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Edited Transcript of WPX earnings conference call or presentation 2-Aug-18 2:00pm GMT

Q2 2018 WPX Energy Inc Earnings Call

Tulsa Aug 2, 2018 (Thomson StreetEvents) -- Edited Transcript of WPX Energy Inc earnings conference call or presentation Thursday, August 2, 2018 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. - Manager 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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* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* Brian Michael Corales

Johnson Rice & Company, L.L.C., Research Division - Analyst

* Derrick Lee Whitfield

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

* Gail Amanda Nicholson Dodds

KLR Group Holdings, LLC, Research Division - MD

* John C. Nelson

Goldman Sachs Group Inc., Research Division - Equity Analyst

* Kashy Oladipo Harrison

Piper Jaffray Companies, Research Division - Research Analyst

* Kevin Moreland MacCurdy

Heikkinen Energy Advisors, LLC - Partner and Exploration and Production Research Analyst

* Leo Paul Mariani

National Alliance Securities, LLC, Research Division - Research Analyst

* Matthew Portillo

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Exploration and Production Research

* Michael Adam Glick

JP Morgan Chase & Co, Research Division - Senior 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

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Presentation

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Operator [1]

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Good morning. My name is Jodie, and I will be your conference operator today. At this time, I would like to welcome everyone to the WPX Energy second quarter webcast. (Operator Instructions) Thank you.

David Sullivan, Director of Investor Relations, you may begin your conference.

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

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Thank you. Good morning, everybody. Welcome to the WPX Energy second quarter earnings 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 to 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 close yesterday. Also, our Q will be filed later today.

Please review the forward-looking statement and the 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. Good morning to everyone on the webcast. On behalf of our entire WPX team, we're glad you've joined us today as we review our most recent quarterly results.

As we sit here this morning, our company has approximately $10 billion in total enterprise value. This is not only another milestone for all the hardworking women and men at WPX but also many of our investors. This has come due to the wonderful growth that we've seen in our equity value, and it will continue. Our growth story is unbelievably compelling from my point of view. I'm pleased with how our people champion each other as they work together, chase the checkered flag to fulfill our goals, show their energy as they recognize the critical importance of our industry and constantly ask why as they look to innovate and challenge former ways of doing things.

To sum, this corporate culture stuff may sound like mere window dressing. But I know it's what creates value. It's how we increased oil volume from 15,000 barrels a day since the last quarter. It's also why our performance this quarter exceeded expectations. It's why our outlook is simply so positive. It's why we've accomplished so much in such a short time.

In our business, you have to have the right geology and leasehold. But what makes the difference is what your people do with those assets and how they market the end product. I'm super proud to be part of the team as thoughtful, decisive, forward looking and tough as nails. We're rightly defined by the results of our work, and we recognize that we have responsibility to execute crisply quarter-to-quarter.

Let's turn to Page 2. Our Permian and Williston teams are well poised to keep delivering for shareholders. And as a company, we're going to remain disciplined with our spending and opportunistic in our approach to create value. These are hallmarks to place WPX on very exciting trajectory. Even though we're seeing tremendous well results at both of our basins, there's no reason to get ahead of our skis. Our pace of development is serving us well. This also helps us stay focused on our infrastructure build-outs to ensure that our growth profile is truly realized.

Gathering lines and equipment, such as compression capacity, are critical in moving our product one step closer to the marketplace. These facilities are vital because they connect us to the strategic takeaway capabilities we have under contract.

As I've said before, this is a complex business with a lot of moving parts, and the favorable results we're seeing comes from strong execution in both of our basins.

This slide illustrates our growth from 23,500 barrels of oil per day to over 80,000 barrels a day in a fairly short time. That's a big, big deal. It's taken a lot of bold moves, creative thinking and grit to get where we're at today, but most importantly, to chart where we're headed. Let's turn to Page 3.

Our oil volume growth is only half a story. We've always said we will not grow for growth's sake. From the day I arrived, we put profitability and improved returns front and center on every well we drill and dollar we spend. Internally, this is part of our annual strategic imperatives that we rolled out to employees.

In black and white, we spell out what value-driven growth looks like. They are the actions that really do move the needle, like lower cost, higher revenues and increased margins on every incremental barrel. And there may not be a better scorecard of what we've achieved financially with our transformation than what you see on this page.

The bottom of the slide shows the commodity price environment we were in for each year for both crude and natural gas. You can see how our production volumes decreased over several years due to the sale of low margin or nonstrategic natural gas weighted assets. The chart clearly shows how much our unhedged adjusted EBITDA climbed on a BOE basis as we narrowed our business focus, dramatically reduced our total production and saw market forces cut oil prices by more than a half.

We feel the unhedged point of view gives us the truest picture of the underlying strength of the company. Today, our unhedged adjusted EBITDA on a BOE basis is exponentially better following our company's transformation. For example, since we entered the Permian in 2015, we're up 461% by that measure. Inherent in all of this is how much our cost has improved as we targeted higher-margin output.

It's obvious that our cleaner, leaner focus has fueled the pace of financial growth that would be attractive for any business in any sector. Growth matters. Margins matter, and real sustainable value matters. In my mind, this isn't just about how we're faring against our energy peers. This transformation competes with some of Wall Street's top-performing companies. Now let's turn to Page 4.

As we drill down into our second quarter results, I'm very pleased by the slate of impressive numbers that highlight our continued progress and success. We beat our second quarter oil guide by 5,000 barrels per day, which is made possible by a 61% increase year-over-year. Total oil and NGL volumes were just shy of 100,000 barrels per day. That's a new record for us. Those volumes accounted for 97% of our total product revenues of $520 million.

Our quarterly cash flow was 136% higher than a year ago. This measure is important because it shows our capacity to reach cash flow neutrality next year and then starts stacking cash. We've also followed through on our pledge to lower our leverage, and we've done so fairly quickly. And most importantly, our unhedged adjusted EBITDA once again is $365 million, that's up 235% year-over-year.

Let's turn to Page 5. And here's Clay Gaspar to talk about our operations.

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

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Thank you, Rick, and good morning, everyone. It's always nice to be the bearer of great news, but I must give credit where credit's due. The strong operational performance is a result of the hard work of our greater WPX team and the alignment of our industry partners. The performance is evident, once again, in both the Williston and the Delaware basins.

As I mentioned on the first quarter call, we set a goal to replace the oil production we sold in the San Juan Gallup divestiture, with the production growth from this quarter. I'm proud to say that we blew right past the 10,000 barrels a day goal, and we actually grew production in the second quarter by 15,000 barrels per day.

Our upstream execution and our marketing strategy continues to lead the pack in the Delaware. The early benefits of this forward-thinking strategy show up in our second quarter numbers, but this work will continue to pay dividends for years to come. This forward thinking and being opportunistic wasn't just a temporary mindset. It's a core competency of who we are as an organization. We continue to think out those opportunities, and we'll keep our competitive edge well out into the future.

In addition, because of this reputation we built, we get approached by other entities with out-of-the-box and forward-thinking ideas. We're currently expanding our Delaware Basin infrastructure to scale up water recycling, reduce flaring and generally handle the larger well rates and larger well pad development. We also continue to make very effective land trades. And every so often, we find a strategic bolt-on acquisition that fills in a land gap for us.

Last year, we worked very hard to lock in the big ticket well cost items, like pumping services, rigs, water and sand. We were very effective in doing so, and we've been very pleased with our partner alignment. That said, we've had some inflation in items like steel, electric line, coil tubing and fuel. Although none of these items are significantly detrimental to our well economics, we're watching these costs intently, and we work to mitigate the pressure on inflation.

Now let's turn to Slide 6, and we talk about our impressive results in Delaware. The chart on this slide shows the Stateline area well results for all zones drilled from 2015 to 2018. As you can see, we continue to make steady progress on well productivity. It should be noted that WPX 2016 average well is above the average for the entire industry for 2017. This is another mark of WPX just being a few steps ahead of the pack.

It's also important to note that this plot is normalized for lateral length. This is a good way to strictly look at productivity, but it generally understates the impact to returns. Simply stated, the productivity going up on a per foot basis, combined with much longer laterals that are materially cheaper to drill on a per foot basis causes the compounding effect that results from substantially higher returns. This is exactly the results we're looking for.

I believe in prior -- I believe that prior success can be the greatest enemy of future success. To prevent this, we routinely challenge the status quo and look for that next step change. This is illustrated on the completions evolution at the bottom of the slide. We continue to iterate on what the right approach is and several critical aspects of well construction and fuel development.

On our Lindsay pads, which we started completing in early July, we're testing longer stages, up to 230 feet, at the same time, tighter cluster spacing down to 14 feet. We're also testing 80% and 100% 100 mesh sand, and we look forward to sharing those results in the third quarter call.

Now let's turn to Slide 7. As you can see on the bar chart, our Delaware oil production has grown almost 100% second quarter '17 to second quarter '18. This impressive oil growth is driven by wells like our recent 7-well 1.5-mile Tucker Draws. This pad has cumulative production of over 1 million barrels of oil equivalent in the first 60 days, with an average 24-hour IP of 2,400 barrels of oil per day.

I just mentioned that we'll have full pad results from the Lindsay on the next call. But just as our preview, our Lindsay -- first Lindsay X/Y well has produced over 50,000 barrels of oil in its first 20 days, with a 24-hour IP of 3,600 barrels of oil a day. I can already hear the internal competition heating up as this team challenges the lowest and North Sunday Island team.

In mid-July, we exercised our option to increase our ownership in Oryx II to 25%. This is exactly the kind of opportunity I mentioned in my opening remarks. This was a grand slam investment, and at the same time, it's a fundamental part of our oil takeaway story. We believe these investments are critical to our near- and long-term benefit of WPX, and thus, we're willing to invest our precious capital into them even we have such a deep and rich drilling portfolio.

During the second quarter, Oryx announced the expansion of Oryx II system from 400,000 barrels to 650,000 barrels per day. WPX is 100,000 barrels a day of capacity on a project that will deliver oil from deep in the Delaware Basin to Midland and Crane.

In regards to our JV with Howard, the first 200 million per day gas processing train will start up this month. The second 200 million per day train is scheduled to be in service mid-2019. The start-up of this plant is a major milestone for the JV, and the partnership continues to provide upside beyond our original expectations.

Now if you will turn to Slide 8, I'll discuss some of our strong results in the Williston Basin. We continue to be impressed with the productivity of the North Sunday Island wells. The strong results we are seeing there and in the Mandaree area have helped us deliver 39% oil growth second quarter of '17 to second quarter of '18, with mostly a flat 2-rig program during that period. The 7-well Arikara pad has cumulative production of 1.4 million BOE after the first 130 days of production. And the Arikara 15-22HB has produced 230,000 BOE in the first 130 days.

Our remaining North Sunday Island well pads are the 7-well Hidatsa and the 3-well Raptor pads. The Hidatsa pad is scheduled to come online mid-September, and the Raptor pad is scheduled to come online mid-October. Because of the prolific nature of these pads and the timing of first sales, the production profile for Williston will be weighted towards the latter part of the year. While growth in the Permian will be fairly steady for the coming quarters, the North Sunday Island well timing should set Williston up for a very strong fourth quarter.

Now I'll turn it over to Kevin, our CFO, for a financial update.

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

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Thank you, Clay. The well results are certainly worthy of the attention and the capital they're receiving. It showcases the value our business is generating. The things today are apparent: growth, discipline and execution. This is why WPX is worth more today than ever before. This is a company that's very healthy and capable of both sustaining and improving upon the results we're seeing. Our strategic decisions have been spot on, like maintaining our multi-basin approach when others were going pure play and getting ahead of the Permian takeaway issues, as Clay mentioned, many of our peers are experiencing today.

Being in the Permian and the Williston gives us some great optionality that others would love to have. We're also building our financial flexibility in a very smart way: by reducing cost, placing our emphasis on high-margin growth and lowering our debt, just like we said we'd do. WPX is in a solid position because of our deftly prioritized -- as we have deftly prioritized our financial success just as much as our operational success. We believe our harmony between the 2 is a recipe for delivering the right results. All of this gives us the luxury of being able to weigh the variety of levers that are available to us as we continue to enhance value for shareholders.

Now let's turn to Slide 10 and review our second quarter results. Oil production of 80,800 barrels per day represents a 61% increase versus the second quarter of '17 and is driven by the Delaware Basin. As Clay indicated, our Delaware team is working extremely hard to manage the activity levels and cost pressures that all our peers are facing in that basin. This growth in the Delaware represents a 16% sequential increase when compared to the first quarter of this year.

The Williston team grew production by 39% this quarter versus last year and 30% versus the first quarter of this year. This strong operational performance from both basins is what drove the financial results for the quarter.

For the second quarter, we are reporting an adjusted EBITDAX of $287 million, which is $164 million higher than the second quarter of prior year, which represents 133% increase. Yes, that's an impressive improvement. However, I'm most pleased by the fact that we've developed our strategy over 2 years ago. We communicated our plan. We worked with our strategic partners, and our employees embraced the direction that we were headed. As I think about where we anticipate it being at this point, we are ahead of schedule.

As I mentioned last quarter, as our production grows throughout the year, our hedge percentage comes down, thus allowing us to capture more barrels at spot prices. Our continued margin improvement on every barrel produced is just as important as the number of barrels we are producing.

For the quarter, our LOE and G&A expense per equivalent barrel had -- have seen decreases when compared to the second quarter of '17. Again, our margin improvement on higher production is driving our financial storyline.

For the quarter, we are reporting adjusted net income of $23 million versus a net loss of $54 million in 2017. The improvement was driven by the same factors impacting adjusted EBITDAX. However, our DD&A was $56 million higher than last year and driven by our increased production volumes. Despite this absolute increase, our DD&A rate improved by nearly $3 per barrel. As we continue to drill better wells at better costs, this rate continues to improve.

In addition, our interest expense per BOE has decreased by over $3 a barrel. This reduction is the result of our increase in production, coupled with the debt management transactions that were completed during the second quarter, where we used a large portion of San Juan Gallup proceeds and a new bond issuance to retire nearly $921 million in outstanding debt.

Our capital expenditures incurred for the second quarter totaled $355 million versus $316 million last year. We are revising our full year capital guidance, which I'll give some further clarification on in a couple of slides.

Now turning to Slide 11. You've heard it now a few times that we believe this slide is a great way to depict the protection that we had against the widening Midland-Cushing basis differentials. I give our oil marketing focus particular credit here, together with the basis hedging decisions we made after our entry into the Delaware Basin 3 years ago.

As you can see from the slide, one of the banks has modeled what the impact to 2019 EBITDA would be at $15 and $20 differentials for WPX and some of our peers. The impact to our results is insignificant, especially compared to the averages of the peer set that they utilized. Our portfolio of sales agreements that exposes to non-Midland pricing, together with our basis hedges, was done way ahead of the widening of this spread. We have these contracts in place for 3 to 5 years until the installation of the necessary pipelines to relieve that pressure.

Now turning to Slide 12. We are updating our full year guidance for several items. First, we are raising our full year production guidance starting with oil. Our full year oil production is now anticipated to be between 78,000 and 82,000 barrels of oil per day. We're also raising full year gas guidance to 150 million to 160 million cubic feet per day; and NGLs to 19,000 to 21,000 barrels per day.

With the increase in production guidance, we're also raising our full year capital guidance to reflect the better knowledge that we have halfway through the year. As you heard Clay mentioned, we have received more project proposals from our peers where we would participate as a nonoperator in the Delaware. There are obviously a lot of great projects down there. Of the capital increase, these project requests represents approximately $50 million. Also reflected in the projected capital is the need for larger facilities and other infrastructure in the Delaware totaling $30 million. The performance of the wells continues to be phenomenal, and we have -- and we continue to calibrate the necessary facilities to optimize the performance of these wells. We are also budgeting another $20 million for larger completions in the Williston Basin. The results of these larger jobs speak for themselves, as Clay showed earlier.

Given we are over halfway through the year, we have also tightened up the guidance range to $1.3 billion to $1.4 billion overall. We also improved our average oil price differentials and slightly increased the natural gas expectations.

On the expense side, we have lowered most of the expected expenses per BOE, except for GP&T, which shows a slight increase. However, this increase is nothing more than a geography issue on any income statement due to the adoption of certain accounting provisions. The offset to this increase is in higher realized commodity prices.

So I sound like a broken record, but the financial transformation that we talked about almost 2 years ago has happened. I remember people telling us, well, all you have to do now is execute. Some believe we would and others we'll always be skeptical. I'm pleased to say the WPX team executed, that the power of the portfolio that remains is going to generate returns for years to come.

Now I 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. There's a question that CEOs get all the time, and I'm sure you've heard it, it goes like this. What keeps you up at night? Well, for me, the answer is really easy: adrenaline. I don't say that (inaudible) even though it might generate a few laughs.

But what I think about where WPX is at, the opportunities we have on the horizon, the tremendous quality of our assets, the quality of our people and our unique capacity to create value, I can't help but be excited. Sure, we still have to execute. We have remained smart in our approach. We need to stick with our plan, and every day brings opportunities for us to sharpen our tools in each of these areas. But we're on the right track, and I feel like we've been a trendsetter.

We ended the Delaware Basin before the market got too hot. And then we made a conscious attentional decision not to be a pure play Permian, when others were being pressured to go that route. We saw the value of being in 2 basins rather than in just one. And now, our Williston well results keep proving our wisdom to retain our world-class position there. The days of the WPX reset were the defining time. And now our relaunch simply look better and better with each passing day.

And at this time, we'll open the line up for questions and 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) Your first question comes from the line of Kevin MacCurdy of Heikkinen Energy.

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Kevin Moreland MacCurdy, Heikkinen Energy Advisors, LLC - Partner and Exploration and Production Research Analyst [2]

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In the release, you hinted second half volumes depending on Williston timing. Can you maybe elaborate on the expected cadence there?

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

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Yes, I think about kind of the cadence that we've shown when these really big pads come on and they line up beginning of the quarter. I think you saw that from first quarter to second quarter here. I think we'll have something similar third to fourth. Now remember, in the background, we have Permian that's growing substantially and very -- most studier. You have a 7-rig program there. You have the benefit of a much more normalized cadence. Williston is -- because these pads are so large, they're so oily, and the timing of those with a 3-rig program, you end up getting a little bit lumpier volumes. So I just want to give you a heads up on that.

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Kevin Moreland MacCurdy, Heikkinen Energy Advisors, LLC - Partner and Exploration and Production Research Analyst [4]

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Great. And as a follow-up, it looks like well performance really drove the beat versus our model. Is there anything new that you're doing in the Delaware specifically on the Tucker and the Lindsay pad?

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

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Kevin, we're always changing things. I think one call I made the mistake of calling it a generation 3, and I promise I would never do that again. So I don't know what generation we're on, 17, 18 or 19. But I think it's a continued evolution. We try to illustrate that and some kind of some high points at the bottom that one completions Permian slide, but I can't say there's anything unique beyond the normal evolution that we're seeing from our drilling completions in conjunction with the reservoir team. Remember, as we're reiterating on these completion designs, we have reservoir engineers tucked right in beside them thinking about well spacing, thinking about well-to-well communication, both vertical and horizontal. What we're really excited about now is we feel like we're steps ahead of many of our peers on the development model, and so we're really moving into a full development mode and really understanding zone-to-zone interactions, which has been very exciting and many times positively benefiting the wells rather than negative interference as we've seen in some of the offset -- excuse me, other basins.

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Operator [6]

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

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [7]

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Rick, in your prepared comments, you mentioned stacking cash in 2019. Just wondering if you could elaborate on that a little bit? As far as the uses of that potential cash go, can you talk about how you think about just improving the balance sheet versus accelerating versus some sort of repurchase our dividend?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [8]

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As you look on our balance sheet, it's going to continue with our -- with our continued growth, you're going to see those leverage metrics even get lower and lower. And at some point in time, I don't know if it's a point of diminishing returns, but at some in time, it's not meaningful as it was, let's say, 12 months ago. I think the reason we use term stacking cash, we wanted to just illustrate the cash flow -- positive cash flow capabilities we have. And I think what we all have to do is we'll look at that time what the best uses of the capital is it still 18 months out. And I think the thing we really want to illustrate is just the strength of our portfolio and the capabilities that we see ahead. Whether that means we redeploy that cash to the drill bit, whether it means we leave it on the balance sheet, whether it means we return to shareholders in some way, I think we have some optionality. That's the key point we want to make.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [9]

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Okay, got it. And then a couple of questions on the Bakken. So you guys mentioned that you have these 2 North Sunday Island pads left. Can you verify that, that -- that those are all the remaining locations for North Sunday Island? And then secondly, can you talk about how to decline curves work obviously, those are very prolific wells. Do they also hold up better than a traditional Bakken well as time goes on? Or are they the same or worse? Any color there?

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

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Yes. So we have -- let's first confirm. There was 23 North Sunday Island wells. So yes, this is the remaining inventory. Just to give a little bit of history on this particular group of wells. This -- we know, -- we knew was some of the best geology in the entire basin. The only reason it hasn't been developed to date was because some complications around land ownership, some disagreements over that. We've gotten through that. We worked through that. Our land team's done an amazing job. And then now we find ourselves sitting on some of the best undrilled rock in the whole basin. So that was kind of the uniqueness of this and why we had these 3 particular drilling spacing units ready to go. So that was your first question. The second question is around the decline. What you'll see is you start looking at some of these longer wells. We have about a year on some of the oldest wells. And they are hanging in and weigh above the type curve for the balance of the Williston Basin. This is just remarkable rock. We're putting state-of-the-art completions to it, and they're continuing to outperform that curve way out into the well's life.

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Operator [11]

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

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [12]

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Rick, question for you or Clay. I noticed on the Tucker Draw, you mentioned fantastic rate despite the restricted flow. And then moving over to the Bakken on that Mandan sort of same thing there. I mean, that well came back on 6,000 obviously with kind of call it the lack of equipment there. So I guess, my question is you are known for having some of the best takeaway in the Permian, obviously, with how much you did ahead of time. But I'm just wondering both -- as I look at both of these areas, are there other things you're still choking back or just -- you know, again, I guess, Clay, the real long-winded question is what would IPs be on some of these if it wasn't for some of these restricted chokes on some of these areas?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [13]

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Neal, that's a tough to answer -- question to answer very definitively because it really -- there's so many things. One, how strongly would you flow these wells back, ultimately, that's a question on reservoir productivity and is there a point at which you're doing negative damage. We feel like we're well in that comfort zone of kind of the sweet spot of flow back. We want to flow back aggressively but not so aggressively where we're doing any negative damage to the rock. All right. You mentioned that we are forward thinkers, and we have embraced this. We are ahead of the takeaway constraints. We think about getting oil all the way to the Gulf coast. We think about getting oil on the ships and selling it internationally. So why do we have a constraint on a well in Tucker Draw. Well, about 16 steps before that, it's things like the size of the separator, the amount of flow back equipment, maybe even your ability to get a right away to put in a water line and you're constrained on how much water disposal you can have at that particular time. These wells continue to outperform our expectations, and we built -- bring on these big pads. The internal debate is very good one, and it's all about how much do we upsize the facilities? How much do we loop the lines, build the facilities, which, obviously, is a cost associated with that well. How much do you benefit from that short-term gain? Or do you just essentially build for a flat 3-month, 4-month, 5-month environment? Is that better value creation? And so it's an interesting debate. The great news is we are seeing very, very strong well performance. As you do that, the facility size has come up. We're spending more money, investing more money on the completions that we have to be able to accommodate these larger completions. As we bring on these big pads, we'll continue to migrate that direction, and I think -- but we're always looking for how do we create value and what's the ultimate return from that investment. Last point, as the uniqueness of the Delaware Basin comes into focus, remember, when we're building this infrastructure and investing for the long term, think about how many times we're going to reuse these pipes, these compressors, this system that we're building. We're building it for, say, a 6-well pad. That 6-well pad as a peak and then, say, 6 months, now that facility is maybe underutilized. Well, think about that again. Because we're going to have another 6-well pad and a third and a fourth and maybe 15th 6-well pad coming through some of these same facilities and certainly some through the same pipe, water disposal and a greater infrastructure. So the investments that we're making today are really, really cost beneficial to the greater development of this amazing asset.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [14]

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Clay, great answer. And just one follow-up right on that same point that you just hit. With those 6 wells and those type of pads, with all the takeaway and everything that you all continue to build out and as you said have -- will build out for the future, would you think that will change your plans as far as the size of the pads, instead you want to do 6, you might end up doing 8 or 10 with these zipper fracs or does that not factored you think on as far as the key economics you're still getting the best out of just doing sort of the size now or will that play into that later on?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [15]

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Great question, Neal. So we talk about this. We've had very, very recent within the last couple of days internal debates on that. And I can tell you, there's just as much argument for smaller pads, there is larger past. As you start thinking about 3- and 4-well pads, now the timing -- the cycle time of that pad is enhanced, okay? So you're -- the lumpiness of that profile is reduced. That is a material advantage to us. You also think about the sizing of the facilities and how big of a peak do you need to build to. As you pointed out, you could argue the other way as well. Bigger pads, more development. I would say it's several things come into play. Some of the most important are the existing facilities, do you already have some of the facilities in place, is it a relatively cheap, say, an extension of an existing line that allows you to build that bigger pad. And then secondly, as you think about scaling up rigs over the coming years, when we're a 20-rig company, it might be a clearly different solution than a 7-rig company. And so there's a lot to go then to it. Sorry to be a little bit convolute on the answer, but that's kind of just in-depth thinking about we are thinking about it and how we evolve this over time.

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Operator [16]

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

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [17]

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Perhaps for Clay, so (inaudible) Slide 7, would it be fair to say that your 1.7 to 1.8 rule of thumb multiplier for long lateral development may be conservative based on the type of draw results and well results you've observed in state data to date with longer laterals, I should add?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [18]

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Great question. I'm glad you remember my 1.7 to 1.8 rule. For the rest of the folks that are just catching up to that, early in the program, I often referenced as we drill longer laterals, please don't just do the simple math of twice as long lateral is going to give you twice as long -- excuse me, twice as much production EURs and the like. My general experience, based on several basin, is about a 1.7 to 1.8 ratio as you double the lateral length. Fine question because these longer laterals are generating maybe a 1:1 or even greater. I think there's a little bit of secret sauce in there. We maximize every footage -- every foot we can. That means building a facility, a surface facility off of location so that we can get legally the right. When -- we're able to start getting into the lateral and perforating that lateral, we are right there trying to maximize that. That allows us, and we're talking about 1.5 miles or even the 2-mile lateral to really maximize that and even get that footage that's in between the sections. So that works in our favor. I think the other thing and I'll go back to the evolution of the completions. We tend to talk about simple terms, sand per foot, perforating clusters, the footage in those. But there's so much to it. I mean you think about the clean-out technology, how we are flowing these wells back, making sure that, that 8,000 to 10,000-foot interval gets the benefits that, that first couple of thousand feet get from a drawdown perspective from a clean-out perspective. Our teams are working exceptionally hard on that. We don't have any secret sauce. I'm not telling you we're doing anything different than all of our peers are working really hard to do. But that is something we often think about, and that 1.7 could evolve to the up over time, and we're certainly seeing some nice correlation there. Good observation on your part.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [19]

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Yes. Clay, perhaps as my follow-up and thinking about what you guys are now doing in the Stateline area regarding our completion optimization pilots, could you outline some of the key variables you are assessing and how fast you could implement those refined designs across the area, assuming success similar to the Lindsay 10-3B-2H?

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

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Yes. So the Lindsay, in particular, we talk about some of the 100 mesh. And again, that's not anything new to the industry. But here's what's different about it, and maybe a way we're thinking about it maybe a little bit different than some of our peers. I think you could think about some of these tweaks in a realm of how do we improve well performance, which is hugely important. But man, in the dynamic world we're living in today of well cost, thinking about local sand, the regional sand versus essentially imported sand, the source, the size, the quality of that sand, that cost-benefit analysis and now that we're chasing $65 or $70 barrels rather than $40 or $45 barrels, that -- all that calculus changes quite a bit. And so our guys are business people at the heart. They're thinking much more about how do we create value. And if that means, you know what, this was the right answer when we had these kind of pressure pumping contracts in these kind of agreements in this kind of pressure on price, maybe we need to think that. Because boy, in the world that we look forward, maybe the next 6 to 12 months, we're seeing some softening of that pressure pumping market, maybe there's something we need to think a little differently about than we did over the last 12 months. So it's an evolution. There's a lot that goes into it. Certainly, pounds per foot, gallons per foot, perforating design, how close those perforations are, how aggressively do we flow back and goes back to the facilities question, how do we clean the well out, how do we give that well every opportunity to produce everything we can, how quickly do we put on artificial lift, what is the means of the artificial lift, those are all parts of the greater equation. But the equation, the metric that we saw for in the end is value. It's not IP, it's not cheapest this or that, how do we create value from this amazing opportunity.

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Operator [21]

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Your next question comes from the line of Leo Mariani of NatAlliance Securities.

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Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [22]

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Just wanted to dig into the Bakken a little bit more. Obviously, very impressive well performance there on the North Sunday Island. You talked about those wells being sort of substantially above average Bakken type curve. Can I get you guys to maybe attempt to quantify this a little bit. Are these wells sort of 2x? And maybe just gives us a sense of what that average basin EUR is.

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [23]

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Great question, Leo. So we look at -- we've held the 1 million-barrel type curve for the Williston for some time now. And in the face of these amazing North Sunday Island wells, it looks like we're the big fan baggers that Rick always accuses me of being. But when we put out a type curve, let's be clear, we're thinking about the next couple of years of average performance. And as we step away from North Sunday Island, that's very tried-and-true and known, you step into areas that in reality, you're going to have some above and some below that 1 million-barrel mark. Here's the really good news. While we've been working on North Sunday Island, some of our peers, especially to the south, have drilled some really phenomenal wells. We're actually completing some wells right now part of in the southern extension of our area that we are very excited about. We're flowing back some other wells kind of in that general area outside of the really super sweet spot, that these wells is probably going to put positive pressure on our type curve. And so I'll still hold to the 1 million-barrel curve as what you should model as you think about what do you expect for us in the 3-well -- 3-rig development over the next few years. That's kind of how we think about it. Very encouraged about the direction of the Williston, couldn't say enough good things about the fight that those guys, our team puts up in the face of some really harsh winters and some other really tough environmental challenges. They're doing a remarkable job, and I'm very, very proud of the -- not just the well results but the way we do it and the values that, that -- that those guys have.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [24]

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Leo, this is Rick. I may also add that there's some couple of things that I think are making North Sunday Island somewhat unique, and that is the amazing observed porosity and permeability we're seeing there. And so in all likelihood, there's a good -- there is a good chance, I think, that we've been somewhat conservative in our spacing assumption. Over time, we'll see how that plays out. But I think it plays well when you start thinking about the question that Clay got earlier, and that is what -- how the well is going to decline. And so we've taken a stab at the spacing assumptions, and -- but you're seeing great, great performance, not only just the performance on the IPs, but let's look at them 6 months, 180 days, let's look at a 1 year and 2-year look. It's phenomenal area, some really strong pressures. That's the other thing we didn't mention earlier, but this Hidatsa pad, we actually had to mud up and have some weighted mud on it. So there's a lot of pressure there. You see that throughout the Williston from time to time. So very, very nice area. But I can tell you on the south side of the leg of Mandaree area, we have got some strong, strong wells. So if you look out over the next several years, we really like the inventory that we have. Obviously, we'd not see a little more depth, but we love what we have, and it's -- we're going to continue to see the Williston team deliver and put up some good numbers.

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Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [25]

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Okay, that's helpful. And maybe just jumping over to the Permian here real quick. Just trying to get a sense if you guys are planning on testing some of the different zones in the next 12 months. I know a lot of activity has been more focused on the Wolfcamp A. I guess, you've got a recent X/Y well that looks pretty good. Just -- can you kind of just give us the high-level landscape sort of some of the tests of the STACK (inaudible) might see over the next 12 months?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [26]

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Sure, Leo. I'll reflect back on 2017. We actually landed in 8 different benches. That was an important test for us. We want to do that early, get a single well in, put a state-of-the-art completion on it and then give those wells time to really understand shape of the curve, how do these compete. Now our gold standard is the Wolfcamp A. I would probably draw a bigger circle around it and say it's the Wolfcamp A and X/Y for a large portion of our acreage position. That's how we're developing it, and the returns on the X/Y as you see with the Lindsay, they can compete every day with the Wolfcamp A. So as that being the gold standard, what we want to do is give Second Bone, Third Bone, B, C, D Wolfcamps opportunities to kind of vie for capital. What we're seeing in some areas that some of these zones really do compete for capital. You'll see us feather in more Third Bone, maybe some Bs, especially in kind of our sand lakes area. That will be -- that'll have more competition for capital, and we'll start developing these as more the bigger flow units. And so I would say this year, we're probably 75% to 80% capital investment on Wolfcamp A and X/Y. 2019, I don't see that materially changing. But maybe we feather in a little bit more the Third Bone and the Wolfcamp Bs to round that out. And we'll continue to test. As we make breakthroughs, you find a new landing zone, and again I'll repeat what I've said several quarters. This is a high-class neighborhood with a lot of high-class neighbors. So don't think that we're doing this on our own. We're looking across the fence and learning from everybody around us, and that's how we've stumbled into some of these amazing new landing zones that we didn't even contemplate when we looked at the original acquisition. So -- but that's why we got into it. We knew there was going to be material upside, and we're really starting to embrace that and continue to benefit from that.

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Operator [27]

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Your next question comes from the line of John Nelson from Goldman Sachs.

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John C. Nelson, Goldman Sachs Group Inc., Research Division - Equity Analyst [28]

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Congratulations on the outstanding execution, and Rick, it sounds like you can use an [ambien] my friend. How should we think about the potential annual EBITDA contribution from your ownership in Oryx II and the Agua Blanca pipelines? And do the current ownership levels make sense to be held in your portfolio longer term?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [29]

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Kevin, go ahead.

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [30]

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Yes, I'd say from an EBITDA level, still yet to be determined if some of that -- some of these shippers start to firm up on each one of those pipes and how much that we're getting out of that. They're still building some of the -- they're still building the pipelines out. And as they start to get additional shippers, we'll start to see some of that come in. So I don't really have a good EBITDA number for '19. I think we just need to see how they -- the pace when which they get that build out, coupled with just how many shippers that they end to get signed up.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [31]

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John, I will say that we've been fairly transparent when we talk about our equity ownership here. We are an E&P company. We have looked at these as opportunity. Great investments. But at some point in time, there will be a monetization of those. We'll certainly retain the capacity and the capabilities for flow assurance, those are sort of things. But in our mind, it was just a great investment opportunity with the great -- a couple of great teams. And so that's our plan. And if you recall, we have a track record of doing that. We make the call early, we put the capital to work. And then we reap the benefits of that when we monetize. We've done that in both historically in San Juan and Williston basins in the past. And so I think you'll see the same thing here. And we expect to see some nice benefits, and I think shareholders are going to be very much rewarded down the road.

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

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I'll just add a bit of that, John, that we got in these opportunities because we needed to firm up our takeaway strategy. First and foremost, as Rick mentioned, we're an E&P company. Now the benefit of being an early mover, having these great assets and being opportunistic is it manifests itself the equity ownership. Now as I think about the equity ownership, I think there's 2 valuations. There is a valuation and maybe an exit point. Once you essentially fill the lines, you've sold out marketed the capacity, and it's essentially theoretical cash flow at that point. The second point is we starting growing -- start growing actual through the financials cash flow. The nice thing is there's markets for both. These are highly marketable assets. They're kind of sitting in our bank account right now. When we come to the right opportunity, we know that these are exercisable options. But as Rick mentioned, we'll still retain our first and foremost priority, which was the takeaway capacity and making sure that we're able to move the amazing commodities from this incredible resource.

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [33]

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Yes, and John I think getting back to your first question, I think as you start to see that EBITDA grow and you get an idea of how much, what the quality or how many shippers and what they're paying on that pipeline, I think what you'd expect to see from us is really optimize that value. When you get out there on that curve and you start to see the cash flows really start to come in.

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John C. Nelson, Goldman Sachs Group Inc., Research Division - Equity Analyst [34]

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That's very helpful. I'm less trying to kind of box you into 2019, but more to Clay's point and kind of what the pipes are sized for and kind of ultimately marketed for. So who knows when you reach it. But is something in the neighborhood of kind of $50 million to $75 million of EBITDA to net to WPX in the ballpark? Or can you just help us think about what could the cash flow from those assets potentially look like, whenever they do get filled?

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J. Kevin Vann, WPX Energy, Inc. - Executive VP & CFO [35]

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Yes, when you can buy the capacity of both of those pipes and where they're going to, I mean, you've got the Agua Blanca, it's going to grow to 500 million cubic feet a day just to us. So the pipeline (inaudible) you could see EBITDA being generated out of both of those assets of Oryx and you could see that growing to really well over $100 million, say, in the next 2 to 5 years.

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John C. Nelson, Goldman Sachs Group Inc., Research Division - Equity Analyst [36]

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And then as my second question, you guys have built a really differentiated firm takeaway position amongst the cement caps in 2019 for both oil and natural gas. Well, it looks like some of your peers might struggle. At the same time, Rick, you kind of alluded to in your remark your equity currency has materially improved recently. So can you just speak to how you think about potential consolidation opportunities within the Permian?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [37]

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Well, I guess, we think about that. The one consolidation of Concho and RSP transaction, I couldn't understand why that transaction happened. I think over time, it will probably be more appreciated in the market what it has been thus far. But I think at some point in time, some consolidation will take place. I think it probably would need to take place. From our perspective, we always have -- we have such a great -- these 2 assets we have, we have great inventory. We have to think how that applies to WPX. We have a very high bar. You never say never in this business. But my gosh, we have such a high bar. We have to be thoughtful about what we would do in that arena. Certainly, to go out and buy a lot of inventory, a lot of leasehold is not generating lot of cash currently. I don't know that, that appeals to me personally at this point in time. So just something have to be very, very attractive. But we -- there's not many of those assets when we compare it to our current asset base. And you have to be careful about falling in love with your assets, but I think we take a pretty critical eye with what we have here in house. And so once again just simply put, it's a very, very high bar.

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Operator [38]

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Your next question comes from the line of Brian Corales of Johnson Rice.

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Brian Michael Corales, Johnson Rice & Company, L.L.C., Research Division - Analyst [39]

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Most have been answered, but I'm just kind of looking into '19. How do you -- what are you all thinking right now on kind of rig count and rig allocation?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [40]

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Brian, we're just in early stages. Right now, I would say our base case, if you look growth profile and our capital discipline that we were employing, I think our base case is probably a flat rig count. We start from 7 in the Permian and 3 in the Bakken. We're getting better every day, and so the same 10 rigs will probably crank up more wells this year than what they did our next year than what they do this year. But we're going to have some sensitivities on that. Obviously, we want to be -- we've talked about cash flow neutrality in the next year close to that. So there's an element. Next year, we'll see what commodity prices are doing certainly. Our hedge percentage for next year is lower. Our volumes are higher. So we're going to have some pretty nice cash flow generating capabilities. We'll watch it, watch commodity prices. I think this base case is -- unless we see complete collapse in commodity prices, I think that's probably the kind of bottom range. But that's our base case. We'll go from there. The other thing I'll say is we will have a strategy session with our board. We always have as annual strategy session. We pressure test our assumptions, our business plan, look for holes, (inaudible) those sorts of things. We do that in mid-September. And so sort of by the time we get to November earnings call, we'll be ready to roll it out.

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Operator [41]

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Your next question comes from the line of Michael Glick of JPMorgan.

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Michael Adam Glick, JP Morgan Chase & Co, Research Division - Senior Analyst [42]

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My question has been answered, guys. Just good quarter and keep doing what you're doing.

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Operator [43]

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Your next question comes from the line of Matt Portillo of TPH.

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Matthew Portillo, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Exploration and Production Research [44]

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I know the vast majority of your capital focus in 2018 remains on your highest return and those capital-efficient assets in the Permian. But I was curious if you might be able to provide some updated color on when we might expect to see some delineation around your assets in Eddy and Culberson to get a better understanding of how those might fit into the capital program over the medium to long term?

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

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Yes, let's see. So how would I think about that medium and long term. So we have a -- I mentioned about 80% of our capital, essentially Wolfcamp A and Wolfcamp X/Y. And so that is what I consider kind of the development turning the crank multi-pad wells, long laterals, put oil in the tank part of our business. The 20%, we're still landing in other zones. We are -- we're doing some CDC work in other parts of the basin. We are testing and delineating kind of little bit lesser-known areas. The good news with the Permian Basin is there's a lot of activity. And so even if you don't see us dedicating dollars to a specific geographic area, it may be because we see others in the area that we have high confidence in essentially delineating it for us. As I think about going to the [North Lee] and Eddy, this is -- this is certainly the case there. We see some really good results. We weigh those results into. Again, our gold standard is Wolfcamp A, Stateline. Does it exceed that? Do we need to divert capital away? By far most of the time, that's still our gold standard. That's where you're going to see a disproportionate share of our dollars. And part of that is because of the amazing infrastructure we have and the cost benefit that we have in that particular area. Stepping out to Culberson that you asked about, to be frank, I think it's just -- it's not as exciting, it's lower return, it's gassier area. We certainly knew that's going into it. It was an extremely cheap exploration option. We continue to hold our hopes that the activity in the area is going to -- that's going to start firming that up a little bit more. But don't expect us to shift dollars out that direction in the foreseeable future just yet.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [46]

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Matt, it's Rick. One thing I may add. We talked about the Tucker Draw pad. That is actually in southern Eddy county. And so I can tell you those results rise to the upside, and we're excited about that. As you get farther up into Rustler Breaks, you'll probably hear us talk a little bit about that later in the year testing some things.

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Matthew Portillo, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Exploration and Production Research [47]

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Great. And then just a follow-up question. Just from a high-level perspective, as you trued up your capital budget, could you speak to the puts and takes on cost inflation views in the Permian? As you mentioned steel and some specific line items have been moving higher, but you're also in the process of adopting additional regional sand, and there may be some pricing tailwinds items like pressure pumping. So just trying to get a sense as you move into back half of the year, how are you viewing cost inflation risks? And if there's potentially any tailwinds, it might mitigate some of those costs going forward?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [48]

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Yes, we've definitely seen cost pressure as you look at '17, early '17 to now. Everybody has gotten back to work. I mean, you can look at the rig count. There's some very obvious pressure on the system. We identified the big ticket items that are relatively easier to lock down, and I mentioned those. Things like pressure pumping, rigs, water, sand, and we got very forward on a lot of those. Some other things that are harder to lock down and relatively smaller dollar items, things like steel, and we market that. We look at that from kind of a 6-month look, but it's hard to really kind of go out 18 months or 2 years on some of those items. Fuel is another one. Guess what, oil price is up. Fuel is costing us more to the tune of about $70,000, $80,000 a well. I will take that one. I'll take that hit. That's fine. The order once typically smaller-dollar items that are hard to contract on a longer-term basis. Things like coil tubing units, wireline units, some of the services that we have just on an immediate basis. You kind of need a coil tubing unit when you do, and you don't when you don't. And so to really lock one down and have it on 24-hour standby is typically not cost effective. So we've elected not to long term grab onto those guys. Now you're seeing some pressure in that. I would say overall, as we look at the well cost movement if we were $7 million probably late last year, we're probably $7.5 million to $8 million. And that varies from Stateline where I mentioned we have some cost advantages on those Stateline wells, these are 1-mile lateral Wolfcamps. You step out, you need to build more infrastructure. You're drilling single wells. Those wells may even approach $8 million, but I think it's kind of our range for the balance of '18 and out into '19. As you mentioned, there are some things working in our favor that could mitigate that. Rick mentioned, we're continuing to drill wells faster. We're still breaking through, trying to figure out how we do things better. That often translates into lower cost as well. It could mitigate some of that increase, but I would say to be on the conservative side, those are the numbers we're working from and thinking about as we move into '19.

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Operator [49]

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

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [50]

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Great. Clay, I always appreciate your macro level observations on the Permian and I think was couple of quarters ago, you described it as the storm was coming and the differentials could get really out of hand. That's obviously happened, and WPX is uniquely positioned to deal with it. And I'm really just kind of curious now and how you see the dynamics playing out with truck line capacity kind of nearing capacity? And really, if this does ultimately provide WPX some opportunity to take advantage of maybe some less prepared peers?

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

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Thanks for that. I think about it kind of 2 fashions. One, I think about the strategic alignment with our industry partners, meaning our service companies, the companies that we're symbiotically related to. They need us. We need them. And I think what we can offer them, and this is what I speak to appear at one of these companies. Essentially, my sales pitch to them is think of us as that forward-thinking steady partner that's going to be there and be efficient with your people and your resources. And so what that allows them to do is it gives us a little bit of a -- an edge in negotiating those agreements. And hopefully, we benefit from better quality, safer companies, better crews and, ultimately, better returns on the wells. As I start thinking about the macro environment, what's kind of the next few things for us to chase, what do we continue to do to stay ahead of, we're a long way from past the storm of the Midstream business. And so I still think a lot about oil and gas, NGL takeaway, and that's everywhere from the well all the way to the end market. I can tell you that the Midstream marketing team lives and breathes this everyday. And it's really fascinating to watch. I sit as a casual observer in a lot of these meetings, and how companies that are many, many, many times our size come to us, invite us to the table and really embrace us as a, I hate to say peer because I don't know if that's the way they would see it, but...

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [52]

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Thought leader.

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

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A thought leader. I mean it's somebody that I really appreciate the input from. I take that as a huge complement from some of these folks. I see it also as an opportunity for us. And so I think about how do we leverage those relationships, that understanding, the position, the good word, that good name that we have built into creating more value. There's always an opportunity in negotiations when you're doing land trades. Once again, hey, we've got a great marketing contracts, we can take your barrels, we can take your gas, we have this great relationship with Howard. We're essentially equipped to handle this. That often works very beneficially to our negotiation strategy. As we start thinking about more material acquisitions on a couple of sections or a part of the township kind of discussion, I think that folds in well. I think if you start thinking about bigger picture, the question back to Rick on M&A and that kind stuff, I think you have to build -- can we extrapolate our culture into embracing whole another piece of business. I think it's the same philosophy. I wish I could tell you we could recreate the contracts we built in 2016 and apply it to any one of our peers. It just that you can't do that today. It's not available. But the innovative and forward-thinking culture is scalable. And so that is something that we're really proud of and I think it's fairly recognized.

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Operator [54]

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Your next question comes from the line of Kashy Harrison of Simmons Piper Jaffray.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - Research Analyst [55]

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Just one really super quick one for me. Clay, do you have any color on what your Midstream partners are currently saying on the actual utilization status of these pipelines in the Permian today, both on the oil and gas side of the equation? Or are we effectively full at this point?

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

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So Oryx II is getting extended right now. And so a big piece of that comes online later this year. The Oryx I, that's essentially full. As I look to WhiteWater, which should be coming online essentially right now, that is contractually -- essentially full. So we don't have full on the gas molecule basis, but happy to report that, that is -- we've got signed up some really good partners, it's about 1.2 Bcf a day of capacity, and it's essentially spoken for.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - Research Analyst [57]

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And just on the bigger scale in terms of long haul out of the basin, any thoughts on the utilization of those pipes?

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [58]

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Well, I think they're pretty full, and then there may be some small amount of capacity. I've actually seen a couple of analyst notes that will speculate whether there's little more capacity than what may be the markets predicted. But I think our sense, of course, we've got plenty of room (inaudible), but I sense is that there is pretty tight.

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Operator [59]

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Your next question comes from the line of Gail Nicholson of KLR Group.

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [60]

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I'm just looking at the first half (inaudible) online in August. Can you just talk about the benefit of that and what that provides you in the second half of '18 versus maybe some of the peers don't have gas processing and ownership of that?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [61]

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I tell you, my prepared remarks, where it's a big deal for the JV, I can tell you, it's a big, big deal for WPX. Right now, our gas -- most of our gas for the Stateline area and the greater Stateline area travels west to a processing plant there. And because of the terms of the deal that we have with that processor, it's interruptible. We are if not the lowest one of the lowest paying customers. And what that translates into reality is as soon as they have a blip, any blip in the operation, we're the first one to get kicked out. And I can tell you, if it's an hour, it is a massive disruption to us. Because if think about what happens. They slam a valve shut. Our lines pressure up. Our compressors pop up from high discharge pressure. All that shuts in and then it just starts working its way back to wells. By the time the well gets shut in, now they say, okay, valves open, we're good to go again. We have to reverse course. And that can take 24, 48 hours, maybe even longer than that, to get those wells line back out. That happens routinely, maybe possibly weekly. Now contrast that, when we open our plant, we are a first in line, we are 50% owners. We will have much higher reliability and I fully expect, not just the reliability of the existing ability, the existing flow of the wells, but I know what we're going to find is, hey man, if you've just look this volatile section of a line, now you've got lower pressure differential and you're going to debottleneck this piece. Hey, if we had one more compressor here that will add capacity they are. And so I think what you'll see is it will be kind of burried into the base production, but you'll see that gas rates continue to improve, and that draws along the oil barrels. When you shut in oil because of the gas lack of ability for oil, guess what, you have to shut the oil in too. And so I think it's going to be an exciting time for us. It's not the day that you flip the switch. You see an extra x barrels per day. But over the next 6 months, you'll see us doing some of the the debottlenecking projects that really materially add to our base production. And by the way, that is part of this capital increase that we spilled out is anticipating some of these infrastructure, things that we will need to do that will have a massive impact on the base production.

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [62]

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Absolutely. And then just going back into the Williston, I mean North Sunday Island, a phenomenal area, '18 execution blowing the type curve out of the water, but '17 is also up outperforming that type curve, especially post that 60-day mark. And just looking at that, is that because you're -- exhibit -- are those wild exhibiting a shallow decline or kind of what's the driver of that outperformance post 60 days in the '17 well execution versus the tight curve?

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Clay M. Gaspar, WPX Energy, Inc. - President & COO [63]

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So you're peering into the one step beyond the gamesmanship that we can play on the side of the table. And I can tell you, you can manipulate a 24-hour IP in 1 million different ways. 60s, 180s, that's just the reservoir rock. That is how well the teams executed on the opportunity they had and how good the rock is. And so as you're noting, the results from 2017 in a flatter decline that's exceptionally good production engineering and field operations, thinking about that artificial lift, doing some of the debottlenecking, making sure everything in place it was all the way back to the phenomenal geology and then the execution on how we drill, complete and equip that well from the beginning.

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Operator [64]

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And so this includes today's Q&A portion of the call. I'll turn the call back over to Rick Muncrief, Chairman and CEO.

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Richard E. Muncrief, WPX Energy, Inc. - CEO & Chairman of the Board [65]

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Well, thank you very much for joining us today. I know we went a little long. But we did a lot of great questions, a lot of discussion. We always enjoy this opportunity to share our thoughts with the investment community and analyst. And so with that, will conclude the meeting. Thank you very much. Have a great day, and we appreciate your interest in WPX.

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Operator [66]

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This concludes today's conference call. You may now disconnect.