WPX Energy (WPX) Q3 2016 Results - Earnings Call Transcript

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About: WPX Energy, Inc. (WPX)
by: SA Transcripts

WPX Energy, Inc. (NYSE:WPX) Q3 2016 Earnings Call November 3, 2016 10:00 AM ET

Executives

David Sullivan - WPX Energy, Inc.

Richard E. Muncrief - WPX Energy, Inc.

Clay M. Gaspar - WPX Energy, Inc.

J. Kevin Vann - WPX Energy, Inc.

Analysts

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Subash Chandra - Guggenheim Securities LLC

Brian Michael Corales - Howard Weil

John Nelson - Goldman Sachs & Co.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Kashy Harrison - Simmons & Company International

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Robert L. Christensen - Drexel Hamilton LLC

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Jeff L. Campbell - Tuohy Brothers Investment Research, Inc.

Gail Nicholson - KLR Group LLC

Operator

Good day, ladies and gentlemen, and welcome to the WPX Energy Quarterly Report and Operations Update Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time.

I would now like to introduce your host for today's conference, Mr. David Sullivan, Director of Investor Relations. Mr. Sullivan, you may begin.

David Sullivan - WPX Energy, Inc.

Thank you. Good morning, everybody. Welcome to the WPX Energy Third Quarter 2016 Update Call. We appreciate your interest in WPX Energy. Rick Muncrief, our CEO; Clay Gaspar, our COO; and Kevin Vann, our CFO, will review our prepared slide presentation this morning. Also along with Rick, Clay and Kevin, Bryan Guderian, our Senior Vice President of Business Development, will be 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 10-Q will be filed later today. Please review the forward-looking statements and disclaimer on oil and gas reserves at the end of the presentation. They are critical and important to our remarks. So please review them.

So with that, Rick, I'll turn it over to you.

Richard E. Muncrief - WPX Energy, Inc.

Thank you, David. Good morning to everyone on the call. Glad you're with us today. I believe this is a perfect time to follow WPX. For all intents and purposes, we've just completed a major transformation of this company. At this time, I want to recognize everyone here at WPX for their tireless determination and their willingness to accept the challenges that not only the market but also our leadership team placed in front of them. Very simply, thank you.

Over the past two years, we did everything we said we'd do. We stripped our house down to the studs and rebuilt everything, including our portfolio and our culture. But that's only the half of it. Now I want to draw your attention to what we're going to do for an encore. And if you look at our track record, you should have very high expectations because we certainly do. In my mind, the next two years are going to be just as big in terms of what we can accomplish. We're at another turning point and we're making that pivot every day. I call it WPX 2.0. You'll see examples all through the slides today of what I'm talking about.

We're talking about something that's measurable, meaningful and sustainable. We're doubling down on our vision, a future that we built with bold, shrewd moves and our entry into the Permian Basin where we're surrounded by high-class neighbors. Over the next two years, we're planning to double our oil production and cut our leverage and G&A metrics in half. That's right, all that in 2017-2018. It means boosting oil by 25% next year and by 50% in 2018. If you're an investor, that's very compelling. And if you work here at WPX, you're thinking we can do that.

Let me put this in perspective. When we overhauled this company, it was like building a brand new muscle car, the kind that you can't wait to show off, kind of like a next door neighbor's cobra. When oil prices crashed, we tightened our belt and did some more fine-tuning, kept working under the hood, but mostly kept the car in the garage. Now, because we're a strong financial because of our willingness to bring value forward because of the horse power we have in all three of our basins, we're ready to rev up the engine a little and hear some of that thunder in the tailpipes.

Now, does that mean that we're off to the drag races? Hell no. Hear me clearly on this. Our plan is based on following the speed limit. We're talking about an 8-rig program next year, not 18 rigs or 28 rigs. I believe that we can achieve our goal because we've rebuilt WPX on a three-pillar bedrock of accountability, employing a biased fraction and driving continuous improvement.

First, we tell people what we're going to do. Second, we don't stop until we get it done. And third, when we finish it – when we cross the finish line, we're onto the next race and finding ways to improve our times and recurrence. Have we accomplished a lot? You bet. Is there still plenty to do? Absolutely. But we love a good challenge and we take notice when people challenge us.

For example, the first time we ever talked about aiming for 100,000 barrels of oil production a day was on a call just like this about 18 months ago. To be fair, it was sort of a flipped remark, but I wouldn't have said it if I didn't believe that we could do it someday. Now there was some friendly chatter about it during the Q&A and the idea of it was somewhat dismissed and even referred to as far-fetched. Well, far-fetched won't be a stretch if we keep executing. The engine's running and we like the sound of what we hear.

Let's turn to page 2. Here's the examples of what we're doing in the garage as we start to put more barrels in the tanks. We know we live in a show-me world and it's incumbent upon us to have a show-you team. And this is how we're adding value and pushing the limits of what's possible. The thing I want to point out is that we're just starting to realize the benefits of shifting our portfolio from gas to oil and from the Piceance to the Permian.

And as we're learning, our Permian story just keeps getting better. Clay will walk you through a lot of details. From a big picture standpoint, this is the framework we've been working together to grow volumes in the Permian. We're actively assessing several different intervals and we keep chipping away at more acreage at very reasonable prices.

In our other two basins, our results are also very, very impressive. In the Williston, we've had recent IPs of more than 3,000 barrels equivalent per day with oil cuts up to 90%. In the San Juan Gallup, we've seen IPs of more than 2,000 barrels of oil equivalent per day with oil cuts of 70%. So, overall, I feel we had a solid third quarter even with an expected trough in production. Things have already picked up in the fourth quarter and will create that momentum into 2017.

Let's turn to page 3. When you hear us talk about accountability and continuous improvement, here is where that translates into actions and dollars. Two years ago, we said we'd simplify our portfolio. We said we'd high-grade our assets. We said we'd shift to oil and we said we'd put our dollars to work in the best areas. We also said we'd address our cost structure.

And here's the outcome of all that. We have attractive returns and great opportunities across all three of our remaining basins. We also have a financial flexibility to double our capital expenditure next year into 150 to 160 spuds in these areas. These drive value forward and provide for near-term growth, all of which is consistent with our long-term plan.

We also have a balanced portfolio that allows us to withstand extremes in commodity prices. Look, there's always going to be a question about commodity prices and what they're going to do. Our plan assumes that oil is going to stay in the $50 range for oil and $3 for gas for the next few years. If something changes, we'll simply do what's necessary and stay true to our disciplined approach. Yes, our goals are aggressive, but we'll temper that with being prudent and flexible.

There always will be debate on whether to move sooner or later. For WPX, all I see is a window of opportunity that's right under our noses now. That's the pivot I'm talking about, getting back to work in all our basins.

Now let's turn to page 4. I really love our forward story. We have built WPX for the long-term. We have scalability, decades of drilling and the financial flexibility we need to meet our goals. I have to say that this plan assumes adding no incremental debt or tapping the equity markets for that matter.

Our goal is to be cash flow positive in two years, grow oil volumes and EBITDAX with a compounded annual growth rate of 20% to 35% through the year 2020, and fund our growth with our cash that we have on hand and our cash flow from operations.

Now let's turn to page 5. When we look at these numbers internally, we think, wow, this is exactly why we're here. This is what we want to accomplish. Those four green bars in each of the charts are the greatest and most exciting growth trajectory in our company's history. And keep in mind, our plan only contemplates modest rig additions year-by-year. We're not even talking about going pedal to the metal.

We were excited when we rolled out the first version of these charts at the Barclays Conference in September, but the numbers we're showing today are stronger and go even further. This update comes just two months after the first time we crunched the numbers.

Here's what I want you to remember. Yes, our portfolio has a lot of capacity for growth, but more importantly that capacity has staying power. We have more than enough drilling inventory to drive value right now as well as further down the road.

Turning to page 6. Clay is now going to walk you through our operations. Clay?

Clay M. Gaspar - WPX Energy, Inc.

Thank you, Rick, and good morning, everyone. First, let me just say that Rick's intro was spot on. The tangible and visible changes to our portfolio gained a lot of well-deserved attention, but it cannot be understated how much we've changed below the external radar in regards to our culture. I'm so proud to work with this team and I can't wait for WPX 2.0 to become publicly visible. From my seat, I see a strong financial foundation, an amazing set of assets and a team poised for growing shareholder value.

With that, let's turn to slide 7 and take a look at our incredible Delaware resource. As we lay out our 2017 capital program, I thought it would be a good time to update everyone on our resource stack in the Delaware. Currently, there are 11 proven productive zones across our acreage. These intervals are in the Delaware Sands, Avalon, Bone Spring and Wolfcamp formations.

While we were only running two rigs in the basin for much of 2016, we mainly focused on the Wolfcamp A. This allowed us to get our drilling techniques in line with the best out there and also push our completions through a much-needed evolution to embrace and even raise the bar for industry best practices.

We have also continued to progress our understanding of many of the other intervals via our participation with or close monitoring of our offset operators. We have also begun to selectively test other very promising intervals. I will tell you more about the early results from the Wolfcamp D and the X/Y test on the upcoming slides.

In the second half of 2017, we plan to drill our first Wolfcamp C well. After that, we will likely be testing a third Bone Spring well. We have so much ground to cover just working up and down this incredible stack of rocks. As an example, I will talk specifically about a Wolfcamp A spacing project in a couple of slides.

The challenge for the team will be continuing to do the important science work required to formulate the ultimate development strategy and, at the same time, deliver on the production growth required to maximize present value from this major piece of our business.

Now, let's turn to slide 8. I'm excited to show you the results from our first two 1-mile D wells. These were drilled in the Stateline area, one in the northwest and one out to the east. Both wells are showing strong initial performance. The oil and gas rates are impressive, but the flat nature of the decline and the very high flowing pressure will drive some really impressive EURs. These wells will continue to flow at these rates for several months. Ultimately, we'll need a few months after the wells start to decline before we can establish a reliable type curve.

The good news is, normalizing these rates and pressures to offset operators gives us great confidence that these zones will compete for capital in our very strong portfolio. The green outline on the map shows where we believe the D is prospective, which covers our entire Stateline and Rustler Breaks areas. These are the two areas that we've been successful in adding to our core acreage position.

Let's turn to slide 9 and talk about our first X/Y well and our upper/lower Wolfcamp A basin test. On our last call, we announced a significant acreage acquisition in the Rustler Breaks area. Now, on this call, I'm pleased to share with you X/Y well results from that acquisition. As an aside, I think this is the perfect example of Rick's opening comments around our bias for action. One of the keys to success for any acquisition is timely development of that asset. At 87 days from closing, we permitted, built facilities, drilled, completed and began flow-back. That is action.

Early time results of this 1-mile X/Y well show a 24-hour IP of over 1,800 Boe a day with 70% of oil. These are very impressive early time results and are consistent with the X/Y results of offset wells in the area and show why we were so excited about this acquisition. Based on these early results and confirmation of our acquisition thesis, we plan to drill approximately 15 X/Y wells in 2017. Again, that is action.

Also in the third quarter, we began a nine-well spacing test in the upper and lower Wolfcamp A in the Stateline field. We are on track to spud the ninth well in late November and begin completing in January. We should see initial production from these wells in late February. Right now, we have all three of the Delaware rigs drilling this pilot.

As I mentioned earlier, it's critical that we understand the proper spacing in each zone. This test will hopefully validate our 16-well DSU assumption for the Wolfcamp A. We will come back later to drill the four X/Y wells and determine future spacing in the X/Y formation. As a result of this large group of wells coming on at one time in late Q1, we will have a nice bump in production in 2Q 2017. The downside is that Permian production will be relatively flat in first quarter 2017. This lumpy production is normal impact of just moving to more pad development.

Let's turn to slide 10 and I can update you on the Williston Basin. In late August, we began completing DUCs and the second rig arrived in late October. During the quarter, the Williston team set a new drilling record of 11.9 days spud-to-rig release. That record is a great example of what our drilling team is doing across the board. When you multiply that efficiency times our 17-rig count, you'll end up cycling through quite a few wells. That well count drives higher 2017 production guidance and the massive growth in 2018.

As you can see from the table, the recently completed DUCs are performing in line with the results of our previously released Emma Owner and Mandaree pads. We should catch up the backlog of DUCs in the first quarter of 2017 and then have a steady stream of new wells to complete from the two rigs.

Now let's turn to slide 11 to talk about San Juan. Last year at this time, I broke one of my cardinal rules regarding talking about well IPs, without having the full context of what the early data is really telling us. I did this because I was so excited about what we were seeing from the changes we made to the San Juan drilling program.

Well, in this case, one year later, because of the continued great technical work by the San Juan team, I'm just as excited about the continuing performance. The top graph shows year-over-year improvement in the well performance in Gallup. From 2013, EURs have improved approximately 140% and just since last year they have improved 65%.

The results from the West Lybrook pad are indicative of those improving results. With 70 to 90 days of production, the West Lybrook wells are all performing above our 650 MBoe type curve. Also, the West Lybrook pad is showing higher oil cuts of about 70% on a three-stream basis. The capital allocation process around here is not an exercise in charitable giving. These results and this team have earned this capital that is being directed to them.

Let's turn to slide 12 and I'll give you a brief overview of 2017 operational plan. I'm excited to get our 2017 guidance out earlier than we have in prior years. It allows us to lock-in programs with our vendors and provide them some much-needed clarity. We're planning to run eight rigs in 2017; five rigs in the Delaware, two rigs in the Williston, and one rig in the San Juan Gallup. All eight rigs will be on the ground and turning to the right by mid-December.

As I previously mentioned, with the great work of our drilling team and their key vendors, these rigs are becoming super-efficient. We continue to increase lateral length in every basin we operate. In the Delaware, approximately 40% of 2017 wells will be long laterals, meaning 1.5 to 2 miles. The resulting average lateral length in Delaware will increase 35% year-over-year.

In the Permian, we plan to drill about 75 wells. The primary focus of 2017 will be drilling the Wolfcamp A and the X/Y. Also, we plan to drill some wells in the Wolfcamp C and D and also in the Second Bone Spring. In the Williston, we plan to drill about 40 wells, and in the San Juan Gallup, a little over 40 wells.

This is certainly an uptick in our activity. But because of the less visible but incredibly important organization process work we've been doing during the downturn, we are ready to get back to work. As our activity picks up, our focus will remain on continuous improvement and driving shareholder value.

Now let's turn it over to Kevin for the financial update.

J. Kevin Vann - WPX Energy, Inc.

Thank you, Clay. As you've seen in the slides and heard in the remarks, all eyes are on 2017. We believe it's going to be yet another breakout year for WPX. 2017 should also be a simpler, cleaner year on our books.

As Rick mentioned, our transformation process is basically done. With that, we're also winding down how that activity is impacting our financial results, from asset sales to severance and relocations costs. You've seen those items impact our results throughout 2015 and 2016 as we reshaped the company. These items impacted our third quarter results as well, but they shouldn't overshadow the tremendous results that we're seeing from our operations that Clay discussed.

We're doing outstanding things in each of our areas, and our strong financial position is going to make more and more of that possible. Today, we've laid out a reasonable yet remarkable trajectory, projections that assume moderate commodity prices and incremental rig additions, while funding our growth without adding any incremental debt.

Our management team has stacked hands on this and we believe it's a meaningful, disciplined way to move the company forward and reward our investors both now and in the future.

Let's turn to slide 14 and take a look at the third quarter results. As I just mentioned, the third quarter was yet another quarter where our results were impacted by a few items that are attributed to our portfolio transformation. For the quarter, our oil production is 15% higher than for the same period of 2015. The increase in our Delaware production is driving this increase.

When comparing to the second quarter of this year, our Delaware oil production rose slightly to over 14,000 barrels per day. Overall, our oil production was marginally down versus the second quarter, as well completions in the Williston Basin did not recommence until August. We will begin to see the benefits from these completions during the fourth quarter.

At approximately 205 million cubic feet per day, our natural gas production for the third quarter was up 11% over the second quarter of 2015. Again, this increase is driven by the additional volumes being generated out of the Delaware.

At over 84,000 equivalent barrels per day, our production is 16% higher than last year and relatively flat since the second quarter of this year. Again, the decrease in activity in the Williston was a major contribution to the flat volumes when looking at the comparison to the second quarter.

For the third quarter, we are reporting an adjusted EBITDAX of $115 million, which is $80 million lower than the third quarter of prior year. Although production volumes were higher than prior year and realized oil prices were only slightly down, the reduction in EBITDAX is primarily driven by the lower realizations on our commodity hedges. The lower prices from our realized hedges accounted for $97 million of the decline.

Also reflected in this quarter's results are the impact of $3 million in severance and relocation costs associated with our efforts to size the organization, commensurate with the remaining portfolio. In addition, this quarter reflects the final month's impact of excess transportation capacity that was retained after the closing of our Piceance transaction.

The financial impact to the third quarter of $6 million is reflected in gas management activities on the income statement. These activities ended at the end of July, commensurate with the closing of the transaction to buyout of the remaining agreements. A charge of $238 million was recorded during the quarter to reflect the impacts of that buyout.

For the quarter, we are reporting an adjusted net loss of $59 million versus a net loss of $10 million in 2015. The decline was driven by the same factors impacting adjusted EBITDAX, but also by higher depreciation, depletion and amortization in 2016, which primarily related to DD&A recorded for Permian on higher recorded production. Lease operating expenses were also higher this year due to a full quarter of activity in the Delaware.

Our capital expenditures incurred for the third quarter totaled $160 million, which included costs incurred to add acreage in the Delaware. On a year-to-date basis, our total CapEx of $424 million includes $60 million of land acquisition cost and $27 million of Piceance expenditures that were reimbursed to us by the buyer of those assets. The projected capital spending for drilling and completion activities remains in line with our guidance of up to $450 million for the full year.

Turning to slide 15. I want to touch on a couple of points regarding our liquidity, debt maturity and strong hedge position, as our activity increases and production profile grows. First, as you see, our liquidity remained strong. During the quarter, we did use a portion of the cash that was on hand at June 30 to buy out of the remaining Piceance transportation contracts as well as fund the acreage additions in the Delaware. With those transactions considered and the payment of the remaining balance on our 2017 bonds, we still have pro forma liquidity of over $1.5 billion.

Recently, our borrowing base of over $1 billion was reaffirmed through a redetermination process. As Rick mentioned earlier, the cash that we have on hand is adequate to handle the funding needed to support our 2017 and 2018 drilling and completion needs.

Our hedge position for 2016 remains strong. We had approximately 80% of our anticipated remaining oil and natural gas production hedged at over $60 per barrel and $3.93 per MMBtu. For 2017, we now have nearly 35,000 barrels of oil hedged at $51.45 per barrel. On the natural gas side, for 2017, we have 170,000 MMBtus per day hedged at $3.02.

With the projected program over the next two years, we continue to layer on more commodity price protection in 2018. For 2018, we now have 20,000 barrels per day of oil hedged at nearly $57 per barrel and 60,000 MMBtus per day of natural gas at $2.93.

As Rick mentioned earlier, our growth is aggressive; however, we will do so prudently and responsibly. The hedge book we have compiled for 2016, 2017 and 2018 demonstrates our discipline to managing the balance sheet. Lastly, I will once again point out that after paying off the remaining balance of $125 million on our 2017 notes, we do not have another debt maturity until 2020.

Turning to slide 16. We are excited about our guidance for 2017, which grows oil production by over 25% and overall production by approximately 20%. We are guiding to a production range of 96,500 to 107,000 equivalent barrels of oil production per day. Of this amount, our oil production is expected to be 49,000 to 53,000 barrels per day. We will accomplish these production results through a drilling and completion capital program between $800 million and $860 million.

We continue to maintain operational flexibility, given minimal rig and drilling commitments throughout our portfolio. As Rick mentioned earlier, in additional to delivering 25% oil growth in 2017, the development program sets the stage for 50% oil growth in 2018.

As you can see on this slide, half of our projected capital will be deployed into developing our Delaware position. As production from the Delaware becomes a higher percentage of our overall portfolio, certain consolidated items like price differentials and production taxes will continue to decrease.

Cash operating expenses, which includes lease operating expenses, gathering, processing and transportation and severance taxes, should average between $9 and $10.50 per unit for 2017. Lastly, I will point out that non-operating expenses on a per equivalent barrel basis, including G&A and interest expense, are projected to decrease by approximately 28% next year.

Over the last couple of years, you've seen the strength in our liquidity and balance sheet by restructuring our credit facility, executing one of the strongest hedge positions in the industry, and opportunistically issuing equity as our returns and growth potential came into view. You've seen us lower costs across the board. You've seen the recent well results from our operations teams.

What you will see next out of the WPX team is the most exciting chapter yet. I have a front row seat to watch it all. I hope you buy a ticket as well because I don't think you will want to miss it.

Now I'll turn it back over to Rick.

Richard E. Muncrief - WPX Energy, Inc.

Thanks, Kevin. Good job. Turning to slide 17, closing slide, our transformation is complete. We've turned the page, we're making the pivot, and we're ready to rev the engine. We also recognize that the value in our strategy comes down simply on how well we execute. It's on all of us here at WPX to make that happen.

Now we've been tested before, and we were up for the challenge. We pushed more than a dozen deals across the finish line with a combined value well in excess of $5 billion over the last two years just to get to this point.

We've also beefed up our technical and operational focus. We've changed our flagship asset. We have a winning mindset. And we're in a position to compete with the best of the best.

Some companies change their names and call it good. Here at WPX, we changed everything except our name. But our new identity and the goals we're pursuing couldn't be more clear.

And at this time, we can open up the line for questions, and I'll turn it back over to the operator.

Question-and-Answer Session

Operator

Thank you. And our first question comes from Neal Dingmann from SunTrust. Your line is open.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Morning, guys. And nice to have a ticket to watch this car change so dramatically, Rick.

Richard E. Muncrief - WPX Energy, Inc.

Good morning, Neal.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Say, Rick, for you or Kevin, just wondering on that, the plan you have basically gives you increased activity but ultimately is going to end up lowering your leverage. How dependent on that, it doesn't appear to be, but how dependent on that is commodity prices?

Clay M. Gaspar - WPX Energy, Inc.

Neal, what we modeled is a pretty – actually, you continue to chase strip around, but really the projections that we're using right now just include basically strip pricing, $50 oil pricing in 2017, and roughly $55 oil price in 2018.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. Okay. Makes sense. And then just maybe lastly for Clay, looking at that slide nine and how successful – just wondering how the success will be on the upper/lower Wolfcamp A density test? Depending on that, Clay, how will that change drilling plans for 2017? And any idea if that is successful as one might think, how many locations in maybe broad terms that could add?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. I think that's a great question, Neal. You're always wishing you had the answer before you had to do the work. And so, as we ramp rigs, we're able to do more of these pilot programs to really understand well interference, what's the right completion, what's the right well spacing, even the staggering from lower/upper Wolfcamp landing zones. As the X/Y comes into play, how that ultimately ties in with the Wolfcamp A development.

So we fully expect that things will evolve. I think what we have currently spelled out in the well count is eight wells in the upper, eight wells in the lower, four wells in the X/Y. That's our base assumption. We're essentially validating that base assumption. If something were to change, then obviously we could scale that up or down accordingly. But ultimately we're trying to extract optimal value and not necessarily just well count.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Makes sense. Thanks, guys.

Richard E. Muncrief - WPX Energy, Inc.

Hey, Neal. This is Rick. One thing I'd like to interject, if I could, is on your question about the dependability on commodity prices. I think one of the things that we've kicked around here, especially even since the Barclays Conference in September, was the fact that we're seeing better and better returns. We're going to have a higher percentage of longer laterals in our plans over the next couple years.

So, when you step back and look at it, we think that unless we think that crude is going to stay in the low 40s, I'd say $42 to $43 for six to nine months, something like that or longer, then I think we may want to step back and look at it. But if you really look at our plan with our hedge position that we have and the economics that we're getting, we feel very good about the strategy and going forward.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great add. Thanks, Rick.

Richard E. Muncrief - WPX Energy, Inc.

Thanks.

Operator

Thank you. And our next question comes from Subash Chandra from Guggenheim. Your line is open.

Subash Chandra - Guggenheim Securities LLC

Thanks. So how did water volumes vary at all – formation water volumes vary at all between the X/Y, the D, and the A?

Clay M. Gaspar - WPX Energy, Inc.

Hey, Subash. This is Clay. Yeah. The Delaware Basin is known for water volumes and we see across the board roughly 3:1, maybe 4:1. We haven't seen a huge variation from that. The D has a little bit higher than that, maybe 5:1, but nothing like we've seen in some of the other areas where you get kind of a 10:1 ratio.

The good news for us, and this is something very important, when we made the RKI acquisition, there was a major water infrastructure business already in place. The full capacity is about 200,000 barrels a day. We're still using roughly 100,000 barrels a day of it. And so, that water handling capability is becoming certainly a core competency for us, and I think anyone that wants to work in the Delaware Basin really has to be able to source water and dispose of water efficiently and effectively.

Subash Chandra - Guggenheim Securities LLC

Yeah. Thanks, Clay. And my follow-up for you is, could you describe maybe some more the differences in rock characteristics in the D because we sort of get this kind of a two-dimensional IP. I get there's a lower oil ratio, but was it tougher to – was it a lower net to gross? Was it tougher to drill? Was it tougher to stay in the zone? Things like that.

Clay M. Gaspar - WPX Energy, Inc.

The D is actually one of the thickest intervals the way we map it out, and of course everybody has their own definitions. We've tried to abide by what we think is mostly the industry standard. The D is actually several hundred feet thick. We're probably in the upper portion of that D.

What we've noticed – you'd notice instantaneously, it does drill differently. It drills a little slower mainly because we have significantly higher mud weight where we're talking about a 16-pound per gallon core environment. So a lot of reservoir pressure. And that just changes the dynamics on weight on bit design, how you're pumping your fluids. So, really that has been kind of a work in progress.

We've TD-ed our third D well now and really feel like we've turned the corner on some of that. I'd tell you the first half of that third well was drilling pretty slow. By the time we TD-ed the lateral, we felt like okay, we've kind of got the right recipe now. And some of it was a little bit different dials than what you would do in a Wolfcamp A.

How does that translate into value? I think the biggest thing is when you look back at those plots on Wolfcamp D, don't miss that pressure plot. That is incredibly important. 4,000 to 5,000 PSI flowing casing pressure on these initial flow-backs and how that's hung in over time is going to be really, really important on ultimate recoveries. And so, that's something we're really excited about.

The dynamics of how these wells flow over time, having the lower oil cut, you probably have a little different artificial lift mechanism. You'll have a little different B factor in decline. And so those are some of the things we'll learn more about as we watch kind of 180 days or 360 days into these wells. The good news is we have some really great offset operators that are drilling some really fabulous 2-mile laterals and we're very much in line with that pressure rate normalized, lateral length normalized results on our Stateline area. So, pretty excited about the early results.

Subash Chandra - Guggenheim Securities LLC

Thank you.

Operator

Thank you. And our next question comes from Brian Corales from Howard Weil. Your line is open.

Brian Michael Corales - Howard Weil

Good morning, guys. And good update you provided this morning.

Richard E. Muncrief - WPX Energy, Inc.

Hey, Brian.

Brian Michael Corales - Howard Weil

If we look at – Rick, in your previous presentation, I guess, just a couple of months ago, it looks like your guidance is on the high-end of that range. Did something change in those last couple months or were you being conservative? What's kind of the thought process there?

Richard E. Muncrief - WPX Energy, Inc.

Well, there have been some changes – I'm going to let Clay add a little more color to it. But there are some changes around the percentage of lateral length and our some efficiencies that have driven our CapEx up in 2017 over more than what we got it to a couple of months ago. But I think the end result is better economics, higher growth rate, and that will really play out in a big way as we enter into 2018.

Clay, why don't you?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. I would say the other thing is you'll see a corresponding uptick in capital. And the way I see that is the rigs are becoming much more efficient. As Rick mentioned, drilling longer laterals, but also cycling through those laterals and those well bores in quicker fashion. So you're seeing more completions, more capital. As a result, you'll see significantly higher 2017 and even more significantly higher impact on 2018. So, really excited about seeing where we are in those stacking out for the guidance.

J. Kevin Vann - WPX Energy, Inc.

And Brian, I think one thing, as you think about 2018, given the payback periods and just the returns that we're seeing on these wells, that helps drive your leverage metric even lower by the end of 2018.

Brian Michael Corales - Howard Weil

Okay. No, that's helpful. And then, one, I mean we've been hearing all earnings season about guys using more sand in the Bakken and they're getting better wells, where I guess your recent wells in the Bakken used only 6 million pounds. Did you all do something different on the completions?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. It's one of those complicated – it's not just pounds of sand. I know we love to simplify it and talk about, hey, more is better. And generally, I'm right there with you. I agree. And we're watching very closely what a lot of those guys are doing, and we're cheering for them because we love to see people kind of break into new territory. And the day that I say we figured it all out and we're done innovating, I'm done. And so I think it's incredibly important that we continue to evolve.

If you align back to our history, we moved from about a 3 million pound design up to about 10 million pounds. We've even pumped a little higher than that, close to 11 million, 12 million pounds on the highest. And so, when we pushed that, when we started doing really some tests on our acreage position to see where does that point of diminishing returns really occur. And what we think from our position and our pump design, with the tweaks we're making, that we can kind of optimize somewhere around 6 million to 8 million to 10 million pounds. And it does vary a little bit on thickness and area of the reservoir. That doesn't mean that if you're pumping 13 million pounds in a different part of the basin that that's the wrong move.

And I can tell you we'll continue to evaluate. We'll watch these guys. We continue to push our own teams and challenge what's happening across the fence. But ultimately it's not – at some point, there is a point of diminishing returns, and at that point we start dialing back and saying, okay, where do we get similar production for less cost. And that's where we've been toggling in our Williston development.

Brian Michael Corales - Howard Weil

All right. Thanks, guys.

Richard E. Muncrief - WPX Energy, Inc.

Thanks, Brian.

Operator

Thank you. And our next question comes from John Nelson from Goldman Sachs. Your line is open.

John Nelson - Goldman Sachs & Co.

Good morning, and thank you for taking my question.

Richard E. Muncrief - WPX Energy, Inc.

Hey, John.

John Nelson - Goldman Sachs & Co.

The investment community has I think recently become more concerned or at least more focused on potential Permian bottlenecks over the next 12 to 24 months. I guess I had two questions. One, do you have any plans to enter agreements to get your oil out of the basin or invest in natural gas processing plants?

And two, as I think about WPX, I think you're in a unique position given that your Bakken wells can actually offer almost just as attractive rates of return. So can you speak to what extent maybe the capital allocation process stays real-time and what flexibility you would have to potentially shift capital over the course of 2017?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. Sure. I'll start with the infrastructure question first, John. As we look, again, going back to what we inherited from RKI was an incredible water system, which is as important as any other system because if you can't get water or dispose of water, you can't do much else. We also inherited a very significant gas gathering system. That was very beneficial.

And as we've talked about, we're now under construction on an oil gathering system as well. That gathering system could have as many as four takeaway points to different pipes. We're in a really unique spot that we have all the major shippers come right through our area. So, within the 3 or 4 miles of the Stateline area, we can tap into some very significant transport.

So we're working those agreements and those conversations right now. We're also looking longer-term. I think where our interest really is today is kind of the challenges maybe three years out, as Permian grows not just on the Delaware side but on the Midland side, and now you start seeing Midland crane potential bottlenecks. So how do you preemptively move there? And we're looking at that very well.

I think, on the gas side of the equation, the gathering's in place. We're continuing to expand and reroute that gas to eliminate bottlenecks. You mentioned the processing. We're always in conversations to expand our processing capabilities and, as we've mentioned before, we would consider other opportunities as well. And there's certainly no shortage of folks coming to us looking for some kind of partnership opportunity.

And then, I'm sorry, John, can you repeat your second question? It was on the Bakken...

John Nelson - Goldman Sachs & Co.

Yeah. Sorry, it was long-winded but more or less to what extent can the capital allocation process stay real-time, as those bottlenecks potentially show up, shift activity up to the Bakken?

Clay M. Gaspar - WPX Energy, Inc.

Yes. John, I mean, we love to say around here, it's great. The guys that are rewarded most are the single basin players and the guys that are rewarded the least are the single basin players, just depends on your current view of that particular basin. So we're real big believers in having a couple of different outlooks.

We're making sure that those basins really understand the competition for capital. And I would say all three are competitive. They all have their strengths. They all have their challenges. And having that flexibility as you go into negotiation, either internally or externally, to say hey, we can divert those dollars. We can scale up. We can scale down. We can shift dollars over. We're running five rigs in the Williston Basin.

Of course, rig's history, they can run – these run a heck of a lot more than five rigs in the Williston Basin. And so we have those capabilities. I would say our pressure on the Permian right now is we need to build that base of understanding. It's such a huge piece of our portfolio that we'll need to continue to develop it and really understand how it fits not just from the Wolfcamp A, but up and down the whole. And so, that's really where our interest lies. Thankfully it's really stout economics, but also we have a high desire to really understand that stack of rocks.

Richard E. Muncrief - WPX Energy, Inc.

Hey, John. It's Rick. I think I would add that that was why it was so important for us to lay out really a five-year plan at this point and start talking about the relative contribution and expectation of each business unit.

But we've got that flexibility and we can move capital very quickly. It's very gratifying to me to see these asset team leaders fighting for the capital and they're all – for instance, we're talking about adding a second rig in the Bakken, but I can tell you the Bakken guys would like to have rigs three and four. The Gallup guys would like to have rigs one and two, and that's one but rig two as well.

So I think we can do that, keep capital real-time if we need to. That being said, I think we are in really a very, very enviable position with our takeaway across the board over the next several years.

John Nelson - Goldman Sachs & Co.

That's really helpful. And then I guess, I know you just gave 2017 guidance which was earlier than expected, but could you just give us some color, and maybe it's a big ballpark, what level of CapEx would be needed to hit that 2018 50% oil growth target?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. So it's basically mimicking the 5:1 that we have in 2017, rolling that into the 2018 and then, at some point in the program, probably adding a couple more rigs, say one to three. That could be Williston. That could be Permian. If I had to guess, I would probably push more towards Permian just because you have so many zones there that you can chase at any one time.

So, that's – and you get similar answers. It certainly keeps us in that 2018 range. The update that we provided today is really directing you towards that high end of the range that we provided back in September and we feel very comfortable that we're heading that direction now.

John Nelson - Goldman Sachs & Co.

Great. I'll let somebody else hop on. Great quarter.

Richard E. Muncrief - WPX Energy, Inc.

Okay. Thanks.

Operator

Thank you. And our next question comes from Jeanine Wai from Citigroup. Your line is open.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Hi. Good morning, everyone.

Richard E. Muncrief - WPX Energy, Inc.

Morning, Jeanine.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

This question might be for Kevin. So, just thinking back to the equity offering earlier this year, which was meant to cover the cash flow outspend over the next two years. And now with your bigger CapEx program versus two months ago, your commentary of not having to add any incremental debt still holds true.

So can you help us understand how the bigger program this year affects the outspend relative to what your September estimate was? And if it's larger, how does that affect your 2018 in terms of has your cash flow projections for 2018 gotten better, assuming that the amount of cash you have is still a fixed amount, i.e., no price changes or no asset sales? So, just trying to figure out what this means for 2018, if your outspend has increased for 2017.

J. Kevin Vann - WPX Energy, Inc.

Yeah. Hi, Jeanine. Yeah. Good to talk to you, Jeanine. And yes, our outspend for 2017 has gone up, but it's only gone up modestly. I think we were right around $350 million outspend the last time we talked, and we're a little bit above that but less than $400 million next year. So really, again, as I commented earlier, what that does for 2018 is it actually de-levers a whole lot faster, much quicker, just given the payback period that we see in 2018. And given the equity proceeds from the June offering, we're still anticipating, again, no incremental debt but also still having some cash left on the balance sheet at the end of both 2017 and 2018.

Clay M. Gaspar - WPX Energy, Inc.

Yeah. Jeanine, this is Clay. One thing I would add is, I mean you noticed, as usual, we're guiding the full-year 2017 one year ahead. What's unique is that we're guiding that single data point out in 2018. And that's not by accident, obviously. The reason we wanted to make sure and describe that data point is because so much of the efforts that we're putting into 2017 differentially benefits 2018. As you're ramping rigs and you're really growing that activity, so much of that 2017 investment really benefits us in 2018. So I think that was an important point for us.

And then, as Kevin pointed out in his prepared remarks, the net debt metrics also significantly improve over where we were before on 2018.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Okay. Great. Thank you very much.

Richard E. Muncrief - WPX Energy, Inc.

Thank you.

Operator

Thank you. And our next question comes from Kashy Harrison from Simmons & Company. Your line is open.

Kashy Harrison - Simmons & Company International

Good morning, and thanks for taking my question. I only have one, as a lot of them were answered already. Just given the improvements that you're already seeing in efficiencies and productivity, do you think there's a case to be made that you could achieve your 2018 oil production guidance without adding the one to three rigs that you're talking about in your presentation?

Clay M. Gaspar - WPX Energy, Inc.

Well, thanks for mentioning that in front of my boss. Certainly. Every time I think we've kind of found bottom on drilling curves and how efficient we can get, the team continues to surprise. So I would never say that we're done innovating and done becoming more efficient. Same thing on the completion side, we continue to increase the amount of stimulation and somehow figure out how to squeeze a few more dollars back out of the system.

So I think the interesting thing is, as you see these rigs cycle faster, that super efficient mode that they would get into, we certainly have upside from what we've baked into the current guidance. And so you can see that. That 11.8 days – or 11.9 days, it was actually 11.88 days, we rounded. 11.9 days, that's not baked into the guidance as the normal rig rate.

As we start cycling through more rigs, more wells like that in the Williston, certainly that pulls more activity into 2017 and would differentially benefit 2018. So you could contemplate a scenario where you're at 5:1, even in 2018 your rig is just become that much more efficient.

Kashy Harrison - Simmons & Company International

All right. Thank you.

Richard E. Muncrief - WPX Energy, Inc.

Thank you.

Operator

Thank you. And our next question comes from Matt Portillo from TPH. Your line is open.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Good morning. guys.

Richard E. Muncrief - WPX Energy, Inc.

Morning, Matt.

Clay M. Gaspar - WPX Energy, Inc.

Morning.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Just a quick high-level question. Looking at your Permian growth over the next few years, could you talk directionally about how the hydrocarbon mix may change as you target some of the oilier horizons in the X/Y and Wolfcamp A? I guess, specifically looking at the mix this year, it's been about 50%, 53% oil. And the well that you're drilling now and the upper targets are kind of that 60% to 70% range. So, just trying to get a better sense of how that might trend over the next few years.

Clay M. Gaspar - WPX Energy, Inc.

Yeah, Matt. You're spot on. We'll be drilling roughly 70 of the 75 wells are A and X/Y, longer laterals, oilier wells, 60% to 70% plus. So, that definitely will have a positive impact on overall oil ratio. The deed, obviously when get into – develop a bit more of that, that would draw it down. We have a handful of those wells planned for next year.

So I think the general trend will continue to work its way up. I don't have an exit rate on the oil percentage handy, but certainly you're thinking in the right direction. If we're roughly 50% now, certainly trend up throughout the year.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Great. Clay, and then just a second follow-up question. You mentioned continuing to push innovation on the completion side. Could you just remind us kind of where your current design is in the Permian today? And then I know the industry has continued to be pretty aggressive here in the basin. I think one of your peers, as of the last few days, mentioned doubling profit loading and doubling fluid volumes in nearby acreage. Just curious how you guys are thinking about test over the next six months?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. We've heard that, not just in this basin but others as well, and it's nothing new. We're right on board with generally more profit is better. What we're trying to find is kind of that optimal state, and so we try real hard not to isolate ourselves and think that we're the only ones innovating. We're going to look across the fence, we're going to watch what those guys are doing, the guys on the very southern end of the basin, watch them. They've been pressing probably harder than the rest of the basin on how much sand you can put in the ground.

But it's also, what type of sand? What is the right mix? What is the concentration? What's the fluid? How much fluid? What's the perforation strategy? How tight are those clusters, diverters, nano-surfactants? There's a lot of things that come into play that there may be a substitution effect where you can get essentially the same results, less sand, substitute some of these other dials in and achieve the same results.

I think that's something we're looking at real hard and we're certainly trying to stay abreast of what everybody else is doing as well.

Richard E. Muncrief - WPX Energy, Inc.

Yeah, Matt, that's true. One thing I'd interject is that one of the things about getting more rigs to work is, exciting to me, is I think we can advance that understanding that Clay's talked about it quicker. Because quite honestly we've just had two rigs running out there about last 6 months to 9 months on our CDC. We haven't even really been drilling where we wanted to, let alone how we wanted to.

So, that's exciting thing about getting more active down there. So we have a lot to learn, but I've got a lot of confidence this team will – they'll push the envelope and we'll strive to get that right answer.

Clay M. Gaspar - WPX Energy, Inc.

And Matt, to answer your original question, we're about 2,000 pounds, up to 2,500 pounds per foot on our sand today.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Great. Thank you very much.

Richard E. Muncrief - WPX Energy, Inc.

Thank you.

Operator

Thank you. And our next question comes from Robert Christensen from Drexel Hamilton. Your line is open.

Robert L. Christensen - Drexel Hamilton LLC

Yes. Thank you. Can you perhaps tell us where the deviation is? Will the sets widen up between 20% and 35% growth over the next four years? I would think it would be in the outer years that that gap sort of opens up. And for what reason would you not be more specific, 20% to 35%? I don't know if you get my question, but...

Richard E. Muncrief - WPX Energy, Inc.

Yeah. Bob, I think we do. What we've tried to do a few months ago when we laid it out was our spend rate, our ability to stack cash, pay down debt out in 2020, versus continuing to just redeploy that capital and basically reinvest into the business and drive your growth rate higher.

And it was a pretty bold step I think for us to, at that point in time, to show that kind of range. But what we wanted to do was show investors what the capabilities were that we had within our assets. And also the flexibility of growth, if we want to take a slower, more measured, more moderate 20% annual growth, which quite honestly with most organizations is very, very aggressive. That didn't really indicate to us internally, and we felt like to the market, what we really had here. And if you recall, on that original presentation a couple of months ago, we showed what the consensus growth was over the next four, five years and it fell, quite honestly, well below our low case.

And so we felt like we wanted to show investors that. Now we also felt like that as we started to go with an increased activity on our capital and drill longer laterals, and the efficiencies that you've heard Clay talking in quite a bit of detail about, that drove our capital numbers higher. So, but that's only part of the story. The big part of that story is that 2018 growth rate. And that's why we're one of few people, if not the only one I've seen thus far, that have gone out and talked about what their growth profile is going to look like in 2018.

So we'll keep investors apprised and analysts apprised of how we're seeing things. But those were why we trended near-term much to the high-end of that range we laid out. So, hopefully, that's answered your question.

Robert L. Christensen - Drexel Hamilton LLC

Thank you, Rick. If I may just have a follow-up. It may come off the top of your head here, but I don't think so. Refresh my memory as to what you paid per acre in the Delaware when you stripped out the midstream and other things that you stripped out. I think you did give a number out back in July of 2015. I imagine it's going to look like a very low number relative to all the transactions we've seen in the last few months.

Richard E. Muncrief - WPX Energy, Inc.

Yeah. What we have is when you back out the production we used that time, you back out the – and we've just assigned $500 million to the midstream as we've...

Robert L. Christensen - Drexel Hamilton LLC

I recall.

Richard E. Muncrief - WPX Energy, Inc.

Yeah. As we learn more about it, that value is probably more than that. But the number that I use is about $12,500 per acre was our entry price.

But I think that only tells part of the story. In my mind, when you step back and you look at the number of intervals that we have, and just what did we get for that $12,500 per surface acre, we have a lot of targets. And when you really break it down like that, I think that the transaction was an absolute home run for us. It set this organization. It set it up.

And it's not just the value of the midstream but, quite honestly, the value of that midstream to be able to address and handle the growth that you have coming up. And that came up in the questions a while ago. And so we're very pleased with the deal but we didn't stop there and we continue to bolt-on. Our team has done just a remarkable job in bringing in another actually close to 13,000 acres now at a very, very attractive price. So we're real pleased on this position.

Robert L. Christensen - Drexel Hamilton LLC

I bet. Thank you very much, Rick.

Richard E. Muncrief - WPX Energy, Inc.

Thank you.

Operator

Thank you. And our next question comes from David Heikkinen from Heikkinen Energy Advisors. Your line is open.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Good morning, you all, and go Cubs.

Richard E. Muncrief - WPX Energy, Inc.

Hey.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

And I'm a Cardinals fan and I can still say that. That was a hell of a series.

Richard E. Muncrief - WPX Energy, Inc.

Yeah.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

The scenarios that you use when you make your multi-year plan, one thing that we saw in your guidance was that your wells per year per rig are really ramping up. And so, that efficiency is happening on the operating side.

Can you talk a little bit about how you incorporate, like things like that improving efficiency? And then particularly in the Delaware, with the productivity per well, longer laterals and new zones in the mix, how those factors fit into the what-if scenarios around your plan?

Clay M. Gaspar - WPX Energy, Inc.

Yeah. Dave, this is Clay. What we're thinking about is working through continued efficiencies of the rigs. I mean, that's super-efficient rig. And where that really translates is just a multiplying effect to, you have five rigs running, it sort of acts like seven or even eight rigs at times. You could mimic that same result by just running the seven or eight rigs out in future years because there is a little bit of dollar benefit, but you still have – you're not radically changing your completion design. You're just actually piling more capital into that year.

So, that's something we model through and we've run through some of the iterations. It's certainly contemplated in that 20% to 35% range, how that shakes out over time. But I think just generally looking at it, when you look to where is that point where a 10% improvement in the first couple of years, maybe it's a 5% or a 3% kind of out in those trailing years. Didn't know those were going to continue to just drive the efficiencies. Look at what we've accomplished as an industry over the last 5 to 10 years. There are certainly still improvements to gain, but probably not at the same clip as what we've seen in the past.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Okay. And I guess, maybe in the 70 to 80 wells in the Delaware next year, do you have a split by zone that you think you'll be drilling?

Clay M. Gaspar - WPX Energy, Inc.

Yeah, roughly, I said in the call, 15 wells in the X/Y.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Okay.

Clay M. Gaspar - WPX Energy, Inc.

Consider that about 70 between the A and the X/Y and then the balance will be D and then the other tests we talk about, Second Bone Spring and also C.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Okay. And then, there's no major difference in costs for those?

Clay M. Gaspar - WPX Energy, Inc.

Not major. Your D is going to tend to be a little bit more expensive. Your X/Y is going to be a little bit cheaper. That first X/Y we drilled – I mean, the first well we drilled, $5.1 million. That's pretty exciting. This last D, I can tell you the first half of the lateral was pretty slow drilling. And so, that's going to – it got a little higher mud weight, got a little slower drilling. By the end we felt like, okay, now we're starting to really make whole and figure this thing out.

So there'll be a little bit of lessons learned as we touch these other zones. But I would say, generally speaking, there's not a major casing design or significant change from moving to a Bone Spring to a Wolfcamp, any one of the zones.

David Martin Heikkinen - Heikkinen Energy Advisors LLC

Thanks.

Clay M. Gaspar - WPX Energy, Inc.

Sure.

Richard E. Muncrief - WPX Energy, Inc.

Thanks, Dave.

Operator

Thank you. And our next question comes from Jeffrey Campbell from Tuohy Brothers. Your line is open.

Jeff L. Campbell - Tuohy Brothers Investment Research, Inc.

Hi. Good morning and thanks for all the great color that you've been providing. I was just wondering, do you have any color on how you managed to acquire the bolt-on acquisition at such a low per-acre cost relative to recent deals and are similar acquisitions still possible in the future?

Richard E. Muncrief - WPX Energy, Inc.

Well, I could tell you, it's getting pretty tight. And it is hard for me to sit here right now and say we'll absolutely replicate that success. But one of the things that really helped us is our – I'm going to go back to one of the fundamental tenets of this company is our bias for action.

One of those deals had a short-term lease on it and it was getting close to its expiration. And because we had a rig running, because we were willing to jump out there, our team acted unbelievably efficiently. And we knocked that thing down and within days we were ready to have a rig headed there.

And I can tell you that's something we've done in prior lives, other companies that really helped you keep your entry cost down, and it's helped us in San Juan. You saw Clay's results out in the Gallup. That's where we've got entry price somewhere around $3,000 an acre on our 100,000 acres, those kind of results. So, that's just how you make money in this business.

And so we think we can replicate some of that, but I can tell you that it's a very competitive landscape out there and I think more and more I'm going to go back to that dollar per acre we talked about in the RKI transaction.

What's different about the Delaware Basin is you've got so many different targets. And so, when people think about their dollar-per-acre entry cost, it's really easy to break it down and divide that by several five or six different prospective targets. And it certainly becomes much more palatable and actually much more exciting.

So we'll continue to look for opportunities. We love our runway that we have if we don't pick up another acre. We've got a lot of work over the next several decades. But that's not how you add value. We'll continue to look for things that add value. Because at the end of the day, we look at ourselves as being value investors. That's why we're taking cash that we have sitting, not making us much money, and we're going to put it to the drill bit.

You've seen the returns that we're getting, and that's creation of value. If we can see acreage out there that we feel strongly that we can drive additional value, we're going to invest in it. But really, really pleased what we've done to-date. So we'll work hard on behalf of the investors to continue to replicate that success.

Clay M. Gaspar - WPX Energy, Inc.

I would say the one other thing that's very significant, I can assure you, Bryan Guderian's team is looking at every deal out there. We are working harder than we ever have on scrubbing every opportunity, knowing that there may be one of these that – a marketed deal that actually fits for us.

What we're finding is we typically can't quite get to the transacting price, and that's fine. But the most important thing for us is that we don't have to do a deal. We've got our 100,000 acres plus. We're in a great position. The last thing we want to do is do a dilutive deal to water down the great stuff that we have, either with sub-quality assets or really expensive assets, just don't compete quite as well on a full cycle basis.

Now, it doesn't mean we'll never do a deal. We're out hunting. We're going to look for that deal, but I assure you the deal that we do will make sense to us on a full cycle basis for full value creation for the company.

Jeff L. Campbell - Tuohy Brothers Investment Research, Inc.

Okay. Great. I appreciate that color. My other question was bearing in mind the similar returns. Are there basin-specific peculiarities behind the logic of giving two rigs to the Williston and one to the San Juan rather than the other way around?

Clay M. Gaspar - WPX Energy, Inc.

So one think you notice, the well count is approximately the same. That's not necessarily how we do the capital. I would say, with San Juan, there's some surface challenges that have bit us before. In the last couple of years, we've moved from three rigs to two rigs to one to zero. For us to kind of change course and add that rig back was a pretty big decision for us. And so we challenged the team to say, okay, lay this program out. We're going to put our rig to work, but not until two things happen.

Number one, we want to make sure that we have that reliable, repeatable-type well that we can really count on. And then number two, all of these surface hurdles around permitting or infrastructure or any of those kinds of challenges, that's all cleared out ahead of us. And so, once we saw those two things out cleared ahead, then we're ready to go. I would say once we gain that confidence, call it a few months, several cycles through this, I'm fully confident those well efficiencies will get better.

We've only drilled with these wells recently kind of in one or six or three kind of wells at a time. When we get a rig up and running, you can bet that those wells will get even better than what we're seeing today. And that'll be their opportunity to vie for that second rig.

And the Williston, we already had one rig running. The efficiencies were there. It was a very easy decision for us to add that second rig. They certainly have capability of handling more than that.

Jeff L. Campbell - Tuohy Brothers Investment Research, Inc.

Okay. That makes perfect sense. Appreciate it.

Clay M. Gaspar - WPX Energy, Inc.

Thanks, Jeff.

Operator

Thank you. And our last question comes from Gail Nicholson from KLR Group. Your line is open.

Gail Nicholson - KLR Group LLC

Good morning. You've just seen significant improvement across all three areas in capital productivity in 2016. When you look at 2017 and the things that you plan to experiment and test on, what do you think could be the single largest game changer from a productivity standpoint going forward?

Clay M. Gaspar - WPX Energy, Inc.

Man, Gail, I would love to have three or four. The first thing that came to mind was drilling the longer laterals. That is, it is so – that's like easy, easy money because when you're drilling these wells, you drill the vertical, you make the turn, you're setting the casing, you're drilling out the lateral. And I can tell you, with the capabilities we have today, we're just getting the rig warm by the time it's time to TD the well and move on to the next one.

That second mile is by far your most efficient drilling. And so what we've had to do in this past year is really get our land and our ability to drill that second mile really from an ownership and regulatory kind of perspective. The technical capabilities, the operational capabilities have been there. So the rigs that we've brought on are all fully equipped to drill the longer laterals. I can tell you the teams are ready to go. That will be an instant game changer. And all three basins, we're really pushing longer laterals. But certainly, in the Permian, it'll be an instantaneous change.

Gail Nicholson - KLR Group LLC

And when you look at 2017, your budget and the acceleration of your rig count, have you baked in any service inflation into 2017?

Clay M. Gaspar - WPX Energy, Inc.

No. We really haven't baked in additional efficiencies. We really haven't baked in any service inflation. We're figuring those somewhat wash. We're starting to see – the first guy we call actually is booked up. That's kind of your first clue that they didn't drop everything and run your way. We still haven't seen where the second or third guy on the list is not readily available, but we're very close. We'll watch that. We have a very sophisticated supply chain organization.

And I can tell you, us getting our budget nailed down early will significantly help us kind of give those guys the clarity they need to align. Because more important than that 2% or 3% extra margin they can get, those guys want to work. They want that – give me that steady job that I can get well-after-well-after-well, and that's what they're looking for.

So, us kind of laying out this program not just into 2017 but throwing it out for 2018. That gives those guys some really good excitement that, hey, this is the company that's going back to work. This is who we want to align with.

Richard E. Muncrief - WPX Energy, Inc.

Hey, Gail. It's Rick. I think the one thing I would add to Clay, I agree wholeheartedly that the longer laterals are at the top of the list. But I think the thing that as we've – what we've learned over the last year, if I compare where we were 12 months ago versus where we are today, I think our understanding and appreciation for the X/Y, which is a target that wasn't even on the radar screen for us when we did the RKI acquisition and we closed it a year ago in August, is now something we're going to be drilling 15 wells on next year.

And on top of that is our very first one out of the box up in Rustle Breaks area is performing extremely well, really in line with several of the other 800, 900 MBoe type wells in the neighborhood for 1-mile lateral. And when you start looking at that, you start thinking about what that could be for your portfolio, your value, your production growth on the oil side. It gets really exciting.

So, when you marry the two of those together, and we can get some of those 2-mile X/Ys together, I think that's something really exciting. And also very much look forward to what we could do with this density pilot project in the upper and lower A. I think that could be huge for this organization in driving value creation.

Gail Nicholson - KLR Group LLC

Great. Thank you.

Richard E. Muncrief - WPX Energy, Inc.

Thank you.

Operator

Thank you. This concludes today's Q&A session. I would now like to turn the call back over to Rick Muncrief for closing remarks.

Richard E. Muncrief - WPX Energy, Inc.

Well, thank you very much, and I appreciate everyone's patience. We felt like we had a lot to talk about today. We did experience the trough in production 2013, just like we've talked about 90 days ago. But as you have seen today, we have a lot to be excited about. We're already executing. That execution is what we've all been known for, and I think you can expect that in the future.

So, have a great day. And just like Dave Heikkinen, I want to congratulate the Chicago Cubs. It's been 100 years in coming. Just like Dave Heikkinen, I'm a St. Louis Cardinals fan. But folks, have a nice day and we'll talk soon.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone have a great day.