Pioneer Natural Resources' (PXD) CEO Scott Sheffield on Q4 2015 Results - Earnings Call Transcript

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Pioneer Natural Resources Co. (NYSE:PXD)

Q4 2015 Earnings Conference Call

February 11, 2016 10:00 AM ET

Executives

Scott Sheffield – Chairman and Chief Executive Officer

Tim Dove – President and Chief Operating Officer

Rich Dealy – Executive Vice President and Chief Financial Officer

Frank Hopkins – Senior Vice President of Investor Relations

Analysts

Brian Singer – Goldman Sachs

Evan Calio – Morgan Stanley

Doug Leggate – Bank of America

Neal Dingmann – SunTrust

Jon Wolff – Jefferies

Dave Kistler – Simmons & Company

John Freeman – Raymond James

Charles Mead – Johnson Rice

Ryan Todd – Deutsche Bank

Jeffrey Campbell – Tuohy Brothers Investment Research

Bob Morris – Citi

Paul Sankey – Wolf Research

Michael Hall – Heikkinen Energy Advisors

David Beard – Coker Palmer

Operator

Good day, everyone, and welcome to today's Pioneer Natural Resources fourth quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today, and these slides can be accessed over the internet at www.pxd.com. Again, the internet site to access today's slides related to the call is www.pxd.com. At the website, please select "Investors", then select "Earnings & Webcasts". Today's call is being recorded. A replay of the call will be archived on the internet site through March 7th.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results and future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page 2 of the slide presentation, and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Mr. Frank Hopkins. Please go ahead, sir.

Frank Hopkins

Thanks, Lori. Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call. Scott will be the first speaker. He's going to provide the financial and operating highlights for the fourth quarter of 2015. Another quarter which saw the company deliver strong execution and performance. Scott will then review our plans for 2016 in the face of the continuing weak commodity price environment.

After Scott concludes his remarks, Tim will review our strong horizontal well results and capital efficiency in the Spraberry/Wolfcamp. He'll also provide more details regarding the 2016 Spraberry/Wolfcamp drilling program. Rich will then cover the fourth quarter financials and provide earnings guidance for the first quarter. And after that, we will open up the call for your questions. So, Scott, I will turn the call over to you at this time.

Scott Sheffield

Thank you, Frank. Good morning. Slide number 3 on our operating and financial highlights. We had a fourth quarter adjusted loss of 27 million, or $0.18 per share. Fourth quarter production, 215,000 barrels of oil equivalent per day. 53% oil. The top end of our revised guidance of 213 to 215. That's an increase of about 4,000 barrels a day, or 2% versus the prior quarter. Full year production, 204,000 barrels of oil equivalent per day. 52% oil versus 48%, in 2014. That's an increase of 22,000 barrels a day, or 12%, versus 14%. Oil production was up 18,000 barrels a day, or 21%, versus 2014. Obviously, the growth driven primarily by the Spraberry/Wolfcamp horizontal drilling program in the Midland Basin.

Also, we delivered 273% drill bit reserve replacement of 210 million barrels of oil equivalent, at a drill bit fine F&D cost of about $10 per BOE. Again, shows you the true prolific nature of the Midland Basin and Wolfcamp, with average operating cost of a typical Wolfcamp well of $5 and fining cost of about $10. It still shows it's very economical in today's environment to still be drilling in this place.

Slide number 4. We did place horizontal wells on production in the Spraberry/Wolfcamp during the fourth quarter. As expected, early production from 35 wells in the North and 9 wells in the South is exceeding expectations, as we had mentioned earlier in January, primarily due to the company's completion optimization program. Also, continuing to strive toward great capital efficiency gains in the Spraberry/Wolfcamp, really driven by service cost reductions, efficiency gains and completion optimization programs. We did issue 500 million at 3.5% senior notes, due 2021, and 500 million at 4.5% senior notes due 2026, in December. To refund payment of our 2016 and 2017 maturities and that will be coming up over the next 12 months.

Working with midstream partners to have our oil export facilities along the gulf coast operational by mid-2016, we did see the first cargo go out recently, not but us, by another producer. It's the first WTI cargo I saw that went to the Caribbean and mixing with heavy Venezuelan crude. So people are starting to pay somewhat of a premium, so we hope we can get some crude out. The only crude that I've seen go out before that were a couple of the Eagle Ford Oil cargoes from Eagle Ford from two other operators. But what's most important for us is that the long term strip has narrowed to essentially nothing between Brent and WTI.

On number 5, our plan, obviously we've made a change since early January. The primary reason for that change is that the entire strip for 2016 has dropped over $10 during that timeframe. Much faster than I had thought, than we had thought at the management team, at the board level. So that's why we have developed this response to that. So we're reducing our horizontal drilling activity by 50%, from 24 rigs down to 12 by mid-2016 while still growing production by 10% plus and preserving the company's strong balance sheet and cash position.

Eagle Ford will be going from six rigs to zero during the first quarter. Two rigs already released. Also in Eagle Ford we will have 17 ducks that will hold off and decide when prices come back, which I expect in 2017, reducing Southern Wolfcamp joint venture from four rigs to zero by mid-2016. We'll be using the rest of our carry as the reason that we're running those rigs until mid-year to fully utilize the rest of the carry. Reducing northern Spraberry/Wolfcamp from 14 to 12, really for capital preservation. Already released one rig. We were going back and forth between 12 and 14. We felt like that we wanted to get our capital budget down about $2 billion, so there's nothing magic about it, but what's amazing is that we're still growing 50%, 10% plus by cutting half of our rigs. A great accomplishment to the Permian team.

Reallocating two Eagle Ford shale pressure pumping fleets to the Spraberry/Wolfcamp. Reduction in drilling activity in [indiscernible] spending results and capital expenditures of about $2 billion for 2016. That's down from our preliminary forecast in early January from $2.4 to $2.6 billion and from actual spending in 2015 of 2.2. That's 1.85 for drilling. That does include tank batteries, SWD, saltwater disposal wells and gas processing facilities. And then an additional $150 million for vertical integration, systems upgrade and fill facilities.

Slide number 6. A continuation of our plan. We are probably the best hedged company in regard to oil again for 2016. We do have 20% for 2017. And we do have great gas coverage, 70% for 2016.

Again, we have a great balance sheet, probably the best in the industry today. When you look at our $500 million coming due from enterprise and look at $400 million of cash on the balance sheet with additional $1.6 billion from our recent equity offering, we essentially have zero debt today. So obviously the best balance sheet among any major and any independent in the marketplace. And that's one of the reasons we decided to grow 10% plus and preserve roughly about $1.7 billion going into 2017. And if prices recover mid-2016, if they recover late 2016, if they recover early 2017, we have tremendous firepower to start up faster than anybody else and get back to our 15% growth profile over the next several years.

Slide number 7. On drilling completions capital, capital program again of $2 billion, $1.85 billion of drilling completion. As you can see, 90% of it's in the north. I won't go over the detail here, but any questions, please give Frank and Mike in the group calls afterwards. Other capital of $150 million and, again, the capital program funding from our cash flow. Plus using a combination of our enterprise funds of $500 million coming mid-year, and $400 million in cash that we had at the end of the year in late 2015.

Slide number 8. Looking at going forward, you can see that we are growing 10% plus. I still think that number is going to lead any company with oil production of any major and independent in the U.S. marketplace. Again, we have the firepower to start it back up fairly quickly. We're looking at 224,000 barrels of oil a day-plus, for the year 2016, going from 52% oil to 56% oil. You can see most of the pickup will be in the second, third and fourth quarter, as we have given out guidance of about 211 to 216 for the fourth quarter. And again, long term, 2016 to 2018, we do show growth in this low strip price environment. 2017 will be again around 10%. Preserving over half of our cash of $1.7 billion by the end of 2017. And so, pioneer can essentially weather 2016 and 2017 without increasing debt, and be able to jump-start at any point in time over the next two years as prices recover.

I'm going to now turn it over to Tim to get into more detail about operations.

Tim Dove

Thanks, Scott. We continue to be very encouraged by the results of our drilling and completion program in the Midland Basin. I will start here on slide 9 talking about the northern area, where we put 22 Wolfcamp B wells on production during the fourth quarter. You can see the production profile in the chart below, as the dark blue lines represents those wells' early production. And it's very clear when you look at that, this is exceptionally strong production results we're seeing. The strongest to date in our program. And it's very clear that these wells are tracking well above that million barrel BOE type curve shown in the dash line.

We did also put two Wolfcamp A wells on production, right at the end of the year. Those are shown in the red line. Below on the grass, you can see there's very little production data. Current thinking is that we will be seeing more data as time goes on. But we're putting these wells on gas lift almost immediately. They had IP rates of about 1570 barrels per day. Of course, early in the life of these wells. We will be reporting more about that next quarter.

When you look at the performance of the wells from the third quarter, it's very clear we have similar results, in the sense if you're looking at the 28 B wells and 2 A wells shown on the graph. One in light blue and the other in orange, respectively. Once again, we have a limited data set on A wells, only 2, but they're performing exceptionally. Well over the million barrel type curve. And when you look at the third quarter B wells, they also performed exceptionally well. So, what you can also see from this graph is, we're improving quarter to quarter sequentially, in terms of the performance of these wells. And that has to do with a great extent related to our completion optimization program. About two-thirds of the wells in the third quarter were subject to completion optimization, and all of the fourth quarter wells were exposed to completion optimization. And so you can see the uplift we're generating as a result of optimizing these wells.

When I talk about optimization, it's several different factors that we're testing, in various different areas. For example, generally, we're changing the stage lengths from 240 feet to 150 feet. We're changing the clusters per stage generally from 4 to 5. We're pumping more fluid. Somewhere in the neighborhood of 36 barrels per foot, compared to the prior 30 barrels per foot. And, importantly, we've increased the sand concentrations for these wells in the fourth quarter up to about 1500 pounds per foot, from a total of about 1100 from prior completions.

We're going to outline a little bit later in the slide deck the expansion of some of these ideas even to further optimization in their 2016 campaign. I would say it's worth pointing out, if you look at the table below, that, of the 22 Wolfcamp B wells put on production, they average exceedingly strong IPs of 2200 barrels per day on a BOE basis, and that compares with 1900, in terms of the campaign from the third quarter. So, dramatic increases we continue to see as completion optimization is paying off very well.

Turning now to slide 10. We have seen similar successes in the lower Spraberry shale, where we popped 11 wells during the quarter. The early production results, as you can see on the graph, are close to that same one million barrel EUR type curve and we did the completion optimizations on 9 of the 11 wells, essentially using the exact same style of franc optimization and completion optimization that I mentioned regarding the Wolfcamp zones. The production on some of these wells is really continuing to build. In fact, only five out of these 11 wells have actually reached their IP rates. They're continuing to build not atypical for lower ratio wells as we take the water off the system, oil rates increase and peak quite a long ways into the early production life. So we'll be having more to report regarding these wells as we see their IPs and can incorporate that into the first quarter report.

Turning to slide 11, once again we're seeing strong results in the south with the JV area, the Wolfcamp. We're reusing essentially the same optimization techniques and we placed nine wells on production in the southern Wolfcamp area. Of the eight Wolfcamp B wells, you can see in the graphs below, particularly on the left blue line tracking above a million barrel type curve and the Wolfcamp A well that was drilled, one of the nine wells, showing the red curve on the right is tracking between 800,000 BOE and a million BOE in terms of its type curve. So these are very good wells in the south and you can see there's various areas of the south that are going to compete very well with the north. Again, all of these were optimized using similar optimization packages as we had discussed earlier in the prior slides.

Now then turning to slide 12. The optimization and productivity gains I have already mentioned are leading to a high level of capital efficiency. That's critical, of course, when we're faced with a low commodity price environment as we see today. You can see on our left graph here that we continue to see dramatic improvements when it comes to our drilling campaign and completion campaigns where we are dropping our costs dramatically sequentially from quarter to quarter. We've decreased our cost for D and C in the north B wells by an average of about 30% over the last year, which is really a phenomenal result. At that same time, as you see the curves on the right, we're seeing sequential increases in cumulative production per well as we go through time. That is reflected in the prior slides that I've already mentioned, but you can see it pretty dramatically here that on a 90-day average rate, our production is up from about 830 BOE per day in 2014's fourth quarter to 1250 in this last fourth quarter. And it's pretty clear, if you look at data, that IPs are well correlated to well EURs. And so you can see we've had a dramatic improvement as a result of our capital efficiency and optimization programs. So it does give us confidence that we are, in fact, increasing capital efficiency through time and that allows us to continue drilling today, albeit at a slower rate based on the commodity price deck.

Turning to slide 13. And this is now reflecting on the 2016 campaign for the Spraberry/Wolfcamp D and C budget. Scott's already mentioned some of this, so I'll be brief. We are going to be moving to 12 rigs in the north, as he said, zero in the south, and expect in doing so to still place 230 wells on production this year, split 60% Wolfcamp B and the balance being Wolfcamp A and along with Spraberry shales, about 190 wells in the north and 40 in the south. And despite the fact we've had weak commodity prices, as I mentioned earlier, we are still generating good returns on the wells we're drilling. The optimization campaign is certainly helping that. Now what we're planning on doing in certain areas is actually furthering that optimization campaign. For example, in some areas actually reduce the cluster lengths to about 15 feet and 10 clusters per stage. We're looking at increasing the fluid utilization up to about 50 barrels per foot and increasing our sand concentrations up to 1700 to 2,000 pounds per foot.

At the same time we continue to experiment with less coarse sand concentration. so 40/70 sand and 100 mesh sand. In doing so, we can put more of a focus on slick water fluid utilization versus gels. We're also in all these areas adjusting spacing and stacking as we learn more in each area. We're really still heavily in the process of learning the best way to complete the wells, and it's not the case, it's the same in every area for every zone. So we can learn a lot this year and it's one of the benefits of continuing a drilling campaign. Costs are coming in about 7.5 to $8 million, and that's based on a 9,000 foot lateral and incorporates the optimized completions costs. The program that we were talking about in terms of production growth, we're incorporating EURs in range, depending on the zone, from 800,000 BOE to about 1.2 million BOE, depending on which zone we're dealing with. And we have IRRs in this campaign. Current prices that are up to 30%. As Scott already mentioned, with our cost being low to develop this production and with operating costs being low, returns are very solid.

Turning now to slide 14. We continue to build out the required infrastructure, albeit at a slower rate of spending, based on what's going on with the price downturn. In terms of tank batteries and salt water disposal facilities, we will spend about $170 million this year. In doing so, we're reducing our cost per well that's hooked up and put on production, from about $900,000 to about $750,000 this year. That's a benefit of the scales coming from the fact of our prior spending on centralization of the facilities. And so, we're beginning to see the benefits that come from pre-planning and pre-spending, in the form of reduced cost too hook wells up.

We will spend about $45 million in gas processing. The most important part of that is completing the Buffalo plant in Martin county, in the second quarter of this year. There are no new plants after that in the foreseeable future. We did announce the start-up of a 20 mile pipeline to deliver effluent water, non-potable water from the city of Odessa to some of our Midland County drilling locations, and that's going to save us a tremendous sum. Calculated $100,000 per well once this water starts being utilized. It just started flowing last week. We'll also spend about $45 million or so when it comes to mainline expansions in other subsystems. And just like the Odessa deal, we continue to pursue purchasing, from the city of Midland, effluent water. In a similar way, those negotiations continue.

Finally, on this slide, the completion of the expansion on the [indiscernible] has been postponed, as you might expect, until we're at a point where we're going to be adding more rigs.

Turning to slide 15. We certainly have begun to see the effects of the strong well results I showed, in the form of production. If you look at the production in the fourth quarter, actually reaching the top end of our revised range, that's emblematic of the fact that we put the number of wells on production we had planned, which was about 44 horizontal wells. But only way you can explain the fact that we're outperforming, is these wells have very strong IP rates, as I showed on prior slides. And so, that gives us a lot of confidence moving forward. The horizontal production actually makes up more than half of our total production today, in this basin, about 60%.

We see production growing in the basin here about 30%. That's after a great year in 2015, at 27%, by putting those 230 wells on production. The first quarter production volumes are forecasted to be somewhat flat, and they're impacted by the fact that we have a great deal of expected shut-in volumes. The fact that we have offset fracs being three times greater than occurred in the fourth quarter, in the first quarter. And the reason for that is, we're popping these wells. We're fracking the wells near existing pads. The objective is, of course, to save infrastructure costs. Whereas, the second quarter should be a strong quarter for production. And we'll expect to pop a similar number of wells in the first quarter, as we did in the fourth quarter, about 45 wells.

So, I will sum it up by saying, these operating results give us a lot of confidence that the Spraberry/Wolfcamp assets can perform well, even in a depressed commodity price environment. Which means, we're poised to accelerate development of these assets when prices improve.

And with that, I’ll pass it over to Rich for a review of the fourth quarter financials and his outlook for the first quarter.

Rich Dealy

Thanks, Tim. I'm going to start on slide 16, where we reported a net loss attributable to common stockholders of $623 million, or $4.17. That did include non-cash mark-to-market derivative losses of $13 million after tax, or $0.09. And it had two unusual items there, both of which we mentioned in our January guidance that we provided. An impairment on Eagle Ford Shale approved properties non-cash of about $542 million after tax, or $3.63, primarily as a result of the reduction in commodity prices. And we had other non-cash impairments, mainly vertical pipe inventory that we're not using because we're out of the vertical drilling business, of about $41 million, or $0.27. So, adjusting for those items, as Scott mentioned, we had a loss of $27 million adjusted or $0.18.

Looking at the bottom of the slide, where we show how we performed against the updated guidance that we gave in January in conjunction with the equity offering, you can see that all the items came in where we would have expected within guidance around the positive side of guidance. The one item I'll make note of is our current income tax provision. We had a benefit of $26 million. That was really the result of a tax law that changed that happened in December where they allowed bonus depreciation. which had the effect of reducing our 2015 estimate of alternative minimum tax, and so we did recognize that benefit.

Turning to slide 17, looking at commodity prices, as you guys are well aware, they were down again in the fourth quarter where you see on our bar charts that oil was down 11% to $37.92, NGL was down 2% to $12.16 per barrel and gas prices were down 20% to $2.03. At the bottom of the slide you can see the benefit of our derivative positions in the fourth quarter. Once again, adding significant cash to the company. Because of that position, we added about $281 million of cash flow in the Q4 related at our derivative position and about $875 million for the year. As we look forward, Scott mentioned we're 85% hedged in 2016 and 70% on gas. And that derivative portfolio at year end was valued at roughly $750 million. With what's happened to prices since year end, it's well over $800 million today.

Turning to slide 18 and production costs. A continuation of improvement here where our production costs for the quarter were $11.02, down about 5% from the third quarter. If you look at base LOE, it was also the main contributor where it was down 5% quarter-on-quarter. But probably more impressive is it was down 22% relative to the 2014 average. And so most of that is really just the company's cost reduction initiatives throughout the year.

Turning to slide 19 and our balance sheet in just a little bit more detail. At the end of the year, we had net debt of $2.3 million. As Scott mentioned, we're probably in the position of the best balance sheet in the industry today. If you take into account the equity offering of $1.6 billion of proceeds, the incremental $500 million of proceeds from the EFS midstream sale that we'll get midyear, our net debt is basically $200 million at the end of the year. If you look at the maturity schedule there, you can see the 2016 and 2017 maturities. Those are the ones that we pre-funded back in December on the chart here, the 2021 proceeds and the 2026. Probably the important thing here is that we reduced our interest rate as we pay those off in order of magnitude of 2% in each of those cases. So, overall, the company with cash on the balance sheet, taking care of our near term maturities, the equity offering, undrawn credit facility, we have a great liquidity position as we move into 2016 and 2017.

Turning to slide 20. Looking at first quarter guidance. Daily production 211,000 to 216,000 BOEs a day. As Tim mentioned, that does reflect the higher shut in volumes due to offset fracs as we're completing wells near existing infrastructure that have wells already connected to it. Production cost down slightly just to reflect our cost reduction initiatives to $10.50 per BOE to $12.50 per BOE. Other one worth noting is DD&A $18.50 per BOE to $20.50. Generally, you would probably expect that to be down a little bit more, given the impairment charge. But I think it's important to note that our approved reserves that we calculate at the end of each quarter reflect a trailing 12 month average prices. As you're aware, prices continue to fall and so that 12 month average will come down, which will affect our end of life reserves that will become uneconomic a little sooner. So I think that offsets to a certain extent the impairment charge related to Eagle Ford.

Interest expense. Higher just reflecting the new bonds that are in there. Once we pay off the 16th and 17th that will drop back down to the levels we've seen in past quarters. On other expense, $70 to $80 million. That is up. It comprised of three big components in there are $20 to $25 million of stacked drilling rig charges that we expect in the first quarter as a result of our rig reduction activities. We also have about $20 to $25 million of unused transportation and gathering commitments in there, and then lastly, about $20 million related to the third party component of our pressure pumping business that we recognized a loss on that's principally non-cash due to depreciation, basing it on a cash basis where we're break even. The other items here are consistent to what we've had in prior quarters so I won't go into those.

So with that, why don't we stop there and we'll open the call up for questions.

Question-and-Answer Session

Operator

Thank you. [Operator instructions] And we'll go first to Brian Singer at Goldman Sachs.

Brian Singer

Thank you. Good morning.

Scott Sheffield

Good morning, Brian.

Brian Singer

You highlighted the strip coming down $10 as why you pulled back just a bit here on the CAPEX. Can you talk more specifically on what oil price you need to see to bring activity back to 18 rigs? Whether the six rigs would go back to the areas from where they originally were? And then what oil price you need to see to bring back officially that long term growth guidance of 15% total and 20% for oil?

Scott Sheffield

Brian, I think if you take away this year and you just look at the strip from 2017 going forward, obviously we'd be bringing back rigs. I think this year we're going to see weakness over the next three to four to five months. It's probably going to stay in the 20s and then it's going to start bouncing back up as we see five, six, 700,000 a day of U.S. shale decline. And so I'm encouraged of somewhere between 40 and 50 for 2017. That will allow us to start back up more rigs. Longer term, I think if we get out of the 40s and get back to 50 plus that you can see us with a strip and continuing in Contango going up from there, I think we can easily get back to the 15% plus range.

Brian Singer

Thank you. Appreciate that. And then also we appreciate the color on what you're doing on the completion optimization front. And just putting a few things you said, your Wolfcamp wells are outperforming your type curve, your Spraberry wells are, too. And then you're increasing your completion optimizations in 2016. The question would be what would you need to see to take up your guidance further for EURs versus the 0.8 to 1.2 and then BOE that you highlight? Or is there some positive impact from high grading that you're seeing relative to the average of well locations that remain?

Tim Dove

Yeah, Ryan, this is Tim. I don't think high grading is really a factor because we're drilling in all of our eight subset areas with rigs as we speak. And the whole objective there is to continue learning. I guess I would focus on the fact that that's exactly what we're doing in 2016 is focusing on understanding the completion optimization by area by zone. And I can tell you, it's not a cookie cutter approach. All these rocks take different fracs, different ways. And so that's why we're a little hesitant to say definitively we have it all figured out because it's going to take a lot more time. And as I said on the call, we only have limited data set really on the Wolfcamp A, as an example. And for that matter, relatively limited data set on Spraberry shale. So I think what you'll see us due in the fullness of time is be able to show you more data by area by zone, and I think we can land on where we think the ultimate sort of positioning should be vis-a-vis those curves when that happens. We just need a little bit more time in the lab to understand exactly what these wells can do.

Brian Singer

Great. Thank you very much.

Operator

We'll go next to Evan Calio at Morgan Stanley.

Evan Calio

Good morning, guys.

Scott Sheffield

Good morning.

Evan Calio

You discussed moving -- you'd adjust the rate count and then moving a pair of completion crews from Eagle Ford to Midland. How many crews are you running in 2016? I'm just trying to understand your view of the growth trajectory in 2016, given Q1's guidance, which I know reflects some shut ins.

Tim Dove

Yeah, Evan, this is Tim again. Right now by moving two fleets, which we're in the process of doing right now, we'll have eight fleets running. And that'll be the beginning point. It's possible we could reduce the number of fleets running as we get into the second half of the year and be able to achieve exactly the same amount of results. But right now we'll be running eight, essentially through the first half of the year.

Evan Calio

And is there any discretionary -- do you see builder draw in 2016 in Midland?.

Tim Dove

Could you repeat the question one more time?

Evan Calio

Sorry. I didn't know. Is there a discretionary DUC build or draw in your 2016 guidance?

Tim Dove

Oh, yeah. I didn't understand you. Sorry. Yeah, we're not ducking any wells in the Permian. We're just going to be continuously completing the wells there with our fleets. And so you will not see any ducks in Midland basin.

Evan Calio

Great. And lastly, if I could, just maybe on the flip-side or the other side of Brian's first question. I know that you guys have significantly more flexibility than peers, but where would you decrease your activity as you move into 2017. Any kind of price sensitivities there would be appreciated.

Scott Sheffield

Obviously, if we stay sub 30 for the next six or nine months, we're going to have to reduce activity. But if we stay sub 30, no OPEC action, not much production decrease in the strip. And if going into 2017 drops way below 40, then we're going to have to reduce activity.

Evan Calio

Okay guys. Appreciate it. Thank you.

Operator

We'll move next to Doug Leggate at Bank of America.

Doug Leggate

Thanks. Good morning, everybody. Tim, looking at the slide, I think it's on slide 13, it pointed to 1.2. The comment that goes along with that is I add ours up to 30% at current strip. So what's the variability and why would you be continuing to drill the lower end of that, assuming that you're not going to raise it at some point? Because I'm guessing that the frilly loaded returns are going to be level at 30. Can you just elaborate on that a little bit? And I've got a follow-up, please.

Tim Dove

Well, as you look at, Doug, the range of data that we're talking about from the standpoint of what these zones have been able to accomplish, we have a range that's actually 800,000 up to 1.2 and probably higher.

To the extent we're drilling Wolfcamp A intervals, I mentioned on the call that we're -- this is in the south I'm talking about. But obviously be limiting the number of wells in the south, but our southern Wolfcamp A wells actually do range from 800,000 to a million BOE. That's why we have the range down that far. They'll be a very limited number of those wells drilled, however. So the vast majority of wells that will be drilled will be million barrel to 1.2 or higher. So the reason we put the range in there simply is to make sure that we can cover all the different angles in the different zones. But I can assure you that our focus will be on the Wolfcamp B, as I mentioned, and the Wolfcamp A, and to a lesser extent, lower Spraberry shale. But all of those, as shown on the prior graphs, are well exceeding one million BOEs in most cases. And so we do try to be conservative on this. The returns, I think, are roughly in that 30% range today, based on strip prices. There's some numbers slightly above and slightly below, but that's kind of the way we look at it from the standpoint of 1 to 1.2 million barrel type curves.

Doug Leggate

Okay, thanks for that. My follow-up, really two parts to it, I guess. First of all, to come back to Scott's comment about if oil prices stay depressed, you have an extremely valuable hedge book and one with a margin that if you took the view of $26 as getting as close as perhaps any of us could have predicted. At what point, to the extent you're only down two, does the hedge become a source of funds? You know that you need it, but just in terms of maximizing value of that hedge book. . My related follow-up, I guess, is given the slowdown in activity, it seems [indiscernible] values are still holding up relatively well considering the collapse in the commodity. So obviously you're not going to get to any recourse to your inventory in any reasonable timeline, so where did you see the potential for liquidation? Again, knowing that you don't need the money, but in terms of how you maximize volume.

Rich Dealy

Yeah, Doug, the problem is we may look at it one month at a time, but the problem, as you know, operating costs around the world in most assets are lower than $26. So that's why I think a lot of people are saying it's going to go lower before it goes higher. So we actually have to see people start shutting in production. So I'm afraid it may go lower. So why unwind at 26, first question. Secondly, it's in Contango, and so it's not a flat 26 over the next 12 months. If it was a flat 26, we may have more of a tendency to unwind. But right now we have no plans to unwind our hedge fund.

Scott Sheffield

Acreage values?

Rich Dealy

Oh, acreage values, yeah, they're still running 20,000 plus in the Permian. That's always an option for us as we have pointed out in the time, to sell some of our acreage at some point in time if we need cash. Obviously, with already $2.5 billion in cash on hand, we don't need the cash but that's always a great luxury for the company to sell part of our acreage over time to fund growth. So it's an option. We're just not going to do anything today.

Doug Leggate

Thanks guys. Is there still an active market on the buy side? I mean, is there still active buyers in your mind?

Rich Dealy

It's the people that are -- they buy. I won't say any names, but they buy, go to the equity markets and deleverage. And they're doing it successfully. And then there's some private equity money out there that's paying $20,000 plus an acre too, successfully. You can see the returns are good. They're still as Tim said, up to 30%. And so, you can sit there and pay 20,000 an acre, and you're not going to get a 30% return because most of our acreage is, essentially, zero basis. So you have got build that in. And so, they're probably only getting 10, 15% returns, and they're hoping for a better price tag. But there's still some deals being done in that.

Doug Leggate

All right. Appreciate the answers, guys. Thank you.

Operator

And we'll go next to Neal Dingmann, at SunTrust.

Neal Dingmann

Morning gentlemen. Scott, could you give maybe some color on your thoughts about, obviously you still have massive acreage in Eagle Ford. Just if you could talk about maybe costs over there, or would you consider parting with some of that acreage, given you're obviously taking activity away from that?

Scott Sheffield

Of course, our activity is down zero here shortly. And we're going to have to wait until prices get back into the mid to high 40s before we start back up again. And so, it may be a while. And so, all of our acreage is held by production. And so, in today's market, I don't think you will see anybody be trading Eagle Ford production or acreage just because the prices are too low. You got to have some type of recovery, in my opinion, over the next two years, before people start moving Eagle Ford acreage and values.

Neal Dingmann

Got it. Got it. And then, you mentioned about the stack and gathering charges just for the first quarter. Is that, if you continue with this rig rate, will you continue to have approximately those type of charges going forward? How should we think about those costs going forward?

Scott Sheffield

Yeah, I think for 2016, they're going to be generally in that range, and they will come down significantly as we move into 2017 and 2018.

Neal Dingmann

Okay. And then, just lastly, I think you hit this Scott, but I think Doug maybe asked about sort of the all-in costs and the returns. How do you look at it, as far as deriving some of your returns on a cash cost versus your all-in cost? I mean, is it as long as you're achieving ahead of those cash costs, you're certainly going to keep drilling or maybe even accelerate? Or is it more based against an all-in cost or return? How do you think about that?

Scott Sheffield

Yeah, the returns that Tim was quoting, well, first of all, it includes all SWD, all-in costs at the least. So it includes SWDs, it includes any seismic, it includes acreage cost, which was generally very minimal. It does not include our G&A and interest. And so, G&A and interest brings those down to probably 10% to 15% type returns.

Neal Dingmann

Now that makes sense. Okay, thanks for all the details, guys.

Operator

We will take our next question today from Jon Wolff, at Jefferies. Sir?

Jon Wolff

Good morning. Good morning. Noticing that Mid-Cush differentials have been pretty flat and, at times, at premiums. One story I heard was that, with all the new pipe setting East, the refiners were quite interested in Permian crude, due to its straight run characteristics for gasoline and diesel. And the other piece was that some of the pipes weren't quite full and were kind of looking for volume. So that was putting in bids. Can you talk a little bit about Mid-Cush diffs?

Scott Sheffield

Yeah. I think as it relates to us, Jon, we have most of our crude going to the Gulf Coast on one pipeline or another. We're seeing definitely interest in the market over there for WTI, but we're not seeing any, even though the export bans been lifted, any significant premium. So, I think for the time being, with the spread just got talked about coming back between WTI, there's not a big differentiation today, but, longer term, we think that will be a benefit to have our crude on the Gulf Coast and have options to move it down to South America or to Europe, over time.

Jon Wolff

All right. I guess the other point is the pipelines not being full. is that a testament to the basin having maybe slowed a little bit? Volume growth has stalled a little bit for the basin, as a whole. Or is it more just the demand center, the demand pull?

Scott Sheffield

Yeah, I think the growth has still slowed some. But I think it was just the case that more pipes were built on the view that growth was going to continue before the price fall. So I think there's extra capacity today and, hopefully, when prices rebound, the basin will be the first to pick up in the U.S., and those pipelines will start getting filled again.

Rich Dealy

Jon, anecdotally, this is really more about associated gas as it is oil. But our gas processing facilities are essentially full today, or actually overfull. That just goes to show you, the Permian Basin production is pretty resilient. That's one of the reasons, of course, why we're pushing ahead with the Buffalo gas plant. But that said, it just goes to show you, I think, oil production has been pretty resilient, also. And I think what we're really dealing with here is a demand pull off of the Gulf Coast.

Jon Wolff

Right. All right. Just a random one, since you probably know about this. 200,000, 300,000 stripper wells in west Texas. Just thinking about operating cost thresholds, as the volumes get pretty low. Hearing anything around shut-ins?

Scott Sheffield

Yeah, Jon, as we have seen in past downturns, as several of us have lived through about five of them, is that, historically, most people just don't shut it in right off the bat. And that's the problem. You have got to lose money for 3, 4, 5 months. People worried about losing leases. And so, it's going to take a good t3, 4, 5 months of real low prices before people start shutting in. They're not going to do it on one month of $15 oil or $18 oil.

Rich Dealy

Yeah, I think the other thing to add there is, the world is now developing, where we're heading more towards more 100% horizontal drilling, those wells can hold production. In holding production, allows to hold those leases for the deeper horizontal drilling, So, you got to be really careful shutting in wells that otherwise would provide for future horizontal drilling.

Jon Wolff

Yep. Got it. Thanks very much.

Operator

Our next question today is from Dave Kistler, at Simmons & Company.

David Kistler

Good morning, guys.

Scott Sheffield

Hi, Dave.

David Kistler

Just thinking about what's baked into the forward guidance. You have talked about the efficiency gains that you have witnessed kind of down 30%, Q4 to Q4. And you've talked about type curves, 800,000 to 1.2. Is that what you're baking in to 2016 guidance, or are you baking in incremental efficiencies? And are you baking in type curves closer to the 1.3 that you referenced in your January release?

Rich Dealy

Yeah, Dave. First of all, I do expect we will have some more cost savings that come out of the fact that we're 100% now on our new contract. We're on a new cementing contract with Permian here shortly. And we're still putting pressure where we can, albeit, it's relatively limited amount of pressure we can put, as low as the service costs have gone. But I think we can get some reductions. Perhaps, 5% cost reduction. We don't really have that baked in today, as much as we expect that to be in the future. So, with the numbers I gave you in my comments, 7.5, 8 million Permian wells is what we expect before any cost reductions that we can further extract. And so, from that standpoint, we're not really baking in any cost savings. By the same token, the majority of the wells we'll drill, what we focus on is a million to 1.2 million barrel wells. That's the kind of range we talk about. As you have seen and we have talked about, there's quite a large number of wells today which we think may exceed the 1.2. But the guidance we're utilizing and what we have baked in, depending about which zone you're talking about, 1 to 1.2. We hope to be able to exceed that, of course. As you know, we tend to be conservative, because it's just the way we kind of put numbers out.

David Kistler

I appreciate that. That's great color. And then, one of the things in the past you talked about doing more Wolfcamp A wells in 2016, and while the percentage is going up, it seems like you're referencing maybe a larger percentage of A's then B's in prior commentary. Not to suggest that sticking with B's is high grading, but can you maybe walk through whether that's optimization for infrastructure that is causing more B's than A's, or if I'm misinterpreting something?

Frank Hopkins

Hey, Dave. This is Frank. I think what we were referring to before was primarily the northern program. And when you add the B's in, which is the primary focus in the JV area, that's what changed those percentages some from some of the earlier numbers you heard us talk about.

David Kistler

Great. I appreciate that clarification. And then one last one. Just probably a little bit more specific. When you were talking about the cost incurred from rig stacking and from the excess firm gathering and transportation commitments, you indicated that that would be coming down in 2017 and 2018. I suspect that the rig stacking comes down, but the firm gathering and transport commitments, does that really change until you start to accelerate drilling? Any kind of color on that?

Scott Sheffield

Yeah, that definitely was just speaking to the stacked drilling charges coming down in 2017 and 2018, the firm commitment in transportation. They will grow some in 2017 and 2018 just with the reduced activity in Eagle Ford for the most part.

David Kistler

Okay, I appreciate that clarification and great work at the drill deck, guys.

Scott Sheffield

Yeah.

Frank Hopkins

Thanks, Dave.

Operator

Our next question today is from John Freeman at Raymond James.

John Freeman

Good morning, guys.

Scott Sheffield

Hi, John.

John Freeman

Just wanted to follow up and make sure I heard you right, Scott, on that kind of preliminary kind of commentary around 2017. Was it 10% growth again in 2017 at the strip using roughly half existing cash and no incremental debt? Is that right?

Scott Sheffield

Yeah, I said that we will have about $1.7 billion left at the end of this year and we'll be close to 10% production growth for 2017 and about half of that cash will be preserved by the end of 2017.

John Freeman

Perfect. And my one follow up, when I look at the new CAPEX budget versus the one last month, the one last month, how much had been allocated to the vertical integration in that preliminary budget last month versus the 150 in this one?

Frank Hopkins

Yeah. He, John, this is Frank again.

John Freeman

Hi, Frank.

Frank Hopkins

I would say roughly, while we didn't have a hard fast number, there was probably $250 million in what we call other capital category, which is what I think you're referring to and that number is now down by about $100 million.

John Freeman

Perfect. That's what I needed. Thanks guy.

Frank Hopkins

Thanks.

Operator

And we'll move next to Charles Mead at Johnson Rice.

Charles Meade

Yes. Good morning, guys. If we could go back to slide 12, and Tim I know you already spent a little bit of time on this, but the graph on the right I thought was a pretty powerful demonstration of the improvement you guys have had. And if I'm reading this right, is it -- it looks like that increased well productivity is not really a function of increased lateral length, and so Is it the right conclusion to draw that that's really what we see the progression through the course of 2015 is implementation of that completion optimization program?

Scott Sheffield

That's right. If you look at -- even our first quarter 2015 was lower than our fourth quarter. That's because we had not yet begun the optimization campaign. It started really in earnest very heavily in third and fourth quarter, of course, mostly third quarter. And you start to see that's where we get pretty significant bumps, but I think it's almost 100% related to completion optimization. Lateral lengths, on average, haven't changed that much. So it really has to do more with well performance.

Charles Meade

Got it. And if we were looking at that, this is for just Wolfcamp B, how would the picture look different, if we were to look at that for Wolfcamp A or for the lower Spraberry?

Rich Dealy

Well, Wolfcamp A, I would say, first of all, we don't have enough well control to really talk too much about that. As I mentioned, we put two wells on in the third quarter and two in the fourth quarter. So I don't think we could really step out there and say that's enough data to say definitively that the third was any different than the fourth that significantly. So I don't think you can really say much there. What you can say in lower Spraberry shale is we have been seeing improvements. And those are shown on some of the graphs. Earlier times we were talking about lower Spraberry shale being more 800,000 BOE thinking, but now you can see the data suggesting, based on what we just put on production in the fourth quarter, something that's more approaching a million. So I think you see it clearly there. The Wolfcamp A I simply say there's just not enough time and well control.

Charles Meade

Thanks for that, Tim. And then shifting over to your reserve focus and specifically the puds, it's understandable you're down to 11% puds with not just the strip but also the five year rule on puds. But can you characterize what the puds you still have on your books here at year end, what they are or where they are and how that is different from where you guys have wound up in years past?

Scott Sheffield

Similar to years past. They're predominantly in the Permian basin, as you can imagine. And with a number in the Eagle Ford, but predominantly they're all Permian basin puds. And so there's about 150 of them in total. I would say, I'm flipping here, 90% of them are in the Permian basin.

Frank Hopkins

Charles, it's Frank. They're all horizontal, obviously.

Charles Meade

Right. Right. And that pud percentage is 150 puds, that's a lower absolute number than what you have had in the past as well?

Frank Hopkins

That's right. Just under the five-year rule and where prices are, obviously we have lots of opportunity out there to add, but we have taken, as Tim mentioned, a conservative approach to it. And just want to make sure we manage the five-year rule, and do it at a slow pace.

All of those areas are technically proven. Just a matter of what the SEC will allow us to book, and what we want to book.

Charles Meade

Got it. Thanks for that added detail.

Operator

Our next question today is from Ryan Todd, at Deutsche Bank.

Ryan Todd

Great, thanks. Good morning, everybody. Maybe if I could follow up. You certainly talked about it some throughout the call, but on kind of a philosophical level. I mean, how do you think about balancing rate of return and growth? And maybe get to a little bit as to what the right level of capital is? I mean, can you walk through a little bit of your thought process? Why 12 rigs versus 14 or 10? What's the right number for the way to think about capital, and how that informs the view going forward? As cash flow increases, do you generally just ramp up as things cross the returns threshold? Or what will drive kind of the absolute level of capital spend, near term and longer term?

Rich Dealy

Yes, Ryan, first of all, returns is first. So having good returns in this price environment is number one. Number two, as I said earlier, we decided it was important to show a reduction from our January call, and also from last year. And so, we're gaining so much efficiencies in optimization, that when we saw the numbers. I mean, how many companies can reduce 50% of your rigs and still show 10% plus production growth. So we sort of targeted 2 billion capital, 10% plus production growth. And preserving most of our cash on the balance sheet all year.

Going forward, when prices recover, you will probably see us do more hedging in 2017, 2018. In three ways, most likely. And then, we will start putting rigs back to work, and the returns will even be better than what Tim mentioned, at 30%. So that's how we will look at it going forward.

Ryan Todd

Okay. I mean, I guess if you think about it directionally, I mean, you laid out a plan right now, which implies some amount of incremental growth in 2017 with this strip. Will you generally ramp proportionally to how cash flow grows?

Rich Dealy

We still got the $1.6, $1.7 billion of cash sitting out there. So it's a question of how fast we employ that. So, I can promise you, we're going to be the number one growth company in 2016 and 2017, in the industry. Most likely 2018, because we have a great balance sheet and we can jump start quicker than anybody else. Most companies are going to have to rush out and sell assets, or go to the equity markets, at some point in time, to deleverage. And so, we will be focusing on adding rigs back to work fairly quickly. With 30 days' notice, we can add rigs back. So, we will have to decide on what growth rate is right in that 2017, 2018 environment. But I said we could get back to 15%. I told Brian Singer that, if oil got back to between 50 and 50-plus, on its way in the strip towards 60, we will probably be hedging and probably moving toward that 15% production growth rate.

Ryan Todd

Great. I appreciate that. And maybe if I could ask one more. Production levels in the U.S. have continued its price to the upside. Yours included. I think some of that is clearly efficiency gains. it does seem as well as if some of the base production is holding in a little bit better than expected. I mean, can you talk a little bit about what you're seeing, in terms of base decline across your portfolio? Whether it's better or worse than you thought it would be, and whether the optimized completions, looking forward, whether you think they'll have any impact on declines going forward?

Rich Dealy

Well, on Eagle Ford, at least we will be able to establish a decline now, since we have zero rigs running. And so, we got a pretty good handle on that. And Permian is doing much better than expected. And with our balance sheet, that's why we're able to grow. Now, everybody, I read all of you all's reports, and most of you all are saying that, so far, people were reporting future reports that U.S. shale should drop 5, 6, 700,000 barrels a day. So, that has to happen so we can have a meaningful recovery in prices by the end of the year. If it doesn't happen, then the recovery is going to be a lot slower. So, I get it mostly from you all reports, based on other people's reporting.

Ryan Todd

All right, great. Thanks for saying that.

Rich Dealy

Balance sheet is the problem.

Ryan Todd

Right. Thank you.

Operator

We'll go next to Jeffrey Campbell, at Tuohy Brothers Investment Research.

Jeffrey Campbell

Good morning. Regarding the cessation of the drilling in the JV, was this a joint agreement, or does Pioneer have priority as the operator on deciding if drilling takes place or not.

Scott Sheffield

Are you talking about, in this case, the southern Wolfcamp area?

Jeffrey Campbell

Correct.

Scott Sheffield

During the period, we have basically unilateral rights to make the decisions regarding what's going to get drilled. However, we don't really run a JV that way. We closely consult with our partner. In this case, Sinochem, and we have come to a joint agreement on this rig count.

Jeffrey Campbell

Okay, thank you. The reason I ask is just because you highlighted that the best wells in the southern JV look very competitive. So, just kind of wondering…

Scott Sheffield

Certainly, if you look at the map and where we see the best well results, they clearly are in the northern part of the southern acreage. I think we can drill very good economic wells there. However, our partner's in a situation where they have their own views and they have their own situation. And so, we can just simply take those rigs and focus them on the north, and be able to achieve at a high rate there.

Jeffrey Campbell

Okay, thanks. That's helpful. And sticking with southern JV, what's the timing of 2016 placing on production? I'm just wondering how to correlate the production coming online with the fact that drilling is going to cease after the middle of the year.

Scott Sheffield

Well, yeah, the drilling campaign will be done in the middle of the year. Of course, in the case of the south, we will be completing those wells through the third quarter.

Jeffrey Campbell

And if I could ask one last one real quick. You provided a 7.5 to 8 million cost range for 9,000 foot lateral, currently. What percentage of 2016 drilling is expected to average around 9,000 feet? If there's drilling that's not going to be around that average, what kind of numbers are you thinking about?

Rich Dealy

The average is going to be about 9,000 feet. Maybe slightly above that. Realizing that we are now drilling wells in excess of 12,000 feet, in some areas where we can and where the leasehold provides for that. We also drill wells, in some cases, at 7 to 8,000 feet. So the average comes to slightly over 9,000 feet.

Jeffrey Campbell

Okay, great. Thanks very much. I appreciate it.

Operator

We'll go next to Bob Morris, at Citi.

Bob Morris

Thank you. Scott or Tim, two quarters ago, when you first talked about handing 2 rigs per month through the second half of the year, you had said then that, if you got to year end, when you were at the point of turning those wells on, that if oil prices were still lower, that you just wouldn't turn the wells on. And I recognize that efficiencies have improved since then. You have added some incremental hedges since then. And that you look at returns on a strip basis here. But, Scott, given your view that oil prices are going be weaker. Over the next few months, could drop even lower, why not still not turn those wells on at this point and just wait the 3 to 4 months or 6 months, whatever it is, until oil prices are a lot higher and build an inventory of ducks, like you're doing in the Eagle Ford, or like a lot of your peers are doing here?

Tim Dove

Well, there's still 475 rigs, 450 drilling oil wells in the U.S. It's a shame we can't all get together. It's collusion, I guess. The federal government calls it shutting everything in at once. But we have to preserve our people. We got over 20,000 drilling locations. So keeping a few locations going on. And based on the strip, we all knew what the strip was over the next 5 years. We can make different decisions, but we don't. We're keeping them going because of the strip and the returns are good. They're not 25, for the next 5 years. If I knew they were going to be $25, $30 the next 5 years, we wouldn't be drilling any rigs today. But I don't.

Scott Sheffield

So, Bob, I guess I would add on to that by saying, one of the real big objectives for us, and I've alluded to it quite a bit on this call, is to make sure that we push forward our knowledge regarding optimization of completions. And so, just drilling a well doesn't cut that, and we got to get them on production and see how they produce. Get the learning’s in place so that when we actually reach the upturn that we're ready to accelerate at a high level of performance, because we built that knowledge base about how to optimize completions in the different areas, for the different zones. So, ducking wells just doesn't cut it. And from that standpoint, we have got to keep moving ahead, in terms of our knowledge base, so that when things improve, we can hit it with all cylinders.

Bob Morris

Okay, great. Thank you.

Operator

We will go next to Paul Sankey at Wolf Research.

Paul Sankey

Good morning, everybody. Thanks for all the information. I was just wondering on your hedging strategy, you mentioned that you're 85% covered for this year and 20% for next year. If we just do the strip as what happens over the next year, would we assume that you would basically be in 2017 in a year's time in a similar hedge position, which is to say unhedged more or less or 20% hedged? Or would you sort of just start adding anyway? Thanks.

Scott Sheffield

Yeah, Paul, there's a lot of volatility in the market. If you look at the last 12 months it's moved around $8, the strip. And so obviously, I'm hoping that there's some actions or rumors or whatever it takes to move the strip up over the next several months. And we will probably be fairly aggressive in hedging in 2017. So it's hard to -- if the strip moves down from here, we're not going to be hedging any more in 2017. But I think there's a good chance with news reports of U.S. shale falling or rumors by Russia or I guess there's one today about a freeze on OPEC production. You've got to use events like that to put hedges in the marketplace.

Paul Sankey

True, I understand. So you want to retain the discipline that you've shown in terms of maintaining a hedge book, but perhaps not just as low as we are today?

Scott Sheffield

Exactly. There will be chances that it spikes, the 2017 strip over the next ten months and we will probably be putting on some hedges.

Paul Sankey

Okay. And separately, the operating cash flow guidance that you gave of $1.3 billion at $36 a barrel, we're coming in a bit low on our numbers. First, wondering is there any working capital changes or anything else in the number that we should account for or can you back us into that number just so that we're very clear? Thank you.

Scott Sheffield

Yeah, it's in the operating cash flow. I mean there's not much in the way of working capital changes, so it was just when we put together the charts that was the price tick at the time. Obviously, the commodity deck has moved since then and so we will continue to watch it and see where we end up. But at 36 and 235 we think we will be at the $1.3 billion level.

Paul Sankey

Yeah. We just wanted to clarify this, if you like a clean number. But I appreciate that. Thank you all.

Operator

We'll take our next question today from Michael Hall at Heikkinen Energy Advisors.

Michael Hall

Thanks. Many of mine have been addressed. I'm just curious, as you look at the 2016 program now versus what you provided a little over a month ago, it seems like Permian's outperforming even over that timeframe, given the reduction in the Eagle Ford, in particular. I'm just curious, I guess. Number one, what was the prior expectation around Eagle Ford as it relates to production growth or declines on the prior rig count? And then did you change at all your assumptions around the Permian on risking your productivity or anything on the like?

Scott Sheffield

Yeah, Michael, first of all, on Eagle Ford, we had stated that in the range of four to six rig count that we would be basically able to keep production essentially flat. At the time during the call, remember we talked about reducing it to four with the potential to reduce it lower. So, obviously in today's world, Eagle Ford production will be declining. It's simply a product of the fact that there's, in our areas particularly, there's quite a lot of NGLs and natural gas in the flowstream, as well as the fact it condensates in our area. It fetches a price which is generally going to be $10 off WTI. So, in today's world, let's just say $17 per barrel. So the economics is we're getting trounced by the commodities on all three fronts and that led to the decision.

By the same token, if you look at Permian, however, the Permian assets pretty clearly are continuing to outperform. I would expect that to be the same going forward as we put our team of geoscientists and engineers to work in the laboratory understanding how to complete all these wells optimally. And that's what's going to happen. And so it's a nice trade to be able to take monies out of Eagle Ford, where the economics are not very good today, and put them in an area that's outperforming.

Michael Hall

Certainly. Yeah, it makes plenty of sense. I guess, touching on offset a little bit, the completion optimization program in the Permian, I guess we've seen a huge, obviously 50% as you showed step change year-on-year in the Wolfcamp B program. Other programs are moving along the learning curve as well. I'm just curious how you think that rate of change changes over time. And how quickly does that rate of improvement flatten out? Maybe using the Eagle Ford as an analogy?

Scott Sheffield

Well, I think first of all the optimization campaign at Eagle Ford took a couple of years for us to pull off. But Eagle Ford is much smaller aerial extent and quite a smaller amount of shale in the sense that the 300 foot or so that you have at Eagle Ford. You have to focus on the fact that even in 2016 we're changing what we're doing in terms of optimization. We're pushing the limits. So we're not standing pat on the 2015 campaign optimization, as I mentioned, we're now looking at, for example, going into a situation where we might even have 15 foot cluster spacing. That would have been unheard of in the past. We'll see how that does. We'll see how we do in terms of increasing our profit concentrations up to let's just say 2,000 pounds per foot. We'll see how we do in terms of spacing and stacking situations in different zones. So I would say we're still pretty early days. We're still improving, we're still learning with every well. And I would anticipate that going through the 2016 campaign and realizing that's one of the reasons we need to keep some rigs running is because we need to get to the end of the plan so when we're ready to add rigs, we're doing it optimally.

Michael Hall

Yep, that's certainly encouraging. It makes sense. And then, I guess, last one on my end, around the commentary about 10% growth in 2017, what sort of rig count assumptions are baked into that?

Scott Sheffield

It's about the same. No change.

Michael Hall

About the same, okay. Very good, appreciate it.

Operator

We'll take our next question from David Beard, at Coker Palmer.

David Beard

Good morning, gentlemen. Appreciate you squeezing me in here. My question is really related to the scenarios for 2017. And you mentioned, if oil stays sub-30, you may reduce activity. Should we think about you being cash flow neutral, if oil stays lower next year? Or how would you think about cash burn next year in a low oil price environment?

Rich Dealy

We haven't made those runs. But, obviously, we have preserved most of our cash position of the $1.7 billion that I talked about going into 2017. So, cash flow probably 700, 800 million, at $30 oil. I'm just guessing off the top of my head. Rich is looking at me. So, you probably get down and just spend 700, 800 million, if that, and then preserve your $1.7 billion.

David Beard

Good. I appreciate the color. I know we're all playing "what if" here with the commodity prices. But thanks for the time.

Rich Dealy

Yeah.

Operator

And ladies and gentlemen, that is all the time we have for questions today. I would like to turn the program back over to our speakers for any additional or concluding remarks.

Scott Sheffield

Again, thank you very much for participating on the call. I look forward to seeing everybody out on the road or the next quarter. Again, thank you very much.

Operator

And, Ladies and gentlemen, once again, that does conclude today's conference and, again, thank you all for joining us today.

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