先鋒自然資源 (PXD) 2015 Q4 法說會逐字稿

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 a 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 and webcasts. Today's call is being recorded. A replay of the call will be archived on the internet site through March 7, 2016.

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 the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in 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'd like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Mr. Frank Hopkins. Please go ahead, sir.

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 in 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 will also provide more details in the Spraberry/Wolfcamp drilling program. Rich will then cover the fourth-quarter financials and provide earnings guidance for the first quarter. And after that we'll open up the call for your questions.

Scott, I'll turn the call over to you at this time.

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% of oil. The top end of our guidance, revised guidance of 213,000 to 215,000. That's an increase of about 4,000 barrels per 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 2014. Oil production was up 18,000 barrels of oil 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% drillbit reserve replacement of 210 million barrels of oil equivalent at a drillbit fine F&D cost of about $10 per BOE. Again, shows you the true prolific nature of the Midland basin and the Wolfcamp, with average operating cost of a typical Wolfcamp well of $5 and a fining cost about $10. It still shows it's very economical in today's environment to be still drilling in this play.

Slide number 4, we did place 44 horizontal wells on production in the Spraberry/Wolfcamp during the fourth quarter. As expected, early production from 35 wells in 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 of 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 by us, by another producer. It's a first WTI cargo I saw, and 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 I've seen go out before that were a couple of the Eagle Ford oil cargos from the Eagle Ford Play 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'll have 17 docks that we'll 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 midyear to fully utilize the rest of the carry from Southern Camp. 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 feel like that we wanted to get our capital budget down to 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 and drilling activity in vertical integration spending results and capital expenditures of $2 billion for 2016; that's down from our preliminary forecast in early January from $2.4 billion to $2.6 billion and from actual spending in 2015 of $2.2 billion. That's $1.85 billion for drilling. That does include tank batteries, SWDs, saltwater disposal wells, and gas processing facilities. Additional $150 million for vertical integration systems upgrades 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 the 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 is in the north. I won't go over the detail here. But any questions, please give Frank and Mike and 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 midyear 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 US marketplace. Again, we have the firepower to start it back up fairly quickly. We're looking at 224,000 barrels 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've given out guidance of about 211,000 to 216,000 for the first quarter. 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. 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 details about operations.

Thanks, Scott.

We continue to be very encouraged by the results of our drilling and completion program in the Midland Basin. I'll 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 line represents those wells' early production. 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. It's very clear that these wells are tracking well above that 1 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 graphs. You can see there's very little production data.

Current thinking is that we'll be seeing more data as time goes on, but we're putting these wells on gas system almost immediately. They had IP rates of about 1,570 barrels per day. Of course, early in the life of these wells -- we'll be reporting more about those next quarter. When you look at the performance of the wells from the third quarter, it's very clear that we have similar results in the sense of you 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 limited data set on A wells -- only 2 -- but they're performing exceptionally well. Well over the 1 million barrel type curve; and as we look at the third quarter of B wells, they also have performed exceptionally well. You can also see from this graph that we're improving quarter to quarter sequentially in terms of the performance of these wells. And that has to do with the 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. You can see the uplift we're generating as 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 four to five. 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 1,500 pounds per foot from a total of about 1,100 from prior completions.

We're going to outline a little bit later in this 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 with 2,200 barrels per day on a BOE basis. And that compares with 1,900 in terms of the campaign from the third quarter. So dramatic increase as we continue to see as completion optimization is paying off very well.

Turning that aside, slide 10, we've seen similar successes in the lower Spraberry shale where we POPed 11 wells during the quarter. The early production results, as you can see on the graph, are close to the same 1 million barrel EUR type curve. We did completion optimizations on 9 of the 11 wells, essentially using the exact same style of frac optimization, completion optimization, that I mentioned regarding the Wolfcamp zones. The production on some of these wells is really continuing to build. In fact, only 5 out of these 11 wells have actually reached their IP rates. They're continuing to build -- not atypical from lower Spraberry shale wells as we take the water off the system, oil rates increase and peak quite a long ways into the early production life. 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 of the Wolfcamp, where we're using essentially the same optimization techniques. And we placed 9 wells on production in the Southern Wolfcamp area. Of the 8 Wolfcamp B wells you can see in the graphs below, particularly on the left blue line, tracking above 1 million barrel type curve; and the Wolfcamp A well that was drilled, 1 of the 9 wells showing the red curve on the right is tracking between 800,000 BOE and 1 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've 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're dropping our costs dramatically, sequentially from quarter to quarter. We've increased our cost for D&C in the north B wells by an average of 30% over the last year, which is really a phenomenal result. At the 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; and 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 1,250 in this last fourth quarter.

It's pretty clear if you look at data that IPs are well-correlated to well EURs. 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, this is now reflecting on the 2016 campaign for the Spraberry/Wolfcamp D&C budget. As Scott has already mentioned some of this, so I'll be brief. We're 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 lower Spraberry shales. About 190 wells in the north and 40 in the south. Despite the fact we've had weak commodity prices, as I've mentioned earlier, we're still generating good returns on the wells we're drilling. The optimization campaign is certainly helping that.

What we're planning on doing in certain areas is actually furthering that optimization campaign to, for example, in some areas actually reduce these stage links of the cluster links 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 1,700 to 2,000 pounds per foot. At the same time we continued to experiment with less core 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 really are 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're going to learn a lot this year, and it's one of the benefits of continuing a drilling campaign.

Costs are coming in about $7.5 million to $8 million, and that's based on 9,000 foot lateral and incorporates the optimized completion costs. In the program that we're talking about, in terms of production growth, we're incorporating EURs that range, depending upon the zone, from 800,000 BOE to about 1.2 million BOE depending on which zone we're dealing with. We have IRRs in this campaign, even at current strip prices, that are up to 30%. As Scott already mentioned, [what a] cost [being] loaded to develop this production, and with operating cost 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 saltwater disposal facilities, we'll 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 that 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 costs to hook wells up. We'll 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 startup 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. That's going to save us a tremendous sum, about calculated to $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 main line expansions and 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 Brady Sand Mine 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 is about 44 horizontal wells. But the only way you can explain the fact we're outperforming is these wells have very strong IP rates, as I showed on prior slides. 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 of 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 we have offset fracs being three times greater than occurred in the fourth quarter, in the first quarter. The reason for that is we're POPing these wells, we're fracing the wells near existing pads. The objective is, of course, to save infrastructure cost. Of course, 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'll sum it up by saying these operating results give us a lot of confidence that the Spraberry/Wolfcamp assets can perform well, in a compressed commodity price environment. Which means we're poised to accelerate development of these assets when prices improve.

With that, I'll pass it over to Rich for review of the fourth-quarter financials and his outlook for the first quarter.

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 noncash mark-to-market derivative losses of $13 million after tax or $0.09, and 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 noncash of about $542 million after tax or $3.63, primarily as a result of the reduction in commodity prices. Then we had other noncash 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 early January in conjunction with the equity offering -- you can see that all the items came in where we would have expected within guidance. We're on 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 change 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 here that oil was down 11% to $37.92. NGLs 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 that position. We added about $281 million of cash flow in the Q4 related to 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. 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, continuation of improvement here, where our production cost 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. So most of that is really just the Company's cost reduction initiatives throughout the year.

Turning to slide 19, our balance sheet, a little more detail. At the end of the year we had net debt of $2.3 billion. As Scott mentioned, 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 an important thing here is that we've reduced our interest rate as we pay those off in an 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 per 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 costs 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'd 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 trailing12-month average prices. As you're aware, prices continue to fall; and so that 12-month average will come down, which will affect some of our end-of-life reserves that will be uneconomic a little sooner. 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 2016s and 2017s, that will drop back down to levels we've seen in past quarters. On other expense, $70 million to $80 million that is up. Probably the three big components in there are $20 million to $25 million of stacked drilling rig charges that we expect in the first quarter as result of our rig reduction activities. We also have about $20 million to $25 million of unused transportation in gathering commitments in there. And lastly about $20 million related to the third-party component of our pressure pumping business that we recognized a loss on. That's principally noncash, due to depreciation; basically, on a cash basis we're break even. The other items here are consistent with what we've had with prior quarters, so I won't go into those.

With that, why don't we stop there, and we'll open the call to questions.

Thank you.

(Operator Instructions)

We'll go first to Brian Singer with Goldman Sachs.

Thank you. Good morning.

You highlighted the strip coming down $10 is 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 6 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.

I think if you take away this year and you look at the strip from 2017 going forward, obviously we'd be bringing back rigs. So 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. Then it's going to start bouncing back up as we see 500,000, 600,000, 700,000 barrels a day of US shale decline.

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 continuing in Contango going up from there, I think we can easily get back to the 15%-plus range.

Thanks. Appreciate that. Also 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 out performing 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 MMBOE 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?

Yes, Brian, 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 objection there is to continue learning. I'd focus on the fact that's exactly what we're doing in 2016, is focusing on understanding the completion optimization by area, by zone.

I can tell you it's not a cookie cutter approach. All these rocks take different fracs different ways. 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.

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 on the lower Spraberry shale. So I think what you'll see us do in the fulness of time is be able to show you more data, by area, by zone. I think we can land on where we think the ultimate positioning should be vis-a-vis those curves when that happens. We just need a little more time in the lab to understand exactly what these wells can do.

Great. Thank you very much.

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

Good morning, guys.

Good morning.

So you discuss moving -- you discuss the rig 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 1Q's guidance, which I know reflects some shut-ins.

Yes, 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 will be the beginning point. It's possible we could reduce the number of fleets running as we get in to the second half of the year and be able achieve exactly the same amount of results. But right now we'll be running eight really essentially through the first half of the year.

Is there any discretionary, do you see builder drawn in 2016 in Midland?

Can you repeat the question one more time?

Sorry, I didn't know if I saw -- is there a discretionary DUC build or draw in your 2016 guidance?

We're not DUC'ing 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 DUCs in midland basin.

Great. Lastly if I could, on the other side of Brian's first question, I know you have significantly more flexibility than peers, but where would you decrease your activity as you move in to 2017? Any kind of price sensitivity there would be appreciated.

Thank you. If we say sub 30 for the next six, nine months we're going to have to reduce activity. If we just stay sub 30, no OPEC action, not much production decrease in the strip, and going into 2017 drops way below 40 then we're going to have to reduce activity.

Great. Appreciate it. Thank you.

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

Thanks. Good morning, everybody.

Tim, looking at the slide, I think it's on slide 13, the 0.8 MMBOE to 1.2 MMBOE, the comment that goes along with that is IRRs up to 30% at current strip.

What's the variability and why would you be continuing to build the lower end of that assuming you're not going to raise the type curve at some point? Because I'm guessing that the fully loaded returns are going to be well below 30. Can you just elaborate on that a little bit? And I've got a followup, please.

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 BOE up to 1.2 million BOE to probably higher. To the extent we're drilling Wolfcamp A intervals, I mentioned in the call that we're -- the range, this is in the south I'm talking about.

We'll obviously be limiting the number of wells in the south, but our southern Wolfcamp A wells actually do range from 800,000 BOE to 1 million BOE. That's why we have the range down that far. There will be a very limited number of wells drilled however. So the vast majority of wells that will be drilled will be 1 million barrel to 1.2 million BOE or higher.

The reason we put the range in there is simply is to make sure that we can cover all the different angles and the different zones. But I can assure you that our focus will be on the Wolfcamp B as I already mentioned and the Wolfcamp A, and to a lesser extent lower Spraberry shale. But all of those are, as shown on the prior graphs, are well exceeding 1 billion 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. And there's some numbers slightly above and slightly below. That's the way we look at it from the standpoint of the 1 million to 1.2 million barrel type curves.

Thanks a lot. My followup is really two parts.

First of all, going back to Scott's comment about if oil price stay depressed, you have an extremely valuable hedge book. And going with the margin that if you took the view that $26 was getting us close to a floor as perhaps any of us could have predicted, at what point do you, to the extent you've already [bound tools], does the hedge become a source of funds? Not that you need it, but just in terms of maximizing the value of that hedge book.

My related followup is, given the slowdown in activity, it seems though that acreage values are still holding up relatively well considering the collapse in the commodity. So obviously, you're not going to get to anywhere close to your inventory in any reasonable timeline, so where do you see the potential for liquidation, again knowing you don't need the money, but in terms of how you maximize value? I'll leave it there.

Thanks.

Doug, the problem is we may look at it one month at a time, but the problem is as you know operating cost around the world are in most assets are lower than $26. So that's why a lot of people are saying it's going to go lower before it goes higher. 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 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 book.

Acreage values.

Oh, acreage values, they're still running 20,000-plus in the Permian. That's always an option for us as we've 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 always part of our acreage over time to fund growth. So it's an option, we're just not going to do anything today.

Thanks, Scott. Is there still an active market on the buy side? Is there still active buyers?

It's the people, they buy -- I won't say any names, but they go to equity buy, go to the equity markets and deleverage, and they're doing it successfully. Then there's some private equity money out there that's paying $20,000-plus an acre or two successfully. But as you can see the returns are good. As Tim said, they're up to 30%.

So you can sit there and pay $20,000 an acre and still get -- you're not going to get a 30% return because most of our acreage is essentially zero basis. So you've got to build that in. They're probably only getting 10%, 15% returns and they're hoping for a better price deck. But there's still some deals being done in that.

Appreciate the answers. Thank you.

We'll go next to Neal Dingmann at SunTrust.

Good morning, gentlemen. Scott, just could you give maybe color on your thoughts about, obviously, you still have massive acreage in the 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?

No, well of course our activity is down to 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. So it may be a while. So all of our acreage is held by production.

In today's market, I don't think you'll see anybody be trading Eagle Ford production or acreage just because the prices are too low. You have to have some type of recovery in my opinion over the next two years before people start moving Eagle Ford acreage in values.

Got it. 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?

I think, this is Rich, for 2016 they're going to be generally in that range. Then they'll start -- they'll come down significantly as we move in to 2017 and 2018.

Okay. And then just lastly, I think you hit this, Scott. But you were talking about, I think Doug maybe asked about the all in costs and the returns. How do look at it as far as deriving some of your returns on a cash cost versus your all-in cost?

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 based against upon an all in cost or return? How do you think about that?

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

That makes sense. Thanks for all the details.

We'll take our next question today from Jon Wolff at Jefferies.

Good morning.

Noticing that mid-cush differentials have been pretty flat to NYMEX and at times at premiums. One story I heard was with all the new pipes heading 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 looking for volume. So that was putting a bid. Talk a little bit about WTI or mid-cush diffs?

I think Permian as it relates to us, Jon, we have most of our crude going to the Gulf Coast in one form in one pipeline or another. We're seeing definitely interest in the market over there for WTI. But we're not seeing, even though the export ban has been lifted, any significant premiums.

So I think for the time being with the spread that Scott talked about coming back between Brent and 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.

Right. The other point is the pipelines not being full. Is that a testament to the basin having maybe slowed a little bit? The fine growth has stalled a little bit for the basin as a whole, or is it more the demand center, demand pool?

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

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

Right. Just a random one since you probably know about it, but 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?

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

I think the other thing to add there is in the world that's now developing, where we're heading more toward 100% horizontal drilling, those wells can hold production. And in holding production, last to hold those leases for the deeper horizontal drilling. You've got to be really careful shutting in wells that otherwise would provide for future horizontal drilling.

Got it. Thanks very much.

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

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

Yes, Dave, first of all, I do expect we will have more cost savings that come out of the fact that we're 100% now on our new tubulars contract. We're on a new cementing contract in the 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. The numbers I gave you in the call or in my comments, 7.5 million, 8 million Permian wells is what we expect before any cost reductions that we can further extract. 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 will be what we focus on is 1 million to 1.2 million barrel wells.

That's the range we talk about as you've seen, and we've talked about. There's quite a large number of wells today which we think may exceed the 1.2 million, but the guidance we're utilizing and what we have baked in, depending upon which zone you're talk about, 1 million to 1.2 million. We hope to be able to exceed that, of course. And of course as you know, we try to tend to be conservative, because it's the way we put numbers out.

I appreciate that. That's great color.

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 seemed like you're referencing maybe a larger percentage of As than Bs in prior commentary. Not to suggest that sticking with Bs is high grading, but can you maybe walk through whether that's optimization for infrastructure that's causing more Bs than As, or if I'm misinterpreting something?

Dave, this is Frank. I think what we were referring to before was primarily the northern program. And when you add the Bs 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.

Great. I appreciate that clarification.

And one last one, 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 would be coming down in 2017 and 2018.

I suspect 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?

Definitely was just speaking to the stack drilling charges coming down in 2017 and 2018. The firm commitments and transportation, they'll grow some in 2017 and 2018 just with the reduced activity in Eagle Ford for the most part.

Okay. I appreciate that clarification and great work at the drillbit.

Thanks, Dave.

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

Good morning, guys.

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

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

Perfect. Then just my one followup, 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 million in this one?

Hi John, this is Frank again.

I'd 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.

Perfect. That's what I needed. Thanks.

We'll move next to Charles Meade at Johnson Rice.

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

I think that's right. If you look at 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. It really has to do more with well performance.

Got it. 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?

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 can really step out there and say that's enough data to say definitively that the third quarter was any different from the fourth that significantly. So I don't think you can 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 is suggesting based on what we just put on production in the fourth quarter, something that's more approaching 1 million BOE. So I think you see it clearly there. Wolfcamp A, I'd simply say there is just not enough time and well control.

No, thanks for that, Tim.

Then shifting over to your reserve bookings, specifically the PUDs, it's understandable you're down to 11% PUDs with not just the strip but the five-year rule on PUDs. Could you characterize what the PUDs you still have on your books here at year end, what they are, where they are, and in how that is different from where you have wound up in years passed?

Similar to years passed they're predominantly in the Permian Basin as you can imagine and with a number in the Eagle Ford. But predominately they're all Permian Basin PUDs. There's about 150 of them in total and I'd say 90% are in the Permian Basin.

Charles, this is Frank. They're all horizontal, obviously.

Right.

And that PUD percentage or 150 PUDs that's a lower absolute number than what you have had in the past, as well?

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've taken, as Tim mentioned, on other things 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 this area has technically proven, just a matter of what the SEC will allow us to book and what we want to book.

Got it. Thanks for that added detail.

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

Thanks. Good morning, everybody. Maybe if I could follow up.

You've certainly talked about it some throughout the call, but on a philosophical level, how do you think about balancing rate of return and growth and maybe gets to a little bit as to what the right level of capital is?

At this point can you walk through a little bit 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 in terms of -- as things cross the returns threshold? What will drive the absolute level of capital spend near-term and longer-term?

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. So we looked at -- we're gaining so much efficiencies and optimization that when we saw the numbers, how many companies can reduce 50% of your rigs and still show 10%-plus production growth.

We 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'll probably see us do more hedging in 2017-2018 to protect using three ways most likely. And we'll start putting rigs back to work and the returns will even be better than what Tim mentioned at 30%. So that's how we'll look at it going forward.

Will you ramp -- if you think about directionally, when you laid out a plan right now which implies some amount of incremental growth in 2017 at the strip. Will you generally ramp proportionately to how cash flow grows?

We still got the $1.6 billion, $1.7 billion in cash sitting out there. It's a question of how fast we deploy that. 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. We'll be focusing on adding rigs back to work fairly quickly. With 30 days notice we could add rigs back.

We'll have to decide on what growth rate is right in that 2017-2018 environment. I said we could get back to 15%. I told Brian Singer that if all got to 50, 50-plus to where it's on it's in the strip toward 60, we'll probably be hedging and probably moving toward that 15% production growth rate.

I appreciate that. Maybe if I could ask one more, production levels in the US have continued to surprise to the upside, yours included. I think some of that is clearly efficiency gains. But you do hear, it does seem as well as just some of the base production is holding in a little bit better than expected.

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 base of declines going forward?

Well, on Eagle Ford, at least we'll be able to establish a decline now since we have zero rigs running. So we've got a pretty good hand on that and the Permian is doing much better than expected and that's why with our balance sheet that's why we're able to grow. I read all your reports.

Most of you all are saying that US, so far people reporting plus future reports, US shale should drop 500,000, 600,000, 700,000 barrels a day. 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 recovery is going to be a lot slower. I get mostly from all of your reports based on other people's reporting.

Thanks.

First rain by balance sheet is a problem.

Thank you.

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

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?

You're talking about in this case the southern Wolfcamp area?

Correct.

During the carry 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've come to a joint agreement on this rig count.

Thank you. The reason I ask is because you highlighted that the best wells in the southern JV look very competitive, so I was of wondering how that --.

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 could drill very good economic wells there.

However, our partners in this situation where they have their own views and they have their own situation. We think we can just simply take those rigs and focus them to the north and be able to achieve at a high rate there.

Thanks. That's helpful.

Sticking with the southern JV, what's the timing of the 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.

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

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

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

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

We'll go next to Bob Morris at Citi.

Thank you.

Scott or Tim, two quarters ago when you first talked about adding two rigs per month through the second half of the year, you had said then 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 jut wouldn't turn the wells on. And I recognize that efficiencies have improved since then. You've added 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 to 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 three to four months or six months, whatever it is, until oil prices are a lot higher and build an inventory of DUCs like you're doing in the Eagle Ford or like a lot of your peers are doing here?

There's still 475 rigs, 450 drilling oil wells in the US. It's a shame we can't all get together. It's collusion, the Federal Government calls it, of shutting everything all in at once. We'd have to preserve our people. We've got over 20,000 drilling locations.

Keeping a few locations going on and based on the strip, if we all knew what the strip was over the next five 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 five years. If I knew they were going to be $25, $30 the next five years we wouldn't be drilling any rigs today. But I don't, so.

So, Bob, I'd 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 we push forward our knowledge regarding optimization of completions. So just drilling the wells doesn't cut that.

We have to get them on production and see how they produce. Get the learnings in place so that when we actually reach the upturn that we're ready to accelerate at a high level of performance, because we've built that knowledge base about how to optimize completions in the different areas for the different zones.

So DUC'ing wells just doesn't cut it 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.

Thank you.

We'll go next to Wolfe Research and Paul Sankey.

Good morning, everybody. Thanks for all the information.

Wondering on your hedging strategy, you mentioned that you're 85% covered for this year and 20% for next year. If we see the strip as what happens over the next year would we assume that you'd basically be in 2017 in a year's time in a similar hedge position, which is to say unhedged more or less, 20% hedged? Or would you start adding anyway?

Yes, 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. 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'll probably be fairly aggressive in hedging 2017.

So if the strip moves down from here, we're not going to be hedging anymore in 2017. But I think there's a good chance with news reports of US shale falling or rumors by Russia, or there's one today about a freeze on OPEC production that you've got to use events like that to put hedges in the marketplace.

Sure, 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.

Exactly. There will be -- I promise you there will be some chances that it spikes, the 2017 strip, over the next 10 months. And we'll probably be putting on some hedges.

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

I'd say on the operating cash flow 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 deck at that time. Obviously the commodity deck has moved since then and so we'll continue to watch it and see where we end up. But at $36 and 235,000, we think we'll be at the $1.3 billion level.

Just wanted to clarify, if you like a clean number, but I appreciate that. Thank you all.

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

Just curious, as you look at the 2016 program now versus what you provided a little over a month ago, seems like Permian is outperforming even over that timeframe, given the reduction in the Eagle Ford in particular. I'm just curious, number one, what was the prior expectation around the Eagle Ford as it results to production growth, or declines on the prior rig count? Did you change at all your assumptions around the Permian risking or productivity or anything of the like?

Yes, Michael, first of all, on Eagle Ford, we had stated that in the range of four to six rig count that we'd basically be able to keep production essentially flat. At the time during the call remember we talked about reducing it to four and with the potential to reduce it lower. Obviously in today's world Eagle Ford production will be declining.

It's simply a product of the fact that in our areas particularly, there's quite a lot of NGLs and natural gas in the flow stream, as well as the fact that condensate in our area fetches a price which is generally going to be $10 off a WTI. So in today's world, let's just say $17 per barrel.

So the economics we're getting trounced by the commodities on all three fronts and that led to the decision. By the same token, you look at Permian, however, the Permian assets pretty clearly are continuing to outperform.

I'd 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. It's a nice trade to be able to take monies out of the Eagle Ford where the economics are not very good today and put them into an area that's outperforming.

Certainly. Makes plenty of sense. That's going to offset a little bit. The completion optimization program in the Permian, we've seen a huge, obviously 50 percentage or so, 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?

I think first of all the optimization campaign in Eagle Ford took a couple years for us to pull off. But Eagle Ford is much smaller aerial extent and quite a smaller amount of shale in the sense of the 300 foot or so you have at Eagle Ford. I think 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 in to a situation where we might even have 15-foot cluster spacing. That would be unheard of in the past. We'll see how that does. We'll see how we do in terms of increasing our proppent 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'd say we're still pretty early days. We're still improving. We're still learning with every well. And I'd anticipate that going through the 2016 campaign. And realizing that's one of the reasons we need to keep some rigs running because we need to get to the end of the plan so that when we're ready to add rigs we're doing it optimally.

That's certainly encouraging. Makes sense. Last one on my end, around the commentary about 10% growth in 2017, what rig count assumptions are baked into that?

It's about the same. No change.

Very good. Appreciate it.

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

I appreciate you squeezing me in here. My question really related to the scenarios for 2017. 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? How would you think about cash burn next year in a low oil price environment?

We haven't made those runs, but obviously we've preserved most of our cash position of the $1.7 billion that I talked about going in to 2017. Cash flow probably $700 million, $800 million at $30 oil.

I'm just guessing off the top of my head. Rich is looking at me. You probably get down and just spend $700 million, $800 million, if that, and then preserve your $1.7 billion.

Good. Appreciate the color. I know we're all playing what if here with the commodity prices, but thanks for the time.

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

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

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