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Pioneer Natural Resources Co. (NYSE:PXD)
Q2 2018 Earnings Conference Call
August 8, 2018, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Welcome to Pioneer Natural Resources' Second Quarter Conference Call. Joining us today will be: Tim Dove, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Neal Shah, Vice President, Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. At the website, select Investors, then select Earnings and Webcasts. This call is being recorded. A replay of the call will be archived on the Internet site through September 3, 2018.

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 now like to turn the call over to Pioneer's Vice President, Investor Relations, Neal Shah. Please go ahead, sir.

Neal Shah -- Vice President, Investor Relations

Thanks, Selsina. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Tim will up first. He'll provide the financial and operating highlights for the second quarter of 2018 and our plans for the remainder of the year. He will also highlight our continuing strong horizontal well performance in the Permian Basin

After Tim concludes his remarks, Rich will update you on our firm transportation commitments to move oil from Midland to the Gulf Coast, and the financial benefits we're receiving from growing refinery and export sales in this market. Rich will also cover the second quarter financials and provide earnings guidance for the third quarter. After that, we'll open up the call for your questions.

Thank you. With that, I'll turn it over to Tim.

Timothy L. Dove -- Chief Executive Officer

Thanks, Neal, and welcome, everybody. This is Neal's first earnings conference call, Frank Hopkins having retired. So, we welcome Neal to the team.

We reported another strong quarter of operating and financial results in the second quarter. We're seeing improvements in our drilling and completions efficiency, and also our well results look very strong. This is also the first quarter where we began to see a very significant positive impact from our FT position on our cash flow. More on that in a minute as we elaborate some more details on that.

Permian production continues to be strong. After we adjust for certain unanticipated items and the impact of those, such as severe weather, highline pressures, and an accounting change, adjusted production came in at 177,000 BOE per day and 272,000 BOE per day. Those were essentially at the midpoint of guidance as shown. Strong earnings quarter with $243 million of adjusted income, or $1.41 per diluted share.

Overall production, when you look at the total for the company, including assets that are essentially in the process of being divested, after you adjust for the same items, would've come in at about 320,000 BOE per day, or near the top of the guidance range. We did place 67 wells on production in the quarter. Some of those were somewhat back weighted to the last two months.

We continue to have an industry leading balance sheet, and our debt statistics continue to be extremely strong, with $1.5 billion of cash on hand. That is after having repaid the senior notes, which became due in May, of $450 million. We've now repurchased $51 million of our common stock during the first half of the year in association with the program we put in place early in the year.

Turning to Slide 4, and then following up on my earlier comments on the positive impacts of our FT position, we did deliver 165,000 barrels of oil a day to the Gulf Coast from the Permian under those FT contracts, and about 103,000 barrels a day were exported. So, we're becoming a very significant exporter when it comes to the Permian deliveries to the Gulf Coast. The uplift from those deliveries to the Gulf Coast added about $69 million of incremental cash flow. So, these numbers are getting significant. But, because the contracts are struck two months before the oil lifts, the Brent-WTI and Midland-Cushing differentials were very high and wider in May and June. A little bit less in July, but the point is, our third quarter uplift should be significantly higher than the second quarter. We're currently estimating it'll be over $175 million for the third quarter. So, we're seeing significant impacts from our FT position in terms of positive cash flow.

If you look at our pricing going forward, the result of that is almost all of our sales to the Gulf Coast will be Brent related in terms of how they're priced. So, 90% of the volume will be going under FT contracts to the Gulf Coast, actually into early 2021, at Brent related pricing. The balance of the volumes of about 10% will now be priced based on WTI-Cushing. We executed an option to do that. There had been, prior to September, being priced based on Midland prices. We have toggled that to now those are going to be priced based on WTI-Cushing. Essentially, when we're done with that, we'll have no exposure to Midland pricing through the next couple of years -- in fact, through 2020.

On the gas side, 70% of our volume, as we've reported before, is transported to the west and tied to Southern California gas price indexes. The balance of the 30% being sold under term contracts at Waha. It did give us an uplift to be able to price the significant amount of gas into the Southern California index market -- in fact, about $0.25 per Mcf positive impact compared to -- we had all that volume in Waha. I think the important message for gas is that we don't anticipate any issues in moving our gas volumes moving forward for a few years, especially until we get the Gulf Coast express pipeline on the second half of 2019.

On the well front, we just want to point out, as an example, that we continue to show impressive performance. An example in particular here is the Wolfcamp D. We have the three-well pad in the southern JV area. We put 3.0 completions on these wells and you can see the numbers are sort of staggering -- about a 75% improvement over the early life of these wells compared to the earlier style completions that were done say three and four years ago in the exact same area. So, you can see we're making significant inroads in improving the performance of these wells as we now have more advanced ability in terms of completions.

Turning now to Slide 5, for the remainder of the year, we plan to add rigs. We're running about 20 rigs on any given day today. The plan is to add four rigs, a couple here shortly and a couple later in the fourth quarter, with the idea of beginning to support the 2019 plan. I think that's going to effectively not impact this year's production as much as it will positively affect next year. We continue, as a result, to be in our range of POPing 250-275 wells this year, which is not changing, even with the additional rigs.

I can say definitively margins remain very strong. Of course, oil prices are significantly up from where they were a year ago. If you go back and check oil prices this week one year ago, they were $49.00. So, you can see we've had substantial improvements as a result of that. The margins, on a cash basis, including the longer-term IRRs, are strong and that is one of the reasons we're seeing the opportunity to invest further in more 3.0+ wells. We've actually seen very good results on our 45 planned 3.0+ wells in the first half of the year and, as a result, we're adding 60 more -- again, related to the fact the margins are quite strong. But, also because of the improvement we're seeing from 3.0+ are substantial as they continue to show significant improved economics from that incremental investment.

I think it's also important to watch the STACK-berry testing we've referred to in the past. We have about 19 wells in three different drilling appraisal programs that will be brought on production the second half of this year. The idea is to develop the strategy for long-term development of the Middle Spraberry Shale, the Jo Mill, and the Lower Spraberry Shale. Of course, we're trying to figure out, even though we've drilled excellent wells in all of those zones, the proper sequencing, spacing, and staggering of those wells and exactly how to stimulate those as to get optimal capital efficiency in those STACK programs.

Actually, the first six of those wells have recently been put online. They're cleaning up as we speak. You can expect some more color on this as we get through the next couple of months -- in fact, on the third quarter call in November.

Now turning to Slide 7, an update regarding our divestiture process. We are fortunate to be able to say we've closed two sales, one being Raton. This is our exit from Colorado after many years being there in the gas business. And also, having sold selected western Eagle Ford acreage. The total of those is $182 million. We have, as recently announced, signed a purchase and sale agreement to sell the West Panhandle field for a little over $200 million. We expect that closing this quarter. We're still progressing divestiture of the Eagle Ford and other South Texas assets. We hope to have some more news on that as we go forward.

At the end of the process, and I think it will take essentially the balance of all of this year, it will result in Pioneer becoming that Pure Play Permian Basin player that we've been talking about. Importantly, it will improve our reported margins, our per barrel and per BOE metrics, and corporate returns when that's all completed. It's a work in progress, but it's going well.

As we've also mentioned during the last few months, we're adjusting our capital program for this year to a range of $3.3-3.4 billion. Fundamentally, we believe this capital is well spent based on what I mentioned earlier, which are the strong returns we're continuing to see at the well level. That will be funded from what has been an increased amount of operating cash flow related to current pricing of about $3.3 billion and part of the proceeds from the asset divestitures I mentioned a minute ago.

The capital budget adjustment is related to the fact that we're going to be adding four rigs in preparation for 2019, and also the incremental 60 3.0+ completions in the second half -- of course, related to the higher pricing environment that we've mentioned and all seen in the industry, compared to what we set our original budgets at the beginning of the year. In addition, in particular, we're now seeing the impacts of the steel tariffs flow through and they're affecting tubulars and other steel products that we use. We could see steel easily, compared to last year, be 20-25% over last year's cost for the same products.

Overall production continues to be forecasted in this range of 19-24%, and we still believe we're trending toward the upper half of that range. I'll give a little bit more color on that in a couple more slides.

Going to Slide 7, just a little bit of an update regarding uplifts from 3.0+ completions, just to give you some confidence that we continue to see dramatic improvements in these as compared to the prior completions. This is, as shown here, in various zones and in various areas across the field. It gives us confidence that the investment in 3.0+ style completions, and the additional capital required for those, is money well spent. As we move forward, the way to think about the program will be us tailoring and customizing completions by zone and by area to optimize capital efficiency. Certainly, 3.0+ will play an important role in that program, but we're going to optimize each specific well, each zone, and each area to get the best results on an economic capital employed basis.

Now turning to Slide 8, we continue to execute a significant growth trajectory in the company, as shown. The third quarter continues that grow as we show at a forecast here, with Permian only at a range of 278,000-288,000 BOE per day. That shapes us up for a strong finish in 2018.

Going to Slide 9, this is important from the standpoint of looking at this business long-term, which we have to do. We continue to reap the benefits of long-term planning in the Permian. As we all realize, this is a multidecade development and it needs multidecade thinking in advance. You can look at this slide and realize, as an example, natural gas processing comes to mind as something that's very important that we need to invest in -- in particular, regarding Targa's gas processing system. They will be adding three new facilities, new plants, beginning later in September of this year, and two more in the first half of next year, that will increase our capacity by 70% compared to where it is today.

So, we're taking broad brush steps to make sure that issues surrounding line pressure and availability of gas prices we're ahead of. Toward that end, the planning is associated now with -- as opposed to putting in a 200 Mcf a day plants, as has been the past track record, moving forward to adding 250 Mcf a day plants as a part of that plan going forward.

You can look at water as another example. We believe that water availability and disposal is an issue that needs to be dealt with long-term, but with that said, our environmental footprint's very important to us as well. You can see on the graph in the bottom left is the plan is to actually get to a point where our use of fresh water approach is zero in a few years. In fact, once we increase our reuse volumes and also bring the Midland water processing facility online in probably early 2020 or so, we get down to a very low percentage.

Right now, we're increasing our reuse volumes of our produced water to the point where it's going to represent 15-20% of our water volumes in the fourth quarter of this year. So, we're taking very specific steps. This is excellent environmental stuff on the one hand, but it increases returns because the economics on produced water and our effluent water systems are quite excellent.

I've already mentioned the benefits of FT. It gives us a tremendous amount of insulation from backups that happen in the domestic markets where we're just producing too much oil and we can't move it out. But, we will have FT scoped out in our case all the way through the early parts of 2021. We'll be looking to other opportunities in the future as well. I think the main messaging here is that long-term planning is essential. We've been investing in it for some time. We continue to invest in it, and we think it's a very big, important aspect of having reliable execution. It's all about improving the economics and reducing our cost structure.

I'll go on to Slide 11, just reiterating that our model and go forward plan remains the same. It's over the next many years to enhance shareholder value through drilling strong return wells that then feed into strong corporate returns, basically featuring capital discipline. We do believe in return of capital. We're heading, hopefully as quickly as possible, toward a cashflow generative model and we think, as a part of that, having one of the strongest balances in the energy patch gives us financial flexibility to pull that off.

The main message, as I referred to in the earlier slide, is that this is a long-term program, multidecade campaign, so we need to be thinking that way. But, also, it reduces risk as we go forward. Again, the message being we have a program we believe is a very good use of capital. It's a high rate of return on capital employed, but also, as a result, leads to the opportunities for an increased return of capital to shareholders.

With that, I'm going to pass it on to Rich for more color on the benefits of FTE and our marketing strategy, as well as review of our financials and a look toward the third quarter.

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

Thanks, Tim, and good morning. I'm going to pick up on Slide 11 and reiterate what Tim discussed earlier on our FT uplift during the quarter. You can see here that we did move 165,000 barrels a day of oil to the Gulf Coast. That did add $69 million of incremental cash flow, or about $4.10 per barrel, uplift to our oil realized prices. Of that, 103,000 barrels a day were exported. That was primarily to Asia and Europe. As you look forward, starting in August, those barrels we can export can increase because we now have access, beginning in August, to all of our barrels getting on the water and being exported. Now, the facility's available in Houston, so those will get Brent related pricing.

We do have about 10% or so of our barrels that are sold in the Midland Basin still, but we did toggle on one of our contracts to move to a Cushing based pricing starting in September. So, we now are 100% insulated from Midland-Cushing differentials starting in September.

Turning to Slide 12, this is intended to provide some color on the two main pricing components of our firm transportation uplift. The first is the Brent-WTI differential, and the second is the Midland-Cushing differential. Simplistically, we are receiving Brent related prices for 90% of our oil sales that we take to the Gulf Coast versus a Midland price. However, there are some timing items that affect the price. For instance, for the majority of our Gulf Coast refinery and export sales, the Brent-WTI differential is fixed at the time the sales contract is entered into, which is typically about two months prior to the plan delivery, really just to allow time for ship logistics and dock space planning.

The second component of the Midland-Cushing differential is typically determined on a trading month basis for the month of delivery, or roughly one month in advance of when the delivery actually takes place. As result, wider differentials for Brent-WTI in May through July and wider Midland-Cushing differentials in June through August-to-date. We do anticipate a significant uplift in third quarter cash flow from our firm transportation. The second quarter was $69 million. That was up from $16 million in the first quarter and the third quarter uplift is more than 2X at over $175 million uplift expected for the third quarter.

Turning to Slide 13, and looking at it similar to what we do on oil on the gas side, we move to the Southern California markets that are tied to Southern California gas price index about 70% of our production. The remainder is sold at Waha under term contracts to utilities primarily. The benefit of moving out to the Southern California markets was a $0.25 uplift in gas prices in the second quarter. If you look at July, because of the heat that's been hitting out in Southern California, we do expect about a $0.60 uplift in July and, based on where we are in August, about a $2.00 uplift in realized prices for those sales in August.

As I mentioned last quarter, we did secure firm transportation on Gulf Coast Express, the Kinder Morgan's Pipeline. That is expected to come online earlier in Q4 2019. At that point in time, we'll have access to LNG exports. We've already actually signed up one contract related to that and then other sales to refineries, petrochemical facilities, and into Mexico. As you can see from this, with our firm transportation arrangements, we are in great position to ensure that all of our gas moves out of the basin and into higher priced gas markets.

Turning to Slide 14, looking at our earnings summary for the quarter. Net income attributable to common stockholders was $66 million, or $0.38 per diluted share. That did include non-cash mark-to-market derivative losses due to the increase in Nymex oil prices during the quarter of $170 million, or $0.99 per diluted share. And then, we had three unusual items all related to our ongoing asset divestiture program. That was a net charge of $7 million, or $0.04 per diluted share. After adjusting for those items, we're at $243 million for the quarter, or $1.41 per share.

At the bottom of the slide, we show our actual results compared to our quarterly guidance. As you can see, our reported second quarter production was 328,000 BOEs per day for the quarter, which is above the top end of the guidance range. The second quarter production includes 50-100 BOEs a day of gas, or 35,000 Mcf per day, that we should have started including in production during the first quarter of 2018 in accordance with the new revenue recognition rules. Unfortunately, after reviewing one of the contracts further, we realized that these volumes were netted to cover certain electric and fuel related charges. Consequently, we had to adjust for those volumes in the second quarter and move the fees from being reported as a reduction in revenue to production costs.

Similar to the other revenue recognition items that we recognized in the first quarter, there were no earnings or cash flow impact associated with this change. The net effect is that the second quarter includes 35,000 Mcf a day of gas production related to the first quarter and 36,000 Mcf of gas that's related to the second quarter for this change. To be clear, there was no wellhead gas production change. Our wellhead production continues to be consistent with our expectations. This was just an accounting change. The rest of the items at the bottom of that table are consistent with our guidance, so no news there.

Turning to Slide 15, looking at our price realizations, we did change up our oil bar here to include our FT uplift. So, if you look on adjusted for our transportation moving barrels to the Gulf Coast, oil prices were up 4% quarter-over-quarter. If you look at the bottom of the table, below the second quarter, you can see that the uplift basically covered our widening differentials in Midland for the quarter.

NGL prices were up 4% quarter-over-quarter and gas prices were down 24% quarter-over-quarter, mainly due to decline in Nymex prices coming out of the winter demand season. And, as we've all seen, substantially wider differentials on gas in all basins across the US.

Turning to Slide 16, you'll see that production costs quarter-over-quarter were fairly consistent. There are two items to note -- one, being the gathering, processing, and transportation increase really reflects the incremental reclass I just mentioned on our contract that we moved fees from revenue down to production costs. So, that had no impact on cash flow or earnings, just a reclass.

And then, LOE is up slightly, due to higher seasonal electricity costs for the quarter. We had a really hot May and June out in West Texas and that increased the demand and therefore pricing for electricity. The other item is labor costs driven by activity with higher oil prices that Tim talked about. So, we have seen some inflation on labor.

Turning to Slide 17, looking at our liquidity position. We continue to have a very strong balance sheet and excellent liquidity, with $800 million of net debt at the end of the second quarter. Our cash on hand was at $1.5 billion. As Tim mentioned, we did pay off $450 million of bonds during the quarter, so that's reflected in there. If you look at the maturity schedule, no near-term maturities at this point. And, the company's in excellent financial condition.

Turning to Slide 18, the only change here is that we are just now giving guidance for Permian Basin on production, production costs, and DD&A, given our ongoing divestiture process and the timing of closing certain of those sales. Other than that, the rest of the guidance items are on a total company basis, so I'm not going to go through them individual, but they're there for your review for the upcoming third quarter.

...

With that, I'll stop there and open up the call for questions.

Questions and Answers:

Operator

Thank you. [Operator Instructions] And we'll take our first question from John Freeman from Raymond James.

John A. Freeman -- Raymond James & Associates, Inc. -- Analyst

Good morning, guys. On the additional four rigs, Tim, it doesn't change the previous number of wells that you're looking to POP. So, as we think about the significant number of ducks that build up, how should we think about cadence of those ducks being worked down in '19?

Timothy L. Dove -- Chief Executive Officer

Since we're starting this up in August, and our typical spud to POP timing is going to be 150-170 days for a three-well pad. You can see that they were talking five months, so we won't even be completing wells until probably January from the additional rigs. It'll effect the cadence of 2019 POPs or ducks. The ducks -- we'll start to reduce that count of ducks starting early next year.

John A. Freeman -- Raymond James & Associates, Inc. -- Analyst

That's helpful. You all did a phenomenal job on the marketing side and getting so much of your crude to the Gulf Coast. What percentage of your exports right now goes to China?

Timothy L. Dove -- Chief Executive Officer

Rich, you want to comment on that?

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

Yeah, we probably have only had a couple sales this year to China, and none recently. As all of these oils are fungible and they move around, I think China has reduced their takes out of the US and those barrels have now just gone to the place where the barrels that China was getting -- we're not getting them today. I think it's just one of those things, that it's a global market and the barrels will move around to find the home where they need to be. But, the demand is still there.

John A. Freeman -- Raymond James & Associates, Inc. -- Analyst

That's great. So, the tariffs that got announced today basically have zero impact on you guys it sounds like. Thanks a lot for the answers. It was a great quarter.

Operator

We'll take our next question from Doug Leggate from Bank of America Merrill Lynch.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks. Good morning, everybody. Tim, could you dig into the CapEx guide a little bit more? When you set your long-term guidance out to 2026, one assumes that you had some idea what the rig cadence was going to be. Adding four rigs in the second half of this year, I'm guessing, was in the original 2018 budget. If it wasn't, can you explain how that's changed and how we should think about the rig trajectory as we go into subsequent years? What I'm really trying to get at is, when you set the '19 budget, are we assuming rig additions at the end of the '19 or did we get another CapEx increase as we move through the year? I'm just trying to understand if that was in the original plan and, if not, what changed.

Timothy L. Dove -- Chief Executive Officer

Yeah, Doug, I'd have to go fish out the original plan that we put out in relation. But, I recall that we were generally talking about adding about four rigs that would support the 2019 campaign. Thus, it's just a matter of the timing of when you want to put those on. In our case, we want to get a little bit of a head start for 2019, so it's a little bit of a bump to the capital budget. We didn't have granularity of which month they would come on when this plan was first put out a couple of years ago. As we get closer, we're maneuvering to hit the kind of numbers we want to hit with regard to execution. That means the idea to put these four rigs on now makes since.

As it relates to what we might put on late next year, gosh. We haven't even really developed our 2019 plan yet. So, it would be too early for me to comment on that.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Just to be clear in what I'm asking, the '19 plan -- whatever year it is -- to tell us that you're going to add rigs. Should we then assume that, when you make that kind of comment, the capital program doesn't include those rig additions?

Timothy L. Dove -- Chief Executive Officer

Well, we had not solidified, for example, on when we would add the 2019 rigs until we got essentially into this middle part of the year. So, it did not include those four extra rigs for this year's capital budget. Now, it is in there and that's one of the reasons we've adjusted the budget. That's the way I would answer the question. We would probably approach it the same way next year. We're going into the year running 24 rigs. We'll see exactly how we might want to adjust as we get to the end of 2019, but that's all still being evaluated.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Okay. Given that you've now quantified the 3.0+ wells in the second half of this year, presumably you have some idea -- I guess, maybe you haven't defined it yet for 2019 -- but, with the additional four rigs plus the incremental 3.0+ wells, does that mean you're actually accelerating the pace versus the original 10-year plan? Or is this still the base case? I'll leave it there. Thanks.

Timothy L. Dove -- Chief Executive Officer

Yeah, I don't think we're really accelerating the case. What we're doing with the 3.0+ wells is just improving the completions, if you will. I think the real important message about that is the one I mentioned during my prepared commentary, which is to say we're not going to be using 3.0+ across the whole field because we've determined in some areas it's just not necessary. We see some areas, for example, where we would use a 3.0+ style amount of profit, but we might not need as much water in certain areas.

So, there is not a cookie cutter approach here. It's going to be evaluated and tailor made by completion, by area, and by zone. From that standpoint, nothing's changed in terms of our long-term modeling. We're just trying to get more efficient in making sure we're being capital efficient in the way we're doing things. There's no sense spending more money on a 3.0+ style completion if we can get it done with a 3.0. That would be the principle.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

I appreciate the answers, Tim. Thanks a lot for your time.

Operator

We'll take our next question from Arun Jayaram from J.P. Morgan.

Arun Jayaram -- J.P. Morgan Securities LLC -- Analyst

Good morning. The first question is for Rich. Rich, you highlighted the cash flow uplift from FT and marketing in Q3. Could you give us a sense of what that could look in 4Q and in 2019 if we just assume the futures market for differentials proves correct.

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

Yeah, if you look at the futures market, the Brent-WTI spread roughly is $7.00 for the rest of the year. If you look at that, and then the Mid-Cush differential, it tightens over the remainder of the year. There is a pipeline going up to Cushing that comes on and moves a little bit more barrels. In general, the fourth quarter could look similar to the third quarter if things stay where they're at and prices stay where they're at. And then, as you move into '19, if Mid-Cush differentials tighten, then that uplift will come down some based on that spread tightening on Midland-Cushing. So, I think that's really where you can do the modeling and calculate what those would look like.

Timothy L. Dove -- Chief Executive Officer

The only thing I'd add is our volume's going up, too.

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

That's right.

Timothy L. Dove -- Chief Executive Officer

The actual dollar per barrel is what you're referring to, but the actual gross dollars we're talking about are going to be significantly higher, all other things equal. Our volume of exports is going up.

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

And our FT, we built it to match with our production growth. So, you'll see our FT volumes that we're moving to the Gulf Coast increase as well.

Arun Jayaram -- J.P. Morgan Securities LLC -- Analyst

Great. Just a clarification, Tim, on your guidance commentary. You reiterated the upper half o the 19-24% Permian production growth outlook for total volumes. Does that also apply to your oil production, to be the upper half of the range for oil?

Timothy L. Dove -- Chief Executive Officer

Yes, it does.

Arun Jayaram -- J.P. Morgan Securities LLC -- Analyst

Great. Thanks a lot.

Operator

We'll take our next question from Brian Singer from Goldman Sachs.

Brian Singer -- Goldman Sachs & Co. LLC -- Analyst

Thank you. Good morning. Can you talk a bit more about the Spraberry and Jo Mill appraisal programs, specifically what your hypothesis is in terms of development strategy and spacing? We wonder a little because, with Lower Spraberry wells achieving some of the greatest uplift from your version 3.0 completions, how would you expect well performance to change, if at all, in a development mode situation with at optimal spacing.

Timothy L. Dove -- Chief Executive Officer

Great question. This is an important topic. I'm going to let Joey Hall answer your question, Brian.

JD "Joey" Hall -- Executive Vice President, Permian Operations

Good morning. Really, that's why you see us progressing the STACK-berry testing. We've done a lot of drilling in the Lower Spraberry Shale, but not nearly as much in the Jo Mill and the Middle Spraberry. We just put the first test online. We're deploying our new and larger completions. Going forward, I would see us start to increase the amount of wells that we do in each one of these areas because they're a significant part of our million in ten initiative. So, we have very high expectations. We know the Lower Spraberry Shale much better than we do the Jo Mill and Middle Spraberry, but everything that we do and see from our competitors around us leaves us incredibly optimistic. So, looking forward to the results. You'll hear a lot more about particularly the Jo Mill and the Middle Spraberry next quarter.

Brian Singer -- Goldman Sachs & Co. LLC -- Analyst

Then, would you expect any degradation relative to the extent of the advantage uplift that you're seeing in Lower Sprayberry in a development scenario (i.e., are we seeing excessively good wells there as a result of just being early on in that program or not)?

JD "Joey" Hall -- Executive Vice President, Permian Operations

I wouldn't say so. I would say what we've drilled is what we expect. We've applied a lot of science to this STACK-berry test and we have over 1,000 wells that we've drilled in the Permian so far. We're taking all the lessons that we've learned -- we have similar issues between the Wolfcamp A and the Wolfcamp B. The lengths that we went to to understand how we should stimulate these wells and what the spacing should be has been quite extensive. So, I have no expectation that we'd see any degradation compared to anything we've seen in the past. To the contrary, because our completions have evolved, I would expect us to see better results in our Lower Spraberry.

Brian Singer -- Goldman Sachs & Co. LLC -- Analyst

That's great. To follow-up on Arun's question on the guidance in the Permian for the rest of the year, if both oil and total production are trending toward the upper end of the range, that would seem to imply an increase, particularly in the fourth quarter in the oil mix -- the oil as a percent of the total relative to your recent adjusted mix. Is that something that you see, and does that just have to do with the timing of bringing wells on? Or, are we looking at it the wrong way?

Neal Shah -- Vice President, Investor Relations

Hey, Brian, it's Neal Shah. It's not the oil mix that's going to increase. What you're looking at is the impact of ASC 606. Both oil and BOEs increase at a similar rate into 4Q to hit our full year guidance and to get to that upper middle half that we were talking about.

Brian Singer -- Goldman Sachs & Co. LLC -- Analyst

Yeah, I think there has been a bit of confusion on this. I think even a little bit here, right now, but that's something to follow-up on, even after the adjustment is made.

Neal Shah -- Vice President, Investor Relations

Yeah, we'll talk to you about that later offline.

Operator

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

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

Thanks. I wanted to follow-up a little bit in terms of the development approach as it relates to the STACK intervals. I want to revisit your thoughts on how you're approaching the Wolfcamp A and B developments. What's the current thought on the need to approach those concurrently to avoid any sort of depletion issues or interference issues as you come back through, if you were develop them on a single stand-alone basis versus a concurrent basis? How are you approaching that today and how has that changed, if at all, versus the past?

JD "Joey" Hall -- Executive Vice President, Permian Operations

I wouldn't say that it's changed, but it has evolved. Across the board, you see all three different options. You see scenarios where we can drill the Wolfcamp A and the Wolfcamp B independently, and timing is not that significant. You see other areas where we believe that you should come shortly thereafter -- within nine months to a year after drilling the Wolfcamp B -- and hit the Wolfcamp A. We also have examples where we believe that you should drill the Wolfcamp A and Wolfcamp B at the same time and zipper frac them. So, as we've evolved and seen longer-term production on these wells, it goes back to the completion recipe. It's going to vary across the field. So, we have all three examples.

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

What's the driving factor that influences whether or not you should be in each of those categories? I'm sure it's a complicated answer, but is there any way to simplify that?

JD "Joey" Hall -- Executive Vice President, Permian Operations

It's actually pretty simple. Thickness is one and presence, or lack thereof, of a frac barrier. It really comes down to that. There are even areas on the further eastern acreage where Wolfcamp A and Wolfcamp B are a single development. As you come across north and south -- if you look at the maps of how we do this, it's not something you can predict without looking at the maps. There are holes in the map where you do it one way and fringes where you do it another way. There are a lot of different variables that go into this. Again, going back to the 1,000 wells that we've drilled and completed, we've been able to zero in on this.

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

Okay. And the spacing configuration in the Wolfcamp A and B at present? What's the current go forward plan on that?

JD "Joey" Hall -- Executive Vice President, Permian Operations

Typically, we're going to be anywhere between 750-850 feet.

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

Okay. In terms of returns of cash, you have a modest buyback program this year. At any point in the next couple of years, do you think we see that picked up? When do you think, at the earliest, see that, given the current strip?

Timothy L. Dove -- Chief Executive Officer

Well, in my earlier comments, I mentioned our longer-term vision, and action plan, is to get to a point where we're cash flow generative to be able to actually make that decision. I think we need to wait until we're at that point. You'll notice, at that point in time, we'll be spending a lot of time on that question. Certainly, it's a matter of our board's review and they are very focused on this exact question. In fact, it'll be a topic at our August board meeting. So, I can assure you it's top of mind and front burner that we need to get there first.

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

Okay. Thanks, guys.

Operator

We'll take our next question from Charles Meade from Johnson Rice.

Charles A. Meade -- Johnson Rice & Co. LLC -- Analyst

Good morning, Tim, to you and the whole team there. If I could go back to the version 3.0+, your incremental 60 completions with that design in the back half of the year, can you give us a sense -- are those more completions in areas where you've already proven that this is the style of completion that's needed and where you're getting the uplift? Or, is some fraction of that, trying to take this new completion design to new areas?

Timothy L. Dove -- Chief Executive Officer

Joey, you want to comment on that?

JD "Joey" Hall -- Executive Vice President, Permian Operations

Yeah, Charles. For the most part -- I can't quote exact percentages -- we're going back to areas where we know we've been successful and then, in a few areas -- we're even drilling in some new areas, apparently. So, we're deploying those in the new areas and seeing what success we have. Even going into this, particularly in areas where we've drilled and completed, we go in with the expectation that it's going to be helpful, not just trial and error to try something to see if it does or doesn't work. So, there is some thought that goes into where we try these things. There are areas we've seen through past drilling and completions that we don't believe that they would be successful. But, for the most part, we're going to areas where we believe we're going to be successful based on past or current technology.

Charles A. Meade -- Johnson Rice & Co. LLC -- Analyst

Got it. That makes sense. Thanks for that detail. I was looking at your Slide 7, which is one of the interesting ones to see an update on every quarter. One of those version 3.-+ curves is not like the others. It's the one on the upper left. You could say that it has a positive second derivative through maybe the first six months, or you could say it looks like accelerating volumes for the first six months of flowback. It seems to be a standout. Could you talk about if you have any confident explanations about what's going on there? Or perhaps just hypotheses that you're working on?

JD "Joey" Hall -- Executive Vice President, Permian Operations

The only thing I would comment on that differentiates that as well is it's the Lower Spraberry Shale development. Optically, I understand exactly what you're saying. But, if you look at the dataset, it's a smaller dataset. It's in one of our better areas, and it just goes to show that there are certain areas where these 3.0+ completions -- and in this particular case, the Lower Spraberry Shale -- just makes a significant impact. And then, you go across the board, you see that it changes. That correlates to why we continue to do this in some areas and we may be a little bit more cautious in some areas.

Timothy L. Dove -- Chief Executive Officer

Charles, just to add, the datasets are materially different. 27 on the lower curve and six wells on the upper curve -- but, we will be having more data. We have six more of this type of Lower Spraberry Shale 3.0+ tests in the second half. So, we'll be building up our dataset. We'll be able to address that a little more clearly to you once we get the results of those wells. We can pile those onto the already six that we have and get a little bit smarter about why they're performing as well as they are. Don't get me wrong, we're happy about it.

Charles A. Meade -- Johnson Rice & Co. LLC -- Analyst

That's helpful. We'll look forward to that. Thanks.

Operator

We'll take our next question from Matt Portillo from TPH.

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

Good morning, guys. Just a little bit of clarification. Given the moderated growth in Q2 and the commentary around upper end of guidance for the full year, it implies a pretty large ramp in production for the fourth quarter, which sets up well for 2019. I'm trying to understand a little bit better what's driving that incremental improvement in growth given the radical POP schedule in the back half of this year.

Timothy L. Dove -- Chief Executive Officer

If you take a look at it, our ranges are put in place to reflect all different outcomes, for sure. The third quarter, in general, is starting off in a very strong fashion and we'll see how it finishes off. We're speaking now about something like a month and a half of data, so the third quarter may be a little bit conservative. That's where we're leaning. The fact is, the moderated growth you saw in the second quarter, to a great extent, not counting the other factors we mentioned, was a product of the fact that we only had 19 POPs in April. You do the math on that, and you realize five or six wells swinging here or there that produce 2,000 barrels a day are enough to substantially move the numbers.

So, it is a very complicated evaluation because there are so many moving parts, but the bottom line is we're confident. It has to do with the fact that the back way to growth in the second quarter -- but also, it's a fact going into the second half of the year, you have the Targa gas plant on. I think it's supposed to come on the end of September, so if you look at the fourth quarter in particular we should see a significant bump in production that comes from the fact we would have relatively lower line pressure issues. That certainly is a contributory fact as well. So, there are a lot of factors to give us confidence. But, we also have to execute.

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

Great. That's extremely helpful. And then, pertaining to the Wolfcamp D, you had early success in delineation of this horizon with modern completions year-to-date. What are your current thoughts around this horizon and how it may factor into development as you move forward into 2019 and beyond?

JD "Joey" Hall -- Executive Vice President, Permian Operations

Matt, we characterize the Wolfcamp D as being applicable to about 60% of our acreage. I would look at the Wolfcamp D very similarly to the way that I would look at the Jo Mill and the Middle Spraberry Shale and Lower Spraberry Shale, in that we continue to delineate. We continue to see promising results. As the development plan progresses over the next couple of years, you'll see us layer in more Wolfcamp D wells.

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

Thanks, guys.

Operator

We'll take our next question from Neal Dingmann from SunTrust.

Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst

Good morning. Tim, my question is on your '18 guide up there. Does that bake in any downtime for the Targa plant or any other variables like that in that updated 2018 guide?

Timothy L. Dove -- Chief Executive Officer

We always have downtime built in. It has to do with a statistical evaluation of the past. It can be calculated somewhat based on many, many years in this field. Of course, we had a bit of a statistical anomaly in the second quarter related to multiple bad weather events that we've never seen in the month of May before. But, that being said, we have downtime and some room in our forecast that's associated with making sure that we allocate the potential impacts of these kinds of issues. Yeah, it's in there. I wouldn't say we have a specific number in there related to the Targa plant coming on. The plant is evidently still planned for the very end of September and, from our standpoint, we understand that's on schedule.

Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst

Very good. Just to follow-up on M&As, it seems like my talks of privates out in Midland Basin there seems to be a number of potentially for sale of some decent sized Midland Basin companies. Would you have interest in any of these given your already existing large inventory position?

Timothy L. Dove -- Chief Executive Officer

I think you got it right in that last part of the question. We have such an extreme amount of inventory to work on and we're doing it as fast as we can. Our main objective, in terms of adding value when it comes to anything related to what you're talking about, is actually the exchange of acreage, the trading of acreage. That's really where the real value comes in when you have such an extensive portfolio that we have. We are still in the midst right now of multiple sets of transactions to exchange acreage, to trade acreage. We're talking about millions of lateral feet added as our goal. A million lateral feet adds $1 billion worth of value, essentially. So, that's where we see the real value.

Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst

Very good. Thanks for the answers.

Operator

We'll take our next question from Derrick Whitfield from Stifel Financial.

Derrick Whitfield -- Stifel, Nicolaus & Company, Inc. -- Analyst

Good morning. Tim, with the understanding that you're better protected from inflationary pressures than most of your peers, how do you see the service price environment playing out over the next several quarters if the industry's faced with Midland netbacks that are less than $50.00 a barrel? Do you think the service companies are trying to look through that potential period of weakness?

Timothy L. Dove -- Chief Executive Officer

Well, first of all, we had a more significant increase in costs this year than we would've assumed as we started the year. We were talking about 5-7% increase. Now, oil prices have gone up -- take hedges out of the mix -- from $49.00 to $69.00. So, a 40% move in oil prices. From that standpoint, having the inflation we have is not unexpected. I think, though, has you look forward and realize with pipeline constraints -- that is to say, on both oil and gas -- coming to fruition, it'll probably lead to a slowdown in completion somewhat. The rigs in general are contracted for longer periods of time than the fracked fleets. So, I think the rig count you see is relatively stabilized and not moving. That makes sense when you get into multiple years, or several-year, rig contracts.

But, I think what's going to happen is a slowdown on the completion front. That's naturally what makes sense if you have essentially full pipelines. That does not bode well for increases in cost when activity levels are coming down. And you see some of the big service companies now saying we're not bring additional frac fleets into the basin while margins are not improving any more than they are. So, I think we could have a situation where, if we can stagnate oil prices where they are today, we might be able to put more of a lid on service cost increases and cost increases in general in 2019 as compared to this year. Just a product of a slowdown in relative completion activity. There is a lot of ancillary aspects of completion activity that would also slow down.

I think the other side of the coin, as we look at 2020 and 2021, when the pipelines are now in place and full in terms of their ability to take volume, that could be another period of inflationary activity to the point where everyone's trying to get their duck count reduced. I would say the bigger risk inflation wise is past 2019. It's really 2020 and 2021. Everything else equal.

Derrick Whitfield -- Stifel, Nicolaus & Company, Inc. -- Analyst

That makes sense. As a follow-up to your comment on the customization of your version 3.0+ design, could you speak to the level of customization that's applied by zone, by area, across the field? I'm trying to get a better sense on the degree of variation in proper loading and fluid loading and cluster spacing.

Timothy L. Dove -- Chief Executive Officer

Sure. Joey?

JD "Joey" Hall -- Executive Vice President, Permian Operations

I wish I could quantitatively answer you question. But, as you see us explain 3.0+ completions, even my team begins to get confused on which ones we're referring to. I would say we have a dozen-plus different recipes. Even if you look at the STACK-berry tests, for example, the way I'm completing my Middle Spraberry is with 2,500 pounds per foot. The Jo Mill's was 1,400 pounds per foot, so nearly half. And then the Lower Spraberry Shale with 2,500 pounds per foot. And then, with the 3.0+, they're 2,500 pounds per foot plus. We're still doing some that are 1,700 pound per foot. Again, when I go back to my description of how we do the Wolfcamp A and Wolfcamp B, the recipes vary greatly across the field. There's just no way I can characterize it by zone, or even by area, necessarily. There is literally a dozen-plus recipes that we're using.

Timothy L. Dove -- Chief Executive Officer

That's a good reason why we have area teams that are very specially located in their areas where things change. It's their job to decipher what's optimal.

Derrick Whitfield -- Stifel, Nicolaus & Company, Inc. -- Analyst

Thanks, guys. That was very helpful.

Operator

We'll take our next question from Leo Mariani from NatAlliance Securities.

Leo Mariani -- NatAlliance Securities LLC -- Analyst

Hey, guys. About some of the infrastructure bottlenecks you guys saw in the second quarter, it sounds like you've baked some downtime in here in the third quarter. But I'm trying to get a sense, as the Targa plant comes online in the September and a couple more next year, do you guys generally see those problems starting to disappear as we head into 4Q in 2019?

Timothy L. Dove -- Chief Executive Officer

Yeah. I think we've baked in some impact in the third quarter. We can relatively clearly estimate that just by basic run rates today of line pressure issues. It comes and goes. As we put new compression in the field, with Targa, you'll see reductions of line pressures in those areas and you'll see them increase in other areas. But, the big fix is to get the new big plants on. That allows us to reduce system line pressure. There are other ways to solve it in the interim, which is to take some gas off the system and so.

But, the fact is, we have it baked into our third quarter guidance. It's really less of an issue in fourth quarter. It certainly becomes a relatively minor issue after the first half of next year, when we have dramatic increases in Targa processing capacity.

Leo Mariani -- NatAlliance Securities LLC -- Analyst

Okay, that's helpful. Just jumping over to CapEx, trying to get a sense of how much you guys had spent in Q2. Additionally, you guys added $400-500 million to the budget. Is there any high-level way to break that down, just in percentages in terms of how much was cost inflation and how much was new activity?

Timothy L. Dove -- Chief Executive Officer

Yeah. If you look overall at the impacts of the adjustment to the budget, we would calculate that activity is somewhere between 35-40% of the change and cost changes are probably 50-60% of the changes. That's probably the way it breaks down. Second quarter, D&C would be at the current run rate of the 3.3-3.4%.

Leo Mariani -- NatAlliance Securities LLC -- Analyst

Thanks, guys.

Operator

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

David E. Beard -- Coker Palmer International -- Analyst

Good morning. I appreciate the time. A big picture question relative to pricing differentials. You could make the guess that you'd bet on better export pricing when you set up your infrastructure. Do you care to share your thoughts longer term on Brent differentials and/or Midland differentials, just as it relates to how you position the company infrastructure wise?

Timothy L. Dove -- Chief Executive Officer

Yeah, if you look at the long-term, if you have plenty of pipeline capacity to the Gulf Coast and you also have plenty of export capacity to go to world markets, then you should see WTI -- or the Houston market, if you want to call it that -- trading at basically a discount to Brent, which is associated with basically transportation costs to move WTI to foreign markets. In this case, you probably expect it to be $1.50-2.00 off Brent in the longer term without pipeline constraints. To get prices elsewhere, such as Cushing or Midland, at that point you just back off the cost to move the oil. So, if you look at our current costs on FT to move oil from Midland to Midland Tank Farm to the Gulf Coast, at about $2.50 roughly on average.

So, that ought to help you with trying to frame up what the long-term thinking is. Now, we're taking advantage of short-term anomalies and we just happened to have the oil in the right place at the right time. Having it on the Gulf Coast is where the money's being made. And that's the benefit we're seeing today.

David E. Beard -- Coker Palmer International -- Analyst

That's great. Appreciate the clarity. Congratulations on the quarter.

Operator

That concludes today's question-and-answer session. Mr. Time Dove, at this time I will turn the conference back over to you for any additional or closing remarks.

Timothy L. Dove -- Chief Executive Officer

I want to thank everybody for spending time with us and being on the call. I hope the rest of your summer is enjoyable for you. Stay out of the heat, and we'll be seeing you in the fall on the road. Thanks very much.

...

Operator

And that concludes today's conference. Thank you for your participation. You may now disconnect.

Duration: 63 minutes

Call participants:

Neal Shah -- Vice President, Investor Relations

Timothy L. Dove -- Chief Executive Officer

Richard P. Dealy -- Executive Vice President and Chief Financial Officer

JD "Joey" Hall -- Executive Vice President, Permian Operations

Arun Jayaram -- J.P. Morgan Securities LLC -- Analyst

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

John A. Freeman -- Raymond James & Associates, Inc. -- Analyst

Brian Singer -- Goldman Sachs & Co. LLC -- Analyst

Michael A. Hall -- Heikkinen Energy Advisors LLC -- Analyst

Charles A. Meade -- Johnson Rice & Co. LLC -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst

Leo Mariani -- NatAlliance Securities LLC -- Analyst

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

Derrick Whitfield -- Stifel, Nicolaus & Company, Inc. -- Analyst

David E. Beard -- Coker Palmer International -- Analyst

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