inventory, as that inventory matures, we learn more about landing zones. We've tested at least 2 landing zones in the Third Bone Spring, sand -- excuse me, in the Third Bone Spring lime today. We've -- both have been very productive. Both have had very competitive individual well returns with the best of the Wolfcamp A. So that's very encouraging for us. What we don't know yet, and we're working on, is how many ultimate landing zones do we have? What's the spacing for it? How do we go in and co-develop? We have very, very good, strong belief that this is an independent flow unit from the Upper Wolfcamp. So what that means is we can go in and individually -- independently develop that and not feel obligated to do it at the same time as the Wolfcamp A. It's very important because we want to go in -- with 5 rigs, we're kind of having to take basically the small of bite as we can. Sometimes 2, as many as 5 or 6 wells. You hit that with a rig, get the rig out of the way, get the completion crew in, get those wells online and then bring the rig back in and do it again. With the Third Bone Spring, as it matures and really falls under the full development queue, we'll have another ability to go in and then plow that down for hugely productive, again, bottom line, full cycle returns.

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Operator [23]

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Your next question comes from the line of Brian Singer with Goldman Sachs.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [24]

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Question on the free cash flow and how that relates to the pace of the share repurchase as we go forward into next year. Do you expect to fund the share repurchase solely from free cash flow and if you don't see it you would wait on the buyback, or would you use the recently strengthened balance sheet from asset sales as -- are you willing to use that in part in addition to free cash flow to meet the buyback expectations?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [25]

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Brian, this is Kevin. The buyback will primarily be funded by our free cash flow. I think as you think about the timing of working capital changes in the back half of this year, with crude settlements occurring kind of later in the month, you may see a little -- from time to time, us use a little bit of the revolver in order to be able to do so. But the intent is we're going to be using our free cash flow in order to buy back those shares. And as you project into 2020, I think if you were to look at the consensus, most of the consensus estimates out there are projecting pretty good free cash flow from our portfolio next year. Obviously, as Rick mentioned, we still have some work to do with our Board and then our September strategy session about what 2020 actually looks like. But with the portfolio that we have and the trajectory that we're on and the well results we're seeing, most of the program is really just going to be funded with our free cash flow. I think, as we mentioned earlier, whenever we did our Oryx monetization and our WhiteWater monetizations of our equity investments there, is it might accelerate it. And really what this does -- what those did was, it created that kind of balance sheet support, as we were projecting our leverage for the balance of this year and our leverage for next year, to be able to do so. Now one thing you will see is, as we start to buy back in these shares, we're going to adjust our hedge book in order to -- again, as Clay mentioned, we plan at $50, strip's a little bit above $50, and we can maintain a really, really healthy balance sheet profile with the little bit of additional hedges as we start executing on this program.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [26]

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Great. And then my follow-up is, you highlighted the disconnect that you see in terms of how the market and how investors are looking at WPX. Are you seeing a disconnect elsewhere on an asset or corporate level that would pique your interest from a consolidation perspective, or is the buyback here a signal that you're solely focused on the free cash flow and buyback capabilities at WPX?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [27]

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Yes. Brian, I think our priority is -- and I answered this question on the last quarterly call -- we're focused on ourselves right now. We've got -- when you know the assets you have better than anybody else, that's what's giving us the confidence in what we're doing. You see crude price is hanging in there pretty well, and yet you see the equity valuations just totally disconnecting from that. And that gives us the confidence to do what we're doing. And you're right, I think you're seeing sort of the multiple compression in companies in the sector is really overdone, I think. And so there may be some things out there that look kind of interesting. The bottom line is, we're really focused on ourselves. And I can tell you, if you could be part of the conversation Clay and his team were having with some of our neighbors down in the Delaware on putting these 2-mile units together, we have checkerboard positions, and the return enhancements we see from that, that's really where more of our priority is right now.

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Operator [28]

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Your next question comes from the line of Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [29]

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Great details today. My question maybe, Rick, for you or Clay or even Kevin, when you guys think about these days, the pad size versus tying up -- I'm just wondering how you view that versus tying up the capital and potential efficiency behind that? I mean, there is obviously a couple of rules -- ways to think about that, but I'm just wondering, you kind of test it a bit different, but I'm just wondering how you think about if you would even venture to even a larger size pad these days?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [30]

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Neal, I think it's an interesting balance. We have a guy in our organization, his title is Director of Subsurface for the Delaware Basin. And his world is everyday trying to crack that code and optimize that scenario. Sometimes we've given him 5 rigs to run with and sometimes it's 7, and sometimes it's more than that. But I think balancing land requirements, making sure we check all of those boxes, understanding the different parts of our geography, we still have some parts of the basin that are little bit further removed in the Stateline. We have to understand those and figure out when they fall into the mix. And then thinking about the flow units, and very importantly, not partially developing a flow unit and leaving a negative path behind you, if you know what I mean. If we -- so you just developed the Upper Wolfcamp A, plow it down, then you come back in a year later and try and do the Lower Wolfcamp A, guess what? It's not there anymore. You have ruined that interval. So that's a big part of the motivation. As I mentioned earlier, we're trying to kind of take the minimum bite that we can in a kind of a vertical slice, so we might hit an X/Y Upper A, Lower A, even a B sometimes. Those would be 4 wells. And then get that rig or 2 out of the way and then go in and complete them, and then come back in 6 months later, do it again and again and again. As we scale up rigs over time, years from now, we'll be able to take bigger bites. I think you have more cost efficiency, each move that you avoid is efficiency gained. The are efficiencies of being able to scale the completions, getting that the frac crew on location and completing more wells. Your facility's efficiencies come along with that. But then there's another side of that coin where if you bring on too many wells at one time, the requirement for facilities and pipe and infrastructure can be incredibly big, and that can kind of get to be the flip side of efficiency and actually cost you more in the end.

So there's kind of a sweet spot in there. I would say anywhere from 3 rigs -- excuse me, 3 wells to 10 wells per visit, probably, as we see it today, is the right approach per visit. And then importantly, you got to get back to it pretty quick. Can't let that sit for a year or 2 before you go back. You will have some really, really bad awareness when you come back to visit.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [31]

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It's great details, because that leads me to related follow-up. You mentioned about sort of pushing the boundaries when it comes to spacing. And it sounds like just on the -- what you're just telling me here is you sort of have done the same now as it pertains to formation? So is -- are you sort of at the point now that you feel good? Or are you going to continue sort of push those boundaries a bit more? Or are you already there and it's going to be more pure developmental when you look at sort of 2020 and beyond?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [32]

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We are moving to more and more full development mode. Now on your first point, do we have the final recipe on exact spacing and how many wells and all that stuff? No, because what happens is, as soon as you get a $5 shift or $10 shift in commodity price, everything changes. Well cost changes. Local sand versus importing sand, everything changes. And so we're very attuned to that and we're self-aware enough to know that we're never going to have the final answer. We're always working towards that right approach. But it's a bit elusive and you never quite reach it. But I'm really proud of the work that the team has done. The core that we've taken, the Pecos project that was taken, the spacing test that we have in the ground and we've been able to watch for a couple of years. There's nothing like comparable data to tell you what really works and what really doesn't. And so all of that is very incredibly important for us to work towards that, the "right" solution.

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Operator [33]

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Your next question comes from the line of Brad Heffern with RBC.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [34]

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Question on midstream. So I think in the past, you've talked about the success that you've had has led to potential partners coming to you with new opportunities that you might have not seen before. I'm curious if you're still seeing that kind of activity? If you think that midstream investment is attractive at this point, or if the repurchase program sort of supersedes that?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [35]

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Yes. Brad, I think the questions have evolved, but the questions keep coming. Everything from exporting oil along the Gulf Coast, how that functionally works, where does the oil go, we're in those conversations. Now let me be clear, we're not building ports on our own or anything along those lines, but it's interesting and very humbling to have some of these supermajors and other world leaders in that space call up little old WPX and want our opinion on some of that. So very flattered to be part of those conversations and always have an eye for how do we create value for our own shareholders in those conversations. Rewind all the way back up to right in the middle of Stateline and in the heart of the basin. The water discussions are fast and furious. You can bet we have call -- had a call yesterday just inquiring about what our plans are. And we're very opportunistic. We watch these things and look for how do we create the most value, at the same time, most importantly, protect that upstream E&P business, because you could do something really flashy and cash in some money on one of these deals and really live to regret it quarter after quarter after quarter if that counterparty is not performing. So we're pretty selective in those kind of marriage-type proposals, but we are always looking and creative and very, very proud of how we see what others may perceive as challenges as sheer opportunities to create incremental value.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [36]

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Brad, this is Rick. I'll interject. I think that it's just a capital allocation decision. And that's my job, I think, is to try to work with Clay and Kevin and the teams on what is the best capital allocation decision we can make. And so we are seeing those opportunities, and we have to be very thoughtful. We now have the share repurchase, which when you look at what our NAV is, we feel like our NAV value is, to where we're trading at today, that's a pretty good slam dunk of an investment I think. And so that versus some of these wonderful Delaware and Bakken returns we're seeing in our wells versus some of the midstream equity investments that we've made that we've done very, very well. So the opportunities still are coming our way and we'll try to do the best we can at being great capital allocators.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [37]

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Okay. And then sort of along the same lines, you mentioned the water, but just how should we think about the plan going forward for the midstream assets that you already have, including the Howard JV and so on? Are we going to see more monetizations like this on 2019? Or how are you thinking about that?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [38]

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We are going to be very, very thoughtful. It's -- we will watch the market. We think in lot of ways our midstream asset and portfolio is still a little bit immature. But we also know that from time to time monetization is the right way to go. And so once again, we'll try to make the right decisions, when is the right time to monetize and if it is right to monetize, and so we'll keep you posted.

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Operator [39]

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Your next question comes from the line of Betty Jiang with Crédit Suisse.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [40]

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I have a question on 2020. Given the well cost savings you're seeing today and generally doing more with less equipment, if you maintain at the current 8-rig pace, do you think you can do the same well activity with a lower year-on-year CapEx next year?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [41]

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I think we could. Because if you think, Betty, the first half of the year we did have some higher well cost. We had some obligations, I believe, on some sand purchases such that if you walked away there's a penalty. Those sorts of arrangements have -- will have expired. So I think your assumptions are right. Same level of rig count, you'd probably see less D&C CapEx.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [42]

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Great. And then just broadly on 2020 planning, I know it's early days, but high-level perspective, are you solving for some adequate level of free cash flow, or an adequate level of production growth with free cash flow more as an output?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [43]

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This is Kevin. And you're right, we're still in the early phases, but I think, first and foremost, we're focused on returning free cash flow or optimizing our free cash flow with an eye on how much production growth is the right amount of production growth given the kind of threading of the needle between how much free cash flow we can generate with -- and I don't even want to talk about rig count, it's more, as you just asked, it's more about the efficiencies that we're getting out of how much free cash flow, given the reduction in capital that we're seeing coming on a per well basis. So that's really, I think, where we start. It's free cash flow. It's the capital efficiency that's driven by the well results, and then kind of what's the resulting production growth and are we comfortable with that production growth?

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [44]

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Got it. If I may squeeze one more in on Clay. Probably not an issue for WPX, but on the Bakken gas infrastructure constraint in the basin, could you give any comment around that?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [45]

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Thanks for the question, Betty. I'm real proud of what the team has done. We have worked very hard on this. We do have the advantage of being very high oil cuts, nearly 85% on our end of the Williston Basin. That works in our favor. But we worked very hard with our midstream gatherers. We have worked very closely with the NDIC to make sure we understand the rules. We explore every option on how we can possibly meet those gas capture rules. As I mentioned in my prepared remarks, we've met that every month. Very proud of that. We continue to do so and we'll continue to do so going forward. There are challenges out there. When gas price is the way it is in the Williston Basin, the midstream providers are often -- there's no financial motivation for them to lay additional lines. Every now and then you have right-of-way constraints or other challenges like that. And so it's really a big deal for the Williston Basin. I think the NDIC has worked very well with industry, but also has some very strong opinions, rightfully so, about not wasting resources. We share those opinions, and I think we've done a very admirable job of being able to meet that month after month, and now year-after-year.

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Operator [46]

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Your next question comes from the line of Leo Mariani with KeyBanc.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [47]

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Just a question sort of surrounding the thinking with the buyback here. Obviously, you know that the buyback is opportunistic, which can certainly involve a fair bit of capital and consume a lot of the free cash flow over time. Do you guys see the buyback is kind of delaying a potential dividend announcement? And then additionally, does the buyback also potentially obviate sort of earlier discussion about maybe adding a rig in 2020?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [48]

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You're right, it is. We are being as opportunistic as we can. And I don't know if it really delays the implementation of a dividend. I think what it is, is as we look at returning -- but we are committed to returning value to shareholders. We have the portfolio to do it and now we're starting to generate the free cash flow that gives us the options in order to be able to do it. And as I sit in my seat and I look at what's the best return of -- what's the best mechanism to return value to shareholders, right now, with kind of the irrational trading that we are seeing in the upstream equities, in particular the way we've traded against, as Rick mentioned, our NAV, that is the best opportunity or that's the best mechanism to return shareholder value now. It doesn't take dividends out of the toolbox for us. I think it's just a matter of, as we start thinking about, over the next couple of years, how are we going to returning value to shareholders, we needed this tool in our toolbox, and we're going to be opportunistic as we think about that free cash flow and how to give it back to the shareholders.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [49]

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Yes, I'd just add some to Kevin. It's an evolution, right? Because the first thing was, we needed to pay down our debt. That was our first "paying back to shareholders" was driving debt down. That was a massive focus for us over the last couple of years. We feel like we've -- if not checked that box, we're well on our way to move it from 1.5 down towards 1.0 on net debt to EBITDAX. I think the dividend conversation is really that sustainability to the point that, okay, we're ready to commit to this for the very foreseeable future and to the point that we can continue to increase that dividend over time and all the things you like to see. And to be honest, we are just not there today. It's not -- we're not at the point where we can -- where you're ready to commit to that. I think in the face of having the dividend -- or excuse me, the buyback opportunity we do, we see that as a better opportunity. And then once the dividends come into focus, we'll move that direction as well.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [50]

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Okay. That's helpful. And I guess, just to follow-up here. Obviously, you guys talked about better oil price realizations when Gray Oak comes online later here in the fourth quarter. Can you guys give a ballpark of -- obviously, there's some price benefit, but can you give a ballpark of how much you can see GP&T per BOE go up when that comes on?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [51]

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What is that number? When Gray Oak comes on, what's the increase in GP&T on that one?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [52]

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It's probably somewhere around $0.15, $0.20.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [53]

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Yes. Pretty negligible. We will see that added on to the (inaudible). Just an important point on that is when we get Gray Oak up and running, obviously we're getting that to Corpus. That's tying those barrels to Brent pricing, international pricing. And so now you're really -- that cost is much more outweighed by the benefit of seeing international pricing.

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Operator [54]

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Your next question comes from the line of Kashy Harrison with Simmons Energy.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [55]

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Congratulations on getting to the point where you can begin returning capital to shareholders. And so -- and maybe one for Clay or Kevin. You highlight the Delaware well cost, I think, tracking maybe around $9.5 million for a 2-mile lateral, Williston looks like it's tracking sub-$7 million. When you take those lower well costs into consideration, when you take your base declines exiting 2019 in consideration, which I imagine should be lower on a year-over-year basis, I was just wondering if you could help us think through that D&C maintenance CapEx level to hold the 2019 -- or 2019 Q4 exit rate flat through next year?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [56]

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Yes. I anticipated the maintenance capital question, and it's one of those tricky numbers, Kashy. It's how do you -- you're talking about oil, you're talking about BOEs and how you manage that? Here is the way I'll answer it, and it's kind of a high-level sense. For us to maintain essentially the same ratio of rig counts that we're doing today, same gas/oil ratio, the same kind of mix in general, and to -- when we think about maintenance capital, fourth quarter or fourth quarter exit -- exit-to-exit kind of flat, that's probably $800 million or $900 million to get that point.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [57]

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Excellent. And then -- that's very helpful. And then building upon a few earlier questions, I know that it's very highly dependent on an -- quite frankly, an enormous amount of variables, but I was wondering if you could just walk us through, as you stand today, how you think about your base case horizontal spacing assumptions on average for an interval? How you think about the optimal vertical spacing? How you think about the number of landing zones? All of that that could be economically developed within, call it a $50 to $55 environment. And then maybe as well as -- I think you made an earlier comment, but how you think about that maximum time lag between the parents and the inflow wells before you run the risk that you're going to start to see degradation in the inflow wells?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [58]

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All right, Kashy. I realize that was a follow-up question subpoint a to z. So I'll try and remember what you asked. As we think about in today's environment, $50 to $55, the optimal spacing, let's just start in Stateline itself, Wolfcamp at the Upper Wolfcamp -- so that's Upper A, Lower A, X/Y, and sometimes B, wherever that flow unit is -- that's probably 4 landing zone -- 2 to 4 landing zones, depending on where you're at in the area. Now it's an interesting -- I've mentioned the number of landing zones, one because that was your question, and then two, it affects the -- how tight you can drill those wells. If you have 3 landing zones versus 2, that definitely impacts how many wells you can cram in on a horizontal sense. When we're driving for higher returns and making sure that we're yielding enough meat on the bone to get all the way through to full cycle returns, I think we're probably as few as 4 wells per landing zones, maybe as 6 wells per landing zones, probably in that range for each one of those. So 4x4 is 16, 6x4 is 24, for that, that would probably be your range, the wells that we land in the Upper Wolfcamp A. And so different ways to talk about that, in a kind of bird's-eye view, but it depends on landing zones and individual well thickness and then obviously the well parameter -- or the reservoir parameters like permeability come into play as well.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [59]

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Got it. And you would still have incremental landing zones associated with the -- I imagine with the Third Bone?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [60]

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Yes. A whole other flow unit, and like I said earlier, we're holding back on saying -- just because we don't know yet -- how many landing zones and well spacing in regards there. But I hope that it shapes up something similar to the Upper Wolfcamp A. To me, the individual well results, the thickness that we see -- interestingly, it has more natural frac barriers in that formation. So you will be able to better control some of the stimulation. But it's too early to kind of nail that one down. And don't forget about the zones below the B as well. We still have C and D that has lots of opportunity. It just has a higher gas cut, but that will come to us in time.

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Operator [61]

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Your next question comes from the line of Irene Haas with Imperial Capital.

Your next question comes from the line of Gabe Daoud from Cowen.

Your next question comes from the line of Jeff Grampp with Northland Capital Markets.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD & Senior Research Analyst [62]

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I'll just leave it at that one kind of philosophical one here, as per you guys on the buyback. Rick, you mentioned in the release, you don't want this to impact your ability to grow in 2020. But just kind of curious, how you guys kind of settled in? Why is the $400 million kind of the right number to put out today? And how you guys maybe balanced any conversations internally on -- were there any conversations, I guess, on scaling back growth and doing a larger buyback program given the opportunity in your stock here?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [63]

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Yes. The buyback is something we've contemplated for quite some time. This is not just something that came about in the last 10 days. We've discussed this option with our Board for quite some time. We always felt like that to do it, you needed to be in that plus or minus 10% of your total outstanding shares to make it meaningful for shareholders, and we ended up getting there. And so we went ahead and thought that it was the right time to implement the program, especially with some of the recent performance that we just -- we hate to keep beating a dead horse, but the behavior, we called it irrational, it just seemed like a perfect setup for us to step in and once again make just really a good fundamental investment in buying ourselves.

As far as upsizing, I think it's much too early for that. We are just -- we'll see how this first tranche goes over the next 24 months.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [64]

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Yes. And I think if you look -- again, if you look at our projected kind of consensus estimates, free cash flows over the next 24 months and you think about $400 million, that's not a bite that's too big for our balance sheet. I did mention that we were going to -- as we buy back in these shares in order to protect the balance sheet, you'd see us do a little bit more hedging. But again, $400 million over 2 years is really pretty commensurate with the amount of free cash flow that we have the opportunity to generate and still give a pretty good growth profile to create more cash flows as we think about 2021 and beyond.

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Operator [65]

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Your final question comes from the line of Gail Nicholson with Stephens.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [66]

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I just wanted to ask you your thoughts about ethane rejection versus recovery in the second half of '19. You have a unique situation with your flexibility and optionality with the cryo facilities. I was just kind of curious on how you guys were thinking about ethane?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [67]

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Yes. Thanks for the question, Gail. It's a very dynamic market. I can tell you a situation that happened within the last week. The issues happened down in Baytown. I think it was a maybe midweek evening, by -- within 12 hours of that, we had already talked to our partners at Howard, we had already made changes at the plant and we were already switching to ethane rejection in the face of a crashing ethane market. That's a pretty unique ability for an E&P company to be able to control and have a say in that real time. So we'll continue to move with the market. We're very thoughtful about staying ahead, obviously, on Waha gas prices. We're working hard on the NGLs as well. It's just -- it's a little more difficult market to kind of pin down because it's so dynamic. We'll continue to watch it. I don't have any strong predictions on where ethane prices are headed. But I can tell you we'll continue to watch it as quickly as real time and make appropriate changes to stay in line for the best value creation.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [68]

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Okay. And then just going back to kind of the comments you guys made in regards to optimal landing zone post the core data analysis you did. When you look back at the landing zone before core data versus post core data, do you know what percent wells were being landed optimally prior to the core data being done?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [69]

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That's a great question. It's a -- sometimes this core data, you're moving the landing zone 10 or 15 or 20 feet. So it's not like you're going from 2 landing zones to 3 or you're shifting 150 feet into really a different interval. Sometimes what we're trying to do is push that landing zone so you're getting the energy of the frac to break through a frac barrier and make sure you're accessing part of the reservoir. Other times, you're trying to distance yourself from that frac barrier so it remains an effective frac barrier and you're able to keep that frac constrained. So I would say it's more about fine tuning. It's kind of like the ultimate frac design. You are never fully there. And then once you figure it out for 1 drilling spacing unit, you move over a couple of miles and it changes again. So we have really good core, that core is able to tie back to the logs. We're part of a consortium in the area, so we share information with other operators, learn from that information. We have a very robust framework structure, all the geologic data, so we're able to move kind of around the field and understand if we learn something here, how does it apply 2 to 5 to 10 miles away. So it's pretty dynamic. I would say very few were landed perfectly; just like your completion design, very few are ever perfect. You're always in search of that perfection and always trying to continue to move towards it, but this incredibly important data helps us get closer everyday.

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Operator [70]

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There are no further questions at this time. I will now turn the call back over to Mr. Rick Muncrief.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [71]

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Thank you, operator. And thanks for those who are still on the call today. We appreciate the opportunity to spend time with you today. We're excited about our future. We had a wonderful quarter, and we're going to have a strong second half. And I think it really sets us up for a nice 2020. So thanks again. Have a great day.

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Operator [72]

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This concludes today's teleconference. You may now disconnect.