先鋒自然資源 (PXD) 2015 Q2 法說會逐字稿

Welcome to the Pioneer Natural Resources second-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. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website select Investors and then select Earnings and Webcasts. This call is being recorded, and a replay of the call will be archived on the Internet site through August 30.

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 would like to turn the call over to Pioneer's Senior Vice President of Investor Relations Frank Hopkins. Please go ahead, sir.

Thank you, Lisa. 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 will provide the financial and operating highlights for the second quarter of 2015 and then he'll discuss our latest outlook for the remainder of the year. After Scott concludes his remarks, Tim will review our second-quarter horizontal drilling results in the Spraberry Wolfcamp and the Eagle Ford shale.

He'll also discuss the significant progress we're making to reduce costs and become more efficient in response to the oil market downturn. He also provide details regarding the latest plans for our Spraberry Wolfcamp infrastructure projects and the economic drivers behind these projects.

Rich will then cover the second-quarter financials in more detail and provide earnings guidance for the third quarter. After that, we'll open up the call as usual for your questions.

So with that, Scott, I'll turn the call over to you.

Thanks, Frank. Good morning. On slide number three, starting off the second quarter adjusted income of $15 million or $0.10 per diluted share, we had already preannounced production in the second quarter of 197,000 barrels of oil equivalent per day, 51% of oil, obviously driven by the strong Spraberry Wolfcamp production growth through the horizontal drilling, and then obviously we had announced lower-than-expected production in the Eagle Ford and West Panhandle field.

We are maintaining our production growth forecast of 10% plus for 2015. Obviously, we're increasing the Spraberry Wolfcamp full-year growth rate of up to 22% to 24%.

We had already announced closing and the sale of the Eagle Ford midstream business for $2.15 billion. Already received $530 million at closing. The additional $500 million will come in in July of 2016.

In addition, you're already seeing benefit from fee reductions under existing downstream processing and transportation contracts roughly to Pioneer $100 million NPV.

We're realizing significant service cost reductions and efficiency gains. We're showing 20% to 25% already decrease in drilling and completion costs compared to 2014. We expect capital costs to decline by greater than 30% going into 2016.

We're seeing a 20% reduction in horizontal tank battery construction costs, already expect that number to be greater than 25%. 17% reduction already in LOE in the second quarter versus all of 2014.

A couple of more comments to give you an idea of efficiency gains. I was out in the field just last week in the Permian Basin. We're already seeing records being set in our Wolfcamp B wells. Our last 10 wells have averaged to drill to TD of 20 days. We actually set a record with a Sale Ranch royal in 13 days. We're seeing records occur weekly as we're moving forward, especially focusing on one zone, primarily the Wolfcamp B.

In addition, if oil prices continue to stay sub $50, I expect at the cost I just mentioned service costs will be under more pressure to come down even further. So I think we'll get more gains in a sub $50, $50 or sub environment.

Slide number 4, 28 horizontal wells placed on production during the second quarter of 2015 in the northern Spraberry Wolfcamp. Early production results in the Wolfcamp B from 16 wells, they are tracking above 1 million BOE equivalent with an average 24-hour rate of 1900 barrels of oil equivalent per day with 79% oil content.

Results from the five wells in the Lower Spraberry Shale are averaging 1 million barrels of oil equivalent with a 24-hour peak rate of 1100 barrels of oil equivalent with 81% oil content. So both continued to average very high oil content.

Tim will talk more about our seven wells benefiting from our completion optimization and what we are doing there, but we're seeing tremendous results from our six Wolfcamp B wells and one Lower Spraberry Shale well.

The average production from all the Wolfcamp B and Wolfcamp A wells, since 2013 in the north, are tracking EURs of 1 million barrels of oil equivalent.

I'm changing the topic in regard to exporting condensate. We're continuing to export the same amount, 20,000 barrels a day, in the second quarter. Obviously, we significantly improved pricing as compared to domestic condensate sales.

We did a spot cargo of 6000 barrels a day this past June.

We are continuing our efforts on lifting the ban. I think we had last week was very important in that regard. Both we had comments from the Speaker of the House, very positive supporting listing the export ban. The Senate actually had a vote in the Energy Committee in regard to lifting the ban. I expect both the House and the Senate -- full Senate, full House -- to vote on lifting the ban sometime in late September or early October.

On my recent visits, something that is helping us significantly and we're getting out the message obviously, if we are allowing Iran to export oil, why not our US producers?

In addition, it was disclosed last week that we are importing Russian oil up into the Northeast refineries. So why let the Russians export oil to the US? Why allow Iran to export oil and not let US producers? So I am changing -- I'm getting more optimistic above 50% now.

Going to slide number 5, outlook, strong commodity positions continue to protect cash flow. We probably have the best -- I mean, if we look at 2015 and 2016 combined in the industry, we have coverage for 90% of our oil for 2015 at $71, 75% of our oil for 2016 in three ways, and pretty much when you look in the exhibits and back between $47 and $67, we get $67 with upside to $77. So obviously, if crude stays where it it is, even for next year, we are going to get $67 for most of the year for 75% of our crude.

We do have good coverage for gas: again 85% in 2015 and 65% in 2016.

We've got a strong balance sheet in the second quarter. Debt to book 23%. Obviously, with the close of Eagle Ford in early July, it further enhance that. Cash on hand the end of July is about $700 million.

We plan to add, as we have stated, two horizontal rigs per month in the north during the second half of 2016 and also plan to add eight rigs in the first quarter of 2016. Six rigs in the north and two rigs in the Eagle Ford.

The rig ramp is expected to bring horizontal activity back to the level it was at prior to the oil price collapse in late 2014. We've already added four rigs. The IRRs, which are most important, what are the returns in this type of price environment? The Spraberry Wolfcamp and the Eagle Ford range from 45% to 60% at current strip prices, including all costs tank, battery, solar, disposal of capital costs.

For example, also in a $50 flat environment, we are still getting 30% to 35% returns.

We have minimal impact on 2015 production obviously due to the time required to drill and complete these multi-well pads. And we continue over to the 2016 to 2018 period, provide a CAGR production growth rate of 15% plus with an oil growth rate of 20% plus.

In summary, with a strong balance sheet, world-class assets with great returns, a superior derivative position through 2016, it gives us tremendous flexibility to adjust the rig ramp based on the Company's commodity price outlook and continuing efficiency improvements.

One thing I can obviously say, we always get asked what commodity price when you slow down? You know, if oil prices go to 40 and stay at 40, for the next 18 months, obviously we will most likely slow down. But as long as in our hedge positions and the strip occurs, there is no reason at this point in time to slow down.

Slide number 6. In regard to our drilling budget of $2.2 billion that we had announced with the rig adds in the second half of the year, it's broken out about $1.95 billion in drilling; $250 million of other capital; water, infrastructure, vertical integration and facilities. Operating cash flow of $1.5 billion as I mentioned already $700 million at the end of July.

And also if you look at this chart, for instance if we get to $40 oil and stay at $40 for the rest of this year, we only lose roughly between the star and $40 oil and $2.90 gas, we only lose about $50 million to $60 million decrease in our cash flow. It's just a tremendous -- so why make the decision now based on current prices?

I'm optimistic by the second half of 2016 that prices will be back to the mid-$50s or even in the low $60s with the second half of 2016.

Slide number 7 and our long-term growth rate. We are still at 15% plus from 2016 to 2018, 20% on the oil growth. Our guidance for third-quarter, a significant increase up to 205,000 to 210,000 barrels of oil equivalent per day, and we'll be moving from 51% oil to 60% oil over the next three years.

I'll now turn it over to Tim to get more detail on our operations.

Thanks, Scott, and I'm going to start with slide 8. As Scott has already mentioned, the second quarter did feature a very strong drilling campaign in the Northern Spraberry Wolfcamp area, particularly in the graphs here on slide 8 show that very clearly.

You can see as he mentioned, that the Wolfcamp B wells, 16 in total, are averaging actually well over 1 million BOE per day so far. Realizing your vertical scale there, there's a log scale. So these wells have done exceptionally well, and as he covered as well, as you look to the right graph, your Lower Spraberry Shale wells are exhibiting probably about 1 million BOE type curve. So they've done exceptionally well.

We did put seven other wells on production in other zones, and the statistics are shown there on slide 8. They track essentially where we've been in terms of these zones as well.

So when you look at that, it gives us a lot of confidence that the drilling we've done in the past will be representative of what we expect minimum in the future.

We also did put on production seven of our 25 well campaign on completion optimization during the quarter, and those results look very favorable. Of course, they involve changing the stage lengths and the clusters per stage, proppant concentration, fluid pump and so on. But those seven wells look very encouraging, and of course, it is going to take more time for the full evaluation. And I expect that over the next couple of quarters we'll be coming out with more data about the actual well results, but suffice it to say, they look very good so far.

Turning to slide 9. This shows the program to date. Results for all of the Northern Spraberry Wolfcamp horizontal wells in the A and B zones, that's now a total of 107 wells. And so we were showing you all the data for all the wells on average, and you can see pretty clearly in the top graph that our numbers are coming in at or above the million barrel type curve for all the As and the Bs similarly running about 1 million barrels BOE.

So it does give us a lot of confidence that we have this consistency across these zones and really across the basin. If you look at the graph on the right, the map, it shows that we have been drilling the B wells particularly over a pretty wide swath of acreage and the As, as well. So it gives us a lot of confidence as we look forward that as we head more towards development mode over the next several years, we'll have at a minimum these kind of results to the extent our optimization campaign is successful. I think results could easily outpace what we're showing in terms of the historical data.

Now turning to slide 10. As we mentioned, we are in the process of ramping up the drilling campaign. Having started it last month, we're now operating 10 rigs in the North. That campaign is showing strong EURs and returns, mostly because of the fact that we've gotten substantial cost reductions that Scott already mentioned, but also we're doing a great job as a company in terms of bringing out new efficiencies. We are reducing our time on these wells. Our spud to pop times, for instance, has been reduced to about 25 days. That has to do with changing the casing design for these wells and in particular trailing only the Wolfcamp B principally as the main zone. Our crews get better and better as they drill just one zone.

We've also seen reductions in the time in terms of the measuring of frac to pop, putting the wells on production building down as well. So we're just getting more efficient, we're getting better, and for that matter, the completions are getting better as well. We're reducing the average time it takes to pump the stages. We're basically pumping more stages per day. So that's all going exceptionally well.

We continue to test new technologies whether it's dissolvable plugs or diversion technologies and, as I mentioned, a large campaign for completion optimization.

The well costs now are coming in about $8 million to $8.5 million. That's down, of course, and represent the 20% or 25% cost reduction or so that we've already achieved, and I think we can actually move those numbers down as we get into 2016 to over 30%. And this is to do with burning off our tubulars inventory, having rigs come off contract and actually increasing savings along other parameters as well.

Returns to the north look exceptionally strong, 50% to 60% based on those million BOE type curves.

As you look at the map on the right, the one thing that jumps out here is the planned number of wells to POP this year. It continues to be 100 wells, but as you look to the number of wells to be spud, it's now increased to about 100 wells. That's associated with the fact we're increasing the rig count, but at the same time, most of those rigs will have no effect in terms of 2015 production. It will mostly affect 2016.

Turning to slide 11, in the southern JV area, the story is very much the same. We are now operating the four rigs in the area getting a similar types of results when it comes to improvements in the drilling campaign and strong EURs, as well as reductions in time on wells.

The wells are a little cheaper in the south, of course, because we're a little shallower. They average about $7.5 million now having -- have the effect of the cost reductions. I think we can move those down to $6.5 million to $7.0 million as we get into the next year, again reflecting the 30% reductions or so.

And these wells have IRRs of about 45% and measure the same way as I talked with the northern wells. And as you look at the plan regarding POPPING wells, we're still POPPING about 75 to 80 wells. We are well on the way to get that done, considering we have 58 that we've done through the second quarter. And then we plan to spud only about 45 wells this year. That's just as a result of a relatively low rig count in the south at four rigs, which has limits in every well we can spud.

Going to slide 12, the strong drilling campaign in the quarter led to a pretty significant increase in production, about 7,000 barrels a day. As you look at the third- and fourth-quarter forecasts, you see that they are plus or minus flattish compared to two-thirds of our run rate. It'll be up in the third quarter but flat in the fourth.

That has to do with the fact that we reduced our rig count late last year into the first quarter this year, and as we now pick that up, you'll see an increase in the trajectory. So I would focus on the 2016 trajectory as being more emblematic of what we can do with a substantial number of rigs working.

If you look back to the last three quarters of 2014, that is the type of growth you should be able to see in terms of a trajectory, and we're back to a full campaign of drilling. So overall it was a strong quarter for our Permian Basin operations.

Now I am going to turn to slide 13. Since the first-quarter call, we've been receiving a lot of interest from our shareholders and the analyst community about how they should be thinking about our short- and long-term infrastructure needs in the Permian considering the size of this, the prospect, the size of the field is pretty large numbers, but particularly regarding tank batteries and saltwater disposal systems and how they fit into the equation.

As we show on the map on the top right of 13, the configuration that we've developed now over the last couple of years in our acreage provides for significant opportunities for optimizing this infrastructure in a centralized fashion.

So what is shown there on the top right are four sections, each, of course, 640 acres or a total of 2,560 acres. They're lined up in a contiguous fashion north and south, which is the optimal direction for drilling. And the base development assumption for these four sections, we will be drilling 60 wells on three well pads, covering four different zones in that acreage. And if you look at the needs for tank battery and saltwater facilities, they are estimated to be about $25 million in total over the whole development of this acreage, including the D&C costs.

So the real point to be noted here is about 75% set of our acreage is amenable to this type of development. So that means what you'll be seeing us do is over 200 of these developments in the fullness of time.

So that's why we really need to get this right in the upfront is to make sure that we have this down, and we believe we're doing it efficiently. With this massive area that we are working on, it will take, needless to say, quite a bit of time to build this out. I think we will be spending about $250 million to $350 million each of the next three years for buildout of these similar systems.

As you see in the bottom graph, this does involve some upfront spending where the first six wells are a total of about $10 million or about $1.6 million for the infrastructure. While the last 54 wells average only about $300,000. So the average for all of the 60 wells comes in at about $400,000.

The key point is that, although we do have some front-end loaded spending, it also reduces the infrastructure capital costs per well over time.

So turning to slide 14, this is just really a real-life example of what I just mentioned. And it's taking place in the Giddings area in the northern acreage of the Southern Wolfcamp JV. The first six wells are drilled, and facilities were built last year, and since then, 14 more wells have been added at about $300,000 per well. And we'll probably put about 12 more wells on production for the rest of the year.

So by the end of the year, we will have connected about 32 wells, more than half of the total of 60, and that will be in less than two years.

And so the bottom graph shows the actual trajectory of average costs coming down as predicted as the last 28 wells are tied in in the next couple of years at about $300,000 per POP.

So given that there's a burden associated with the upfront capital, why develop the infrastructure this way would be the question, and I'll cover that on slide 15.

So the real question is, what would be our alternative? The most simplistic way to think about that would be to set smaller tank batteries and smaller saltwater disposal systems to handle each well as it is drilled rather than a centralized approach. And so we've done some calculations as to what that would look like compared to how we are doing it.

And so the question is, why is our centralized infrastructure method the preferred way to go? Well, you can see in the two graphs here on slide 15, and that is to say what happens when you do it our way is that the total infrastructure costs for the field are lower. The actual upfront capital costs are lower, and we get the benefits of three well pad being more efficient, especially on a cost basis.

In addition, because the three well pad drilling production and cash flow is accelerated and doing it our way also avoids the losses of possible future drilling locations due to surface limitations, you eat up a lot more surface when you place one tank per well than the way we do it, and the result can be losing locations.

And finally, it reduces the number of offset wells that we have to shut in during completions of wells nearby.

The most important factor, though, is it increases our net present value of the entire project by about $40 million for each of those 2,560 acres. Or if you calculate it out on a per acre basis, it is about $15,000 an acre. So about $40 million, and that's if you don't lose locations. If you were to lose locations, you could gain $80 million of value.

So, if you calculate this across our entire acreage position, it's a tremendous amount of value. We think the logic is compelling, and this is the basis upon which we will continue to develop the massive opportunity we have.

I'd ask that if you need more information, feel free to contact Frank and the IR team, and I know they'd be happy to walk you through the assumptions of the analysis.

Let me go then to slide 16. This is a summary of where we are regarding the Permian water system. As you all know, we're planning for a long-term solution to our water needs, the objective of which is to reduce the cost of water per well and also to make sure we have adequate water in the sense of non-potable water. We want to get to the point where we're not using any freshwater if we can do so. The savings of the cost savings per well is significant, probably $500,000 per well.

The project as mentioned will come on in phases over several years. The first of which is the initial phase we're doing this year, which is doing the engineering and right-of-way, connecting the Santa Rosa brackish water source that we are already producing. It's about a $70 million project, moving water up from the south into the SWAT area.

The second phase we are commencing here in the second half of the year and anticipate completing it next year, and that's bringing in the Odessa water. That's the effluent water from the city of Odessa; about 100,000 barrels a day. It will be ready later this year and into next year and then subsequent to which we need the subsystems and frac ponds built out to make sure we can get the water to our locations.

So the total cost for that project is about $100 million. $60 million of which hits this year and about $40 million next year. But it will, as I mentioned, reduce our purchase and handling costs of water of about $500,000 per well. Do the math on that, and that's a payout that is less than two years.

Turning now to slide 17, this slide gives us an update regarding the status of some for other infrastructure projects. In terms of gas processing, our interest in the Targa system is very important because it gives us a seat at the table to make sure that future plants are built in advance of our throughput needs in the area. And notwithstanding that, it allows us to be confident that we can get our wells hooked up immediately and ready for production. It's improved our contract terms significantly, and also, of course, we benefit to the extent the third-party volumes are put through plant as well.

This year's budget has about $70 million net to Pioneer for the initial construction phase of the Buffalo plant in Martin County. That's about a 200 million cubic foot per day plant and for gathering system upgrades.

So what we've seen in the Permian Basin is by virtue of spending time on things like field compression, line looping and so on, reducing pressures in the field, we've actually substantially increased gas production.

If you take a look at our data, the fourth-quarter Permian Basin gas production is about 13% of total production. In the first quarter, it's 15%. That's not because wells are getting more gassy, it's because we're getting better at capturing the gas that's being produced, and that's the result of reduced line pressures.

So that's been a big positive for us. The 2016 spending should be similar to this year, and it will be in essence put in place to continue what I mentioned but also to finish the Buffalo plant. That plan should be done later next year.

In the sand mine, of course, we have done work this year regarding beginning the expansion. We've done some of the groundwork for that. We spent about $25 million this year with the idea of more than doubling the sand mine capacity. Today we really do not need more sand, but we can see the day we will.

So we put off the completion of the expansion, it would be about a $75 million expansion and probably don't anticipate it happening any time before, let's say, 2018 or so.

Turning to slide 19 then and the Eagle Ford results, most of our drilling has been in Karnes and DeWitt County, some of our very best areas. And, as a result, we are generating very high returns about 60% IRRs and 1.3 million BOE EURs in the area.

Importantly, we continue our downspacing and staggering program in both the Upper and Lower targets, and those wells continue to do well. You can see the bottom hand graph on the right showing downspacing results. You know the difference between a 300-foot spacing versus 500, and they are essentially spot on. So that gives us a lot of confidence that this downspacing is being very effective.

And we will be anticipating and expecting to increase the rig count to six -- from six to eight early next year. Well costs have come down significantly about $6.5 million now. Remember we started -- first started up in the Eagle Ford, they were $8 million or $8.5 million. So we've made huge strides there. But we've had about a 20% cost reduction already and expect over 25% -- we could get the costs down to roughly about $6 million, we think, by early next year. And here we are experimenting with it, although we are in the early days of using new completion technologies that I already mentioned regarding diversion and dissolvable plugs.

Turning then to slide 19, the Eagle Ford results for the quarter. Production was down slightly. It had to do with a couple of factors. One was that we put on production nine fewer wells than we anticipated, mostly due to weather, and then as has been documented, we had some wells we put on production late 2014 that were disrupted that we had too high it turns out of the forecast for their 2015 production from this area, so we're reevaluating that.

So in essence, they came in lower on production than when we had anticipated in the early planning. So we're reevaluating the drilling in that area until we can understand why those wells have come in at lower rates.

And so as a result of all that, we are moving our production growth forecast down to just a slight increase of 1% to 2% for the year. Ethane rejection continues. This is across the board. Ethane and propane prices are in the tank, and as a result, where we can, we are rejecting ethane throughout our operations.

So I'm going to stop there and pass it over to Rich for a review of the second-quarter financials and his guidance for the third quarter.

Thanks, Tim, and good morning. I'm going to start on slide 20 where we show we had a net loss attributable to common stockholders of $218 million or $1.46 per diluted share. That did include non-cash mark-to-market derivative losses of $222 million or $1.48 per diluted share.

And then we also note on this slide here, unusual items that aggregate $11 million or $0.08. So adjusting for mark-to-market unusual items, we were at $15 million or $0.10 of earnings. The unusual item, the biggest item that was our previously announced restructuring that we did in the Raton asset team and the closure of the Denver office.

Looking at the bottom of the slide where we show Q2 guidance versus results, we've talked about production, and we'll talk a little bit more about production costs in a slide or two.

The one item to note is DD&A came in above the high end of the range that we had put out, really resulting from lower commodity prices which had the effect of shortening the economic life of our producing wells. This resulted in a negative price revision to proved reserves, which caused our depletion expense to be higher than we anticipated.

Turning to slide 21, looking at price realizations, you'll see on the bars there that oil prices during the quarter were up 20% to $51.64. NGL prices were down 6% to $14.03, and gas prices were also down 12% to $2.37.

When you look at the tables underneath those bar charts and particularly at the derivative ones, you'll see that our derivative position, as Scott mentioned, has paid big dividends for the Company over the last number of quarters. For the second quarter, we added $150 million of cash for the quarter as a result of our derivative position.

Turning to slide 22 on production costs, you can see that for the quarter production costs came in at $11.19, down 11% from the first quarter, primarily driven by decreases in our base LOE, good work from the asset teams and their cost reduction initiatives, mainly on fuel, electricity, oilfield supplies and services, were the major items.

So in total, we were down, as Scott mentioned, 17% from our average production LOE costs per BOE in 2014. And then obviously a production in ad valorem taxes with the decline in commodity prices are also down quarter on quarter.

Turning to slide 23, liquidity position. We continue to have an excellent balance sheet. You can see we had net debt at the end of the quarter of $2.5 billion. $219 million of cash on the balance sheet that was supplemented by the closing of the Midstream sale in early July that added $530 million of cash. So at the end of July, we are now sitting at a little over $700 million of cash on the balance sheet and expect to get another $500 million in July of next year. Plenty of liquidity with an unsecured credit facility availability of $1.5 billion. So all-in-all great financial position as we move into the second half of the year.

Switching gears and moving to slide 24 and talking about third-quarter guidance. Production expected to be 205,000 to 210,000 BOEs per day for the third quarter. Production cost guidance here is up slightly from where we ended -- came into the second quarter, mainly because of the sale of the EFS midstream that we talked about in past quarters that will cause our production cost to increase about $0.75 to $1.00 per BOE. So that's reflected in the guidance.

Other thing in guidance that's of note is DD&A, you'll see that is up also reflecting that we were another quarter of lower commodity prices, which we expect to have some more negative price revisions to reserves.

Other expense of $45 million to $55 million includes $20 million to $25 million of stacked rig charges. That is down from the second quarter of $28 million of stacked rig charges reflecting the rigs reporting back to work.

And then the other item of note is current income taxes of $45 million to $55 million. This reflects the alternate minimum tax that we will have to pay associated with the EFS midstream sale. We were able to shelter regular tax, but we will have some AMT to pay. So that's reflected in that $45 million to $55 million estimate.

So with that, we'll stop there and open up the call for questions.

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch.

Guys, thanks for all the color on the infrastructure costs. But I wonder if I could try and -- I know you tried to kind of dumb it down a little bit. But I wonder if I could try and ask you to dumb it down even further? If you look at the proportion of total capital, which is on infrastructure in the current year, I want to say it is about 30% or something like that. How would you expect the proportion of infrastructure spending to trend over your planning period? I don't know if that's an easy question to answer.

Yes, I think -- well, first of all, our tank battery and saltwater disposal expenditures are going to continue probably for the next three years at the rates I mentioned. So those are just required to start building out these four section developments as we continue the campaign.

As you look out, for example, the gas processing facilities, we'll probably be spending a similar amount next year as this year, but that's to complete the Buffalo plan. We don't have any further gas plants on the horizon after that. So I think it's safe to say, it'll be sometime before that [70] million or so reoccurs after 2016.

And then from the water plant standpoint, I think the first tranche being the Odessa project is something we're going to do, and we are going to complete that next year. It's only a small amount next year relatively speaking. After that, all bets are off. We're going to evaluate what's the proper next step based on how the conditions are in the market, what water needs we have, where we need the water, what the well economics look like in terms of next step some water supply. So we can do that ratably, we can just do it piece meal, and we can get -- hold off a lot more capital on water if that's what we choose to do.

Got it. I appreciate that, Tim. My follow-up is -- it's related to the rig count relative to what you've previously been targeting, which was I guess kind of gets you back to where you were, as you said, in your previous release in terms of number of rigs.

But I'm going to use an [Oxy] example, if I may. They originally were targeting 50 rigs by 2018. And now what they are saying is, you know what, we can do the same amount of work with 25. We'll never get 50. So kind of the same question to you with 36 rigs by the end of the first quarter, what's the pace of POPS if you like? And I know you have only just given us up those numbers, so it's a bit unfair to ask what happens next. But obviously there is a lot of cash flow that comes with the growth trajectory. So what is the kind of medium-term plan beyond the first quarter? So efficiency what do you get with the 36 rigs, and what's the plan beyond the first quarter through your planning period. And I'll leave it there, thanks.

Yes, Doug, I sort of alluded it at in the opening slide and then finishing up a couple of slides later. The thing we're seeing is that we are budgeting somewhere between 28 and 30 days to spud to TD of these wells, Wolfcamp B wells. And so we've had our last 10 wells at 20; we had one at 13. If we continue to see that number come down, obviously, we can drill the same number of wells, get the same production growth with less rigs.

So obviously that would happen with us as well. We need to see the efficiencies continue before we make that decision. Obviously, we'll be flexible with our best balance sheet and our best superior derivatives. We have a lot more flexibility. So you may see at some point in time us add less rigs. It won't be because of the commodity price. It will be because we are drilling these wells in 20 or 22 days on average. So I hope that answers your question.

So should we really think about you at some point living within cash flow, Scott, or how are you targeting the spending, I guess, is really what I'm trying to get at?

Yes, with -- I've looked at almost all of our peers. Almost all of our peers are 2 times the 4 times debt to cash flow. We are essentially a little over 1. So obviously, we have more firepower than almost all of our peers. We have a better hedge book. We have more cash on the balance sheet.

So we're going to use that cash. We will use our balance sheet somewhat to a point going into 2016. So we have lots flexibility.

Got it. I'll leave it there, guys. Thanks so much.

Charles Meade, Johnson Rice.

Scott, if I could just pick up a bit on Doug's question there, and I know you guys have been asking these questions a lot of ways. But you obviously have the returns at the well level to justify the investment, and you're in the great position with all these recent asset sales that you've got a relatively under-levered balance sheet with cash. But what is the year that sounds like the objective function for you guys is you're looking for growth, and I'm wondering if that's -- if that is the objection function, what are the constraints? In the near-term, is there a dollar amount in excess of cash flow that you're thinking about that you're comfortable spending? And then as that moves over the time, at some point what becomes relevant constraint? Is it debt-to-EBITDA, or how are you thinking about that over the three-year timeframe?

Yes, I mean, it's important -- we think it's important to bring our NAV forward. It's important to show growth as long as we're having very good returns. We have stated debt to cash flow publicly of [1.5]. Maybe we go to [1.6], [1.7] at some point in time. At the same time, we have a lot of flexibility. We have obviously other assets to divest of to look at. And so right now, we see under this current environment, in this strip environment, no need to do anything else, except execute.

And we think will get better production growth than we are actually showing with the results that we are continuing to see in the Wolfcamp B and the Lower Spraberry Shale. So it's really getting to growth. We're targeting the 15%, but you've got to have great returns. At the end of the day, we've still got to have a good balance sheet.

Got it. That's helpful, Scott. And then if I could move on to the development pattern that you guys laid out here with the four stack sections and the 30 wells across a section, I'm curious if you could elaborate a bit on how many different zones you see contributing to this 30 wells across a section? And I guess as kind of a backward way of asking of what your assumed spacing in a section, you know the lateral offset to the section, are there? And if there's possible upside to that -- I'm sorry, not 60 but 30 wells across a section.

Yes, Charles, this is Tim. It's actually 60 wells covering the entire four sections drilling both northward and southward, so we're clear on that. And the way I couch that was four different zones. That's just a model we would look at today.

I mean if you look at our well results so far, it's pretty clear that we've proven up the Wolfcamp B, the Wolfcamp A, Lower Spraberry Shale, a lot of cases in the Middle Spraberry Shale. We have a lot of options, of course, for Wolfcamp D, depending on where we are and what is the optimal zone to be drilling in the area we are. But this is just one model.

If you look at the spacing assumption here, it's about 600 to 660 feet spacing is what's assumed in there, if you just do the math. That wouldn't necessarily be definitive. It's possible we could come in slightly inside of there.

But the other thing to note is we have room in here to come back to other zones as well. So we're not limited to only four zones. This is just the pattern we're drilling in what we would say would be the optimal four zones in an area.

So we could come back and drill other zones on the same acreage position and do that perhaps a little bit later. You mean you have to realize, Charles, each of these for sections takes, if you just do the math, 60 wells and $8 million you're dealing with nearly $0.5 billion to develop 2,500 acres.

So we'll only get to the best zones first I guess is the way I would look at it, but we have space to go back to other zones.

That's helpful, Tim. And when you say space, if I understand you correctly, it's really you're talking about surface, space on the surface pattern to come back in and get those zones.

Right. Correct.

Right. Thank you.

Leo Mariani, RBC.

Just a question here on the 2015 overall production growth. You guys talked about 10% plus. Are you guys adjusting for the divestitures that you had in 2014 to get to the 10% plus, or is that just the straight calc on the 2014 production versus the 2015 production?

Yes, Leo, it does include those divestitures being taken out.

Okay. Now that's helpful. And I guess obviously, I know it's early days, but you guys did talk about encouraging results from seven of your new Permian wells that you used enhanced completion designs. Is it -- do you have enough data yet to say if those wells appear to be performing better than kind of the existing wells at this point in time?

Well, of course, we are not ready, Leo, to give you a whole lot of data on that until we have more definite data -- in fact, more data on more wells. But suffice it to say, where we would have been averaging about 1900 IP or 24-hour peak rates on the Wolfcamp B wells, we are easily seeing well over 2,000 on those wells that are affected by the completion optimization.

So we're not going to give you specific numbers, but see pretty significant bumps. And we just need a little more data, a bigger data set in order to sort of calculate averages. But I can tell you, it is well over 2,000 as an example compared to the average.

That's helpful. And I guess you guys also talked about some longer-term asset sales to keep the balance sheet strong. Would some of the midstream infrastructure you're building out over the next couple of years be a critical part of that? Any other kind of high level color you can provide there?

Leo, I'm just trying to address the long-term question if for some reason we will continue to do what we have the last three or four years to make sure we keep a great balance sheet. We do have three other assets that we could divest of over time. There are no plans at the current time to do anything.

Okay. That's helpful. And I guess you guys also talked about a 900 MBOE EUR in the Southern Wolfcamp, which is a nice bump. Just trying to figure out if that's the whole Southern Wolfcamp or just the Northern part of the Southern being the best part there?

Yes, we are drilling mostly in the north, and what we are reflecting on is the results in the North.

Okay. Thanks, guys.

[Michael Hall], [Heikkenin Energy Advisors].

Thanks. Good morning. Congrats on a good update. Just curious, as you push on the rig ramp plan, you know you've been focused on single interval here, more so with the Wolfcamp B. Does that focus change as this rig ramp escalates, and how do we think about kind of maintaining the efficiencies you've seen so far as you keep pressing on the gas bill?

Yes, I think over time, Michael, you'll see us do some As, sprinkle in some As in Lower Spraberry Shales. We are seeing great results from both also. But we obviously don't want to sacrifice our efficiencies, but hopefully the As and the Lower Spraberry Shales can be drilled the same amount of drilling spud time as we're seeing in the Wolfcamp Bs.

Okay. And then on the centralized facility versus single well case that was helpful case studies to lay out for us, just to make sure I'm clear, are you building out the facilities for all 60 wells initially, or is that -- are those in kind of modular pieces?

What we do, I kind of mentioned this, Michael, when I was going through those slides is that we build out, first of all, a tech battery that's a relatively large tank battery to handle the first six wells. In addition to which we then come back in on individual wells and put in separation and basically production lines, and that's substantially lower.

So after the first six wells are put in, we have relatively lower capital going in actually probably $300,000 per well just for separation and production facilities, as opposed to the $10 million upfront to get the first six wells on.

Got it. That makes sense. Okay. That's helpful. And then I guess it's been touched on a little bit in terms of potential sources of future capital, but in the context of the centralized facilities, you had mentioned that maybe 75% of the acreage was amenable to that sort of development. I am just trying to think, if the other 25% isn't at a structural economic disadvantage relative to the whole inventory and, therefore, might be -- you might be willing to think about monetizing small pieces of the acreage that don't fit in as well from a contiguous standpoint or some other characters.

Michael, we are -- first of all, we're trying to block in through small deals, transactions and get contiguous tracts through acquisitions. We've been averaging $20 million, $25 million, $30 million a year the last two or three years, and we will continue to do that at very low acreage costs.

Your bigger picture question, we've always been open, and that's another source of capital is looking at selling a portion of our fringe acreage. The transaction, there's been three transactions that I have seen over the last 90 days that people are continuing to pay $30,000 to $35,000 per acre in good tier one acreage. So if we can get those type of prices, that is another source of capital that we would be willing to look at, besides divesting of our three assets.

Great. That's helpful. It certainly seems to make sense. And then on the great LOE improvement, is that sort of 2Q level sustainable? Just kind of modeling tech question.

Yes, sustainable other than for the increase from the EFS midstream that we talked about that will lose the benefit of that cash flow. So it will be, like I said, a $0.75 to $1.00 bump.

And the other thing that's happened there with electricity, of course, is we are tending to go more towards gas lift, which is a pretty significant cost saver.

Okay. That's all I had. Thanks. I appreciate the time.

John Freeman, Raymond James.

You previously talked, Scott, about how you were looking at 28, 30 days spud to TD, and now you got these recent wells at more like 20 days, and obviously the one that was 13 days. If I look at kind of a little bit different angle, if I look more just kind of spud to POP times and look at your preliminary growth guidance that you have given for kind of 2016/2018 timeframe, does that assume that the spud to POP times in the Permian, for example, just stay in the kind of 140 to 160 day range, or do you in that kind of preliminary guidance assume additional efficiency gains?

No, no. It's still assuming the 140 to 160 timeframe. Just that the drilling is what we're seeing the quicker efficiency gains, and obviously you end up spending and drilling a lot more wells, spending more capital if you can drill these wells in 20 days versus 28 to 30 days. So that's why we're watching that piece a lot closer.

Okay. And then just the one follow-up for me when we look at kind of the current well costs and I guess right now just look in the Northern area at the $8 million to $8.5 million and the goal to get it down kind of $7.5 million to $8 million by early next year, it seems like a good bit of that you've bridged almost just by itself at least if the numbers have held for what you all previously said about $300,000 a well in savings just on the dissolvable plug. Is there another kind of big-ticket item like that, or it is more just from that point just efficiency gains?

Yes, I would tap the brakes on that being the dissolvable plug technology being that which we could calculate across all the acreage. We really testing that, John, in just a handful wells. I think it really has more to do with the fact that when we ran the big rig ramp-up last year, we built a pretty substantial tubulars inventories that we are just burning off. We certainly burn it off faster with the rig count increasing. But I don't anticipate really being in the market for a lot more tubulars until we get right at the end of the year and into next year. Those tubulars are going to come in 25% less than where they were. So that's kind of in the bag in terms of a cost reduction we can count on that's not incorporated in the numbers today.

The second thing that happens, especially as we get into 2016, is we have rigs coming out of stack off contract. And to the extent those were replaced with spot rigs, those were easily 20% savings in terms of spread rates. And we're not seeing that today, as you know, because we are, in fact, taking rigs right out of the stock at the old rate. And so accordingly, these things are kind of in the bag. I think we could say with a lot of confidence those are coming. We've just got to get the fullness of time behind us, and we'll see those cost reductions.

Great. Thanks, guys. Appreciate it.

Brian Singer, Goldman Sachs.

Looking at slides 8 and 9, can you talk in more detail about the 16 Wolfcamp B wells that you brought on in the quarter that got very substantially above 1 million BOE rates? I guess six of them looked like they were the results of the completion optimization program, but can you add some more color on the others whether there are regional sweet spots, where on the map page 9 they were, if they were concentrated or they were equally spread out?

I think you see kind of a statistical result that you expect. You see some particular wells in the same areas doing better than offset wells and vice versa. So I don't think there's anything particular.

I think what we can say is, and Scott really alluded to it, the Sale Ranch area up in Martin County has gotten really some simply outstanding results, many of those wells well over 2000 BOE per day.

Our Hutt area continues to produce well and with the wells producing on a 24-hour basis in the neighborhood of an average of, say, 1,600 or 1,700 barrels a day. So it is statistical, but there are certain areas like Sale Ranch which are really over performing.

Great. Thanks. Then back to the first question on what happens if you're drilling days fall and you're left with the decision of whether you want to complete more wells with the same rig counts and spend a little bit more money but then grow more versus drop rigs, same wells, same growth, how do you think about how to make that decision, and what metrics do you look to to say, you know, let's keep our rig count and grow more versus cut CapEx -- or I'm sorry maintain CapEx and drop rigs?

Yes, Brian, we are focused on the 15% production growth number at the end of the day to have a great balance sheet. So those are the two driving along with obviously getting great returns.

So those are the drivers. So if for some reason we have a choice to go to 20% to 25% production growth and spend a lot more money, take more balance sheet risk, we'll probably not do that.

I would kind of add to that, Scott, by saying, to add rigs, what we are doing is taking them out of stack, Brian. We're not adding new contracts and rigs. And so, therefore, if the rigs we have running are way more efficient, you just take less rigs out of stack. That's way I think about it.

Got it. And is it fair to say we take the amount of production you have hedged divided by the 75% that you're basically guiding towards the plus or emphasis on the plus in your guidance for next year?

We haven't given out 2016 guidance, but I think over the three-year timeframe, it could be a plus, obviously, with the efficiencies and everything else. But at the same time, we are not going to push the 15% number, especially with these type of commodity prices and these type risks until things reset, supply/demand resets worldwide.

Great. Thank you.

Mike Kelly, Global Hunter Securities.

Thanks for getting me in here. Curious, you know, Leo kind of already hit on this, but we'd like to get your thoughts on the longer-term strategy with these infrastructure and assets in the Permian, and why or why not these would ultimately be good assets to monetize potential timing, what would make sense, and then just specifically, curious if in your opinion, these tank batteries would be a good fit for an MLP portfolio? Thank you.

Mike, this is Tim. I think starting with the tank batteries, the tank batteries and saltwater disposal systems are really pertinent to the wells, and they are one and the same essentially. So I don't see that at all as being the future candidate.

However, when you start looking at some of our other infrastructure projects, this would include sands. It would include water. It would potentially include gas processing facilities. They could theoretically be candidates. The real question, for example, in gas processing is that we could benefit a lot from having a seat at the table. You can refer back to my comments on that.

And so to the extent we need to build out more, having to see the tables are positive, and when we feel like it's the right time, that would be an excellent candidate. I think we would also say that about the water system and the sand mine, realizing that neither one of those have been expanded yet and, as a result, are not yet at their peak EBITDA.

So given the fact that those are probably sellable based on the multiple EBITDA, it wouldn't make sense to do it today.

So one thing we want to make sure is these things do get built. They get built on our time line with our flexibility. The examples of the water system, we can slow it down as much as we want to in the face of the situation where we have low commodity prices. And so we have all the flexibility in the world to make those decisions and go as fast or as slow as we need to. That's true of the sand mine as well. So we want to maintain that control, especially when we have the kind of volatility we've got.

Okay. Fair enough. And Tim, maybe switching gears here a little bit, but on the enhanced completion front, I think if you go across the industry here in different basins and even in the Permian, you have seen pretty staggering upticks in terms of what ultimately you are sort of projected to be at with an enhanced completion program. And it's not exactly clear in terms of what is apples to apples for comparing what the base reference point is. But I was hoping you could give some context on that. Are you guys -- are these really very big changes in terms of what you're doing on the completion side here versus kind of the base case standard completion, or is it more on that? Is it just modest uptick in terms of ultimate expectations versus [conch] on the other side of the basin talking, about 60% to 70% upticks and 180 day rates? Maybe just provide some context. Thanks.

I think the first answer to that question is it's too early for us. We've got so much work to do in terms of optimization. This is not true, not just only this 25 well campaign, as we look to the future with all these zones. Of course, they all behave differently under completion and so on. So we've got -- we have a laboratory that will be working for a long time on this question. But I think the most simplest way to deal with it is anecdotally and looking from the standpoint at our best analog, which is Eagle Ford.

And Eagle Ford, of course, we publicized a similar program where we could pretty easily document simply because you're dealing with 300 foot of shale. And depending upon which area, anywhere between 15% and 30% increases in EUR in a situation where because the increased completion at 5% to 10% capital cost bump. So that's Eagle Ford shale.

We were successful there. I anticipate us being successful here.

But to give you an exact number, it's just way too early. But I told you, we are encouraged and gave you a couple of numbers to say, we are seeing rates which are indicative of substantial bumps in the EURs if you believe that there is a strong correlation between production, especially early production in EURs, which we do.

Great. Thanks, Tim. Good update, guys.

Neal Dingmann; SunTrust Robinson Humphrey; Analyst

I know most of your plan is pretty well set as far as the rigs you mentioned in the Perm added. I guess just my question is, if you have some of the success over in the Eagle Ford, particularly with some of this Upper Eagle Ford potential, any thoughts about would that change any plans for potentially in 2016, or are you pretty well set now with the 12 rigs coming on in the Perm and what you have going on in the Eagle Ford irrespective of results?

None that is irrespective of results. I mean we are going to look at how the wells perform, and Eagle Ford we have had quite excellent results as I mentioned. Of course, right now, we are sort of targeting in on the two rig add, and that will be focused on both Upper and Lower targets, as well the staggering and spacing concept. But that's because we're drilling excellent wells.

I think we'll always be in the business of allocating capital to the best returns is what it amounts to regardless of the basin.

And then in that Eagle Ford, just so I'm clear, are you going to be drilling some Upper and Lower on the same pads and that will further improve the costs on some of those?

Yes, that's right.

Okay. Very good. Thank you all.

Robert Christensen, Imperial Capital.

Robert Christensen

Yes, my question is, why not do more in the Lower Spraberry? It's less depth and probably less cost in this environment. And you've had some very good wells this quarter, a material uptick from what you drilled in the second half last year there. So that's question one.

Yes, I think, of course, I think Scott already mentioned that to you that where we really had not anticipated doing any Lower Spraberry Shale wells this year's campaign, Bob, will be mostly just because of wanting to stick to the zones which were very predictable. The more we see the Lower Spraberry Shale, the more excited we get.

In fact, if you take a look at this year's campaign of 100 wells that we now plan to spud, that's up from the earlier campaign because of the new rigs. About 10% of those will, in fact, be Lower Spraberry Shales.

And so yes, I would agree with you, Lower Spraberry Shale is great. It calculates us having the most oil in place of any of these zones. If anything, it is complicated by the fact you've got offset vertical wells in the area that need to be considered, but overall the productivity looks quite outstanding.

My second question is, I guess, high level. So you're going to be capable with 18 rigs as of the end of the first quarter of 2016 to grow at these 20% growth rates through 2018. Without incremental rigs, we draw a line end of the quarter, of the first quarter of 2016, and we are going to be capable of growing at 20% plus oil through 2018.

That's correct.

Okay. And to tack on to that, do you hit a skate velocity? In other words, provide enough cash flow off the first two years of this effort to live within cash flow under sort of $60 oil, which I think is the strip out in 2018. Do we hit sort of a skate velocity?

Yes, if it gets up to $60 and stays there, we are in tremendous shape, Bob. So with a 30% drop in costs, a $60 oil price environment, you'll see significant growth coming out of Pioneer.

But within cash flow in, let's say, living within cash flow in like 2019, I realize there are so many moving parts here. But I think if we (multiple speakers) feel comfortable --

Yes, probably by the end of the three years, we will probably get to neutral cash flow in that type of environment with the well costs staying down 30% plus.

Excellent. Thank you very much.

Paul Sankey, Wolfe Research.

Appreciate the detail, and this is in many ways a follow-on question, even to the previous one about high-level strategy. You know listening to you, I was reminded about the old joke about two hunters meeting a bear, and the one guy says, you can't out run a bear. And the other guy says, no, but I can out run you.

And I guess the idea of my question is, at the highest level strategy, do you see yourselves as part of the global market share war that we're seeing in the industry and that you're just going to out run it and survive it? Or is the aim here to sort of growth to the point where you show within financial reason your long-term potential is so significant that you can sell Pioneer to a higher bidder?

So I guess I'm ultimately asking, why don't you pursue more of a return strategy than a growth strategy this year?

No, number one is a return strategy. So we stated we're getting 45% to 60% returns at the strip prices. So that's the number one driver. The second driver is to bring our NAV forward, and it just happens to get -- we get substantial growth with that. At the same time, maintaining a great balance sheet.

So, we think -- I personally think shale oil will out survive LNG projects around the world. It will survive new exploration project. It will survive essentially all other shale plays US in the Midland Basin, and so the world needs the Permian Basin.

So eventually supply/demand is going to reset. And the longer it stays lower, oil prices are going to bounce back even quicker. It's going to be very volatile over the next several years. So that's the focus of the Company.

Yes, that's just a very clear and simple answer. So I guess you are ultimately part of the market share war and you're going to run faster than the LNG, Hunter and everyone else out there?

That's right.

Great. You've answered it. Thank you.

And ladies and gentlemen, this does conclude our question-and-answer session for today. I'd like to turn the conference back over to Scott Sheffield for closing or additional comments.

I'll probably just add a good closing remark so on that last question. So, again, look forward to seeing everybody on the road and have a great last month of the summertime, and we'll see you in September with the startup of the conferences. Look forward to seeing everybody in November to report our next quarter's production.

Thank you very much.

And ladies and gentlemen, this does conclude today's conference, and we do thank you for your participation.