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WPX Energy Inc (WPX)
Q3Â 2018 Earnings Conference Call
Nov. 01, 2018, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, ladies and gentlemen, and welcome to the Q3 2018 WPX Energy, Inc. Earnings Conference Call. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference call is being recorded.
I would now like to turn the conference over to your host, Mr. David Sullivan, Director of Investor Relations. Please go ahead.
David Sullivan -- Director of Investor Relations
Thank you. Good morning, everybody. Welcome to the WPX Energy Third Quarter 2018 call. We appreciate your interest in WPX Energy. Rick Muncrief, our CEO; Clay Gaspar, our COO and President; and Kevin Vann, our CFO will review the prepared slide presentation this morning. Along with Rick, Clay and Kevin, other members of the management team are available for questions after the presentation. On our website, wpxenergy.com, you will find today's presentation and the press release that was issued after the market closed yesterday. Also our Q will be filed later today. Please review the forward-looking statement and disclaimer on oil and gas reserves at the end of the presentation. They are important and integral to our remarks, so please review them.
So with that, Rick, I'll turn it over to you.
Richard Muncrief -- Chairman and CEO
Thank you, David, and good morning to everyone on the call. I want to thank you for spending time with us today as I know this is a busy time for everyone who tracks our results. And as always, we're grateful for your interest.
At WPX, our long-term vision remains simple and steadfast. We're staying true to our disciplined capital plan. We're growing margins nicely. We're doing things from a technical standpoint that are cutting edge. Our oil growth is on track. Our outlook for 2019 and beyond is positive and strong. And our focus on generating free cash flow over the next several years is very, very real.
As I've said before, this can be a humbling business. We're obviously affected by the recent pullback in the equity market. And closer to home, we recognize the role we play in driving our own performance. That performance is typically quite robust, 54% oil growth over last year is pretty impressive.
At the same time, we fell slightly short of expectations during the third quarter. That stemmed from a combination of things in September that were both in our control and outside our control. Nonetheless, we own these results. And moving forward, the successful start-up of our joint venture gas plant in the Delaware Basin is exactly the solution we envisioned. You'll hear more details from both Clay and Kevin in a few moments.
Now let's turn to page two. I talk a lot about thinking ahead, executing, and being a technical leader, and for good reason. Every highlight on this slide is a direct result of that. We believe this is truly a competitive advantage for us. We have some of the very best assets and best people in our industry. You can be sure we're going to keep finding ways to continue to optimize the value of our resources.
To borrow a phrase from a book I read, "to whom much is given, much is required," we take that to heart as both a responsibility and an opportunity. There's so much more we can extract from this wonderful portfolio we've built. During the third quarter, the company's Delaware crude oil realizations were extremely strong relative to our competitors. We're pleased with that, but we're not surprised.
I also can't wait for Clay to walk you through some of the details of what we're learning from our advanced technological approaches. Our recent completions in several Third Bone Spring wells and our Pecos State pilot test are some of the newest examples of why our outlook is so incredibly positive. We've also made some smart investments to acquire attractive equity positions in takeaway pipeline systems. Ultimately, we'll see a very nice return on these investments as we monetize them, fueling options to generate even more cash flow growth from our core operations.
Now let's turn to page three. Maybe it's just my competitive nature, but I've been wanting to have this conversation for quite some time, and here's what we're thinking. WPX isn't just a great stock for energy investors, it's a great stock for any investor. It's time to change the expectation for what a competitive energy producer like WPX can accomplish, not just compared to our industry, but against the broader market.
I personally believe we're all punching above our weight. The chart here offers some proof. I know there are several variables and assumptions at play here, but I want you to see what I've seen. WPX has the capacity to deliver growth and a cash flow per share that's triple the projections of other sectors. Let me repeat that. WPX has a capacity to deliver growth in cash flow per share that's triple the projections of other sectors.
We fully expect to double our EBITDA and cash flow from operations over the next two years, based on $65 oil and $3 Henry Hub prices. I think that bears repeating as well. We fully expect to double our EBITDA and cash flow from operations over the next two years based on $65 and $3 Henry Hub prices.
Of course, I'm excited and I'm OK with being labeled as biased, but I hope my confidence speaks loudly about what I see as our place at the table. I fully expect the generalist investor group to begin to take notice. We have a lot of work ahead to make this a reality, but simply put, it's entirely achievable.
I'll turn it over to Clay now to show you what we're doing in real-time to recognize some of our potential. Clay?
Clay Gaspar -- President and Chief Operating Officer
Thank you, Rick, and good morning, everyone. Operationally, we continue to see strong well results in both basins and have never felt better about the quality and the depth of our incredible inventory. Furthermore, our flow assurance in the Delaware Basin has been enhanced by the start-up of our joint venture processing plant in Stateline. I'm also excited to share with you some of the highlights of an incredibly successful data project we conducted on the Pecos State pad.
Before diving into our third quarter operational results, it's worth mentioning that with our processing facility up and running, we've been able to greatly reduce our flaring in the Stateline area, while our gas and NGLs are now at all-time high production rates for the basin.
As Rick said, our business can be humbling, and we certainly had a few of these challenges stack up on us late in the third quarter. Significant third-party processing disruptions tied to a very tight fractionation markets, running parallel with the delayed start-up of our full capacity of the JV plant, and then compounded by weather and electrical disruptions during this critical time hindered our ability to deliver on the full well capabilities to market.
On the last quarter's call, I talked about our excitement around getting our plant up and running. For the last several months, our third-party processors have been squeezing our volumes negatively, impacting our gas and NGLs and indirectly our oil rates as well. In September, we had to resort to storing NGLs rather than selling them, even with third-party plant and full ethane rejection. As a result, we currently have 165,000 barrels of NGLs in storage that we will sell ratably in November, December, and January.
Once again these issues highlight why 18 months ago we chose to create a midstream joint venture to build our own processing facility with ample fractionation capacity and residue gas takeaway to control our own destiny. The good news is that we now have a facility 50% owned by WPX and committed to WPX volumes. The first 200 million cubic feet per day processing train is in service and the plant is now processing about 150 million cubic feet a day and sending 17,000 barrels of NGLs down to Mont Belvieu. Currently we have priority rights under our JV agreement to 27,500 barrels of fractionation capacity at Mont Belvieu, and that will ramp to 52,000 barrels.
Now let's turn to slide five and I'll talk about the Pecos State project. Let me just start by saying Rick and I have been involved with lots of groundbreaking projects over the years, and we're both very cautious about the potential of these projects creeping into the science project for the sake of science rather than sticking to the core objectives that they originally set out to create value. I could not be more proud of our team and how they've focused on solving the most pressing, value-driven objectives.
Back in 2016, we were leading the industry on Delaware Basin multi-zone spacing tests. In early 2017, we brought on the CBR 22, the most advanced and aggressive spacing test in the Delaware Basin. I can tell you we continue to look back and learn from those wells, and we're now approaching two years of production.
As you know, parent-child well relationships are not fully understood until the pad is most of the way through the hyperbolic portion of the decline curve and transitioning into the exponential phase of the decline curve. We continue to watch this high-frequency data very closely and have learned several lessons that impact our development strategy today. For the balance of 2017 and most of '18, we've continued to push frac design, perforation strategy, proppant selection and intensity, and of course, landing strategy relative to geology and the stacking and staggering of other wells.
Earlier this year, our team started to pull together a wish list of things we would love to know about the field, and how we might be able to close that knowledge gap. For those not close to the technical work on an everyday basis, you have to understand that much of what we "know" is really inferred hypotheses extrapolated from measurable characteristics. For normal trials and tests, we are needing to watch production for several months to really understand how the test worked out, resulting in substantial lag time between investment and actual learning.
Let me contrast our experience here at Pecos State. The incredible amount of real-time data that we were able to collect and truly see and hear was happening downhole gave us the confidence to alter our completion designs real-time during the completions. The fiber optics, microseismic, chemical tracers, geophones, external pressure and temperature gauges, as well as the concentration of activity was informative like I've never seen in a project like this before. We watched how changes in design impacted each perforation cluster. We tested where we could get more aggressive on design to enhance recovery, and where we could get more aggressive on cost to ultimately create the most value from the design.
This is truly groundbreaking. In fact, we're changing how we pump our jobs going forward based on these results. We are also reworking agreements with our service companies based on these changes and to benefit from this knowledge arbitrage. In addition, we're flowing these wells -- as we flow these wells back, we will be getting detailed information about how the wells produce over time. This will continue to provide valuable information that we will benefit from for years to come. We also took a core through the best 800 feet of our 9,000-foot hydrocarbon column. We have real-time observations and intel from that core, but the real value will be coming in the months ahead as we do incredibly detailed centimeter by centimeter analysis of that core.
I can anticipate the questions, specifically what did you learn, what are you doing different. As you can imagine, this was an important investment for us. And with what we learned, we think it's very important for us to keep this knowledge tight. Here's what I can tell you. Today, we much better understand the impacts of proppant selection, carrying fluid, how to pump the job, perforation strategy, landing zone, frac dimensions, and vertical and horizontal well spacing implications. In retrospect, it's the list of information that our teams set out to understand when we conceived this test.
Now let's turn to slide six and we'll talk about the Third Bone Spring and other highlights. As I mentioned on previous calls, our primary targets have been the upper and lower Wolfcamp A and the Wolfcamp X/Y. At the same time, we have dedicated the equivalent of one rig to resource delineation. The objective of that rig is to derisk other landing zones and ultimately build more high-return, derisked inventory. I have referred to the Wolfcamp A as our gold standard that all of the other zones are competing with for capital.
As I've hinted at before and now can confirm, the Third Bone Spring is now there. Next we'll start working on spacing tests as we eventually move toward full development mode. The Third Bone Spring wells, highlighted in the upper left box, are recent examples of this delineation work. The CBR 11 has a 60-day average equivalent production of nearly 3,000 BOE per day and the CBR 9 has cumulative equivalent production of 44,000 barrels in 23 days. On the east side of Stateline field, the Lindsay wells continue to look great, as you can see from the highlights in the bottom right box. Our marketing strategy for oil paid dividends in the third quarter. The average realized price for oil for our Delaware barrels, including the Midland basis swaps, was just under WTI. This forward thinking will continue to provide significant value to the corporate bottom line.
Let's turn to slide seven, and I'll discuss our tremendous results in the Williston Basin. For the quarter, Williston continued its long tradition of delivering very strong well results. On our North Sunday Island acreage, the seven-well Hidatsa North pad has 30-day average IP or average production of 2,442 BOEs per day with 80% oil. As I projected on the second quarter call, the Hidatsa North wells came on late in the third quarter, contributed little to the third quarter average volumes, but should be a strong contributor to Williston's fourth quarter oil growth. Our three-well Raptor Pad is our last North Sunday Island pad. Those wells are just cleaning out, and I'm looking forward to sharing those results with you on the next call.
As you can see on the map in the bottom left of this slide, we completed wells across most of our acreage position. Almost all of these wells, the Behr, Grizzly and the Otter Woman are above our type curve with the lower performing wells trending toward our 1 million barrel equivalent type curve. Very exciting stuff.
With that, I'll turn it over to Kevin, our CFO, for the financial update.
J. Kevin Vann -- Executive VP and Chief Financial Officer
Thank you, Clay. It's great to see our joint venture plan up and fully operational. We can already see the effects of that relief as we begin the fourth quarter. Thinking ahead and being in control of our own destiny has really differentiated us over the last several years. Now that we have long-term processing reliability in the Delaware, we will continue to benefit from the investments we have made long into the future.
As expected, our oil growth story continues to mature with oil revenues surpassing $0.5 billion for the first time in our history with this quarter's results. However, WPX is more than just an oil growth story. For the quarter, we are reporting an adjusted net income of $29 million. This marks the second consecutive quarter that we have posted adjusted net income. Although the number isn't wildly impressive yet, it does represent that our return on capital employed is improving.
With the transformation of the portfolio completed earlier this year, the financial impact of the changes take a while to manifest through the financial statements. Last year, during the same call, I made a similar comment. However, the statement was made in regard to our leverage. That seemed to be the overhang to the WPX storyline. Well, we executed on the plan, and now, nobody asks questions about our leverage.
2019 is the year that we see cash flows -- cash flows from operations funding our base capital program. There were skeptics last year when we rolled out our plan to get our leverage down through the drill bit. And there will be skeptics this year on our free cash flow generation. Not only did we hit our leverage goal, we exceeded it. That's what we do at WPX. With the team that we have here and the quality of the Delaware and Williston assets, not to mention our differentiating midstream strategy, I would be careful about the level of skepticism going forward.
Turning to slide nine. As Rick indicated earlier, we have successfully managed the Midland basis differential prior to the widening of it. You can see the results of those efforts in our third quarter financial statements. Despite the temporary issues with transitioning to our processing plant, the risk of gas processing and downstream fractionation have been resolved. Now you will see WPX results continue to bear the fruits of the hard work and foresight our marketing and midstream team had in establishing one of the best positions in the Delaware.
For the quarter, at 83.4 Mbbl per day, our oil production is 54% higher than for the same period of 2017. That growth was driven by our Delaware team as production in that basin grew to nearly 43 Mbbl(ph)of oil per day or an 89% increase since the third quarter of last year. Despite the short-term issues we experienced in the third quarter, that growth over the last year is more than impressive and really exceeds where we expected to be at this point last year.
Our Williston Basin also has contributed to that growth with nearly 41,000 barrels of oil per day in the quarter, which represents a 30% growth from last year. The Williston team has been flexing its muscles, and now we are starting to see the Delaware carry our oil growth profile. This growth in production is driving our cash flows, and our margins continue to increase. These factors are driving our improved capital efficiency and ultimately are leading us to increased financial flexibility in the future.
When comparing to the second quarter of 2018, our oil production was up 3%. As we have mentioned, the timing of the large multiple-well pads in Williston contributed to the relatively small quarter-to-quarter growth. Also the September constraints on processing, coupled with some electrical issues in the Permian, put a slight governor on the third quarter numbers, but has also set us up for an impressive fourth quarter.
At 160 million cubic feet per day, our natural gas production for the third quarter was up 86% versus the same quarter of 2017 and up 5% since the second quarter of this year. Again, the Delaware Basin led the charge on that growth. Our NGL production of 13.7 Mbbl per day was 52% higher than the third quarter of 2017. Although the year-to-date yield(ph)growth was impressive, the 27% decline since the second quarter overshadowed this growth given all the short-term constraints that we've discussed. As Clay mentioned, we will be getting a portion of these barrels back during the fourth and first quarter as we sell them out of inventory.
For the third quarter, we're reporting an adjusted EBITDAX of $288 million, which is $138 million higher than the third quarter of prior year. For us, these results demonstrate the quality of our underlying assets and the execution by the team. We are also reporting an adjusted net income of $29 million versus a net loss of $40 million in '17. Again, this represents the second consecutive quarter where we are reporting an adjusted net income. The improvement was driven by the same factors impacting adjusted EBITDAX: higher oil volumes and better margins on each barrel produced. But there were other non-cash items that impacted the quarter as well.
First, depreciation, depletion, and amortization was $60 million higher this quarter versus 2017 which resulted from higher production volumes. However, our DD&A rate per barrel at $17.01 continues to improve. Last year that rate was $18.72. As I've mentioned the last couple of quarters, these types of results are often subtle in the financial performance, but it reflects that we are drilling better wells at improved cost which leads to higher returns on capital employed. Our capital expenditures incurred for the third quarter totaled $370 million. But of this amount, approximately $17 million relates to land purchases where we were able to acquire some nice acreage in and around our Stateline area of the Delaware.
Turning to slide 10. As I mentioned earlier, we are ahead of our original plan that we laid out over two years ago. Through our efforts to transform the asset mix of WPX, we understood that we had effectively sold assets that generated a lot of cash flow, but we did so to help fund the future development of our remaining two assets in the Delaware and Williston Basins. The WPX team has executed, and now, we are looking forward to 2019 where our base capital plan will be funded by cash flows from operations. Our base plan includes operated and non-operated, drilling completions, and facilities capital, together with up to $100 million in midstream development. And we are guiding to a base capital plan between $1.45 billion and $1.65 billion.
Recognizing that we have been extremely successful in making out-of-the-box investments in midstream opportunities, we will potentially have the chance to make other investments in further midstream development or land additions that might be above our base plan. These investments will only be done to the extent that we monetize some of the historical midstream investments that we made, such as our equity interest in the WhiteWater gas pipeline and the Oryx oil gathering system. To the extent midstream investments are divested in 2019, we anticipate proceeds in excess of our potential discretionary investments. We are guiding to a range of $250 million to $350 million of these types of investments depending on the success of our monetization efforts.
With the base capital plan, we are projecting oil production between 100,000 barrels per day and 105,000 barrels per day and a total equivalent production between 159,000 barrels per day and 171,000 barrels per day. Based on the midpoint of this guidance, our oil production growth will be 28%, natural gas production growth of 35%, and NGL growth of 38%. More important than the production growth, again, this base plan will all be funded within free cash flow.
Last year we talked a lot about our 2018 financial and operational goals. They went hand in hand and continue to do so. I discussed the trajectory of where we were headed. Again, we were growing into our capital structure that we had created by making the transition into the Delaware. Skepticism was there as to whether we would hit our leverage goals. Some investors believed in us and have been rewarded for doing so. Over the next couple of years, we will continue to grow EBITDA and cash flows. We have a trajectory toward free cash flows. I know we can execute, we have executed, and we'll continue to do so.
I will now turn it back to Rick for some closing comments.
Richard Muncrief -- Chairman and CEO
Thank you, Kevin. I'm grateful for our team and how our people at every level are so personally invested. There's a spirit of pride that runs through the entire company, out in the Permian, up in North Dakota, and right here in Tulsa, and that's because we understand that every barrel we produce is part of a bigger picture, and painting that picture is everyone's job here. It's not easy, it's never been easy, and we don't expect it to be, but we're eager to do it.
Now, next year, we'll be talking about six-digit oil volumes as we produce more than 100,000 barrels of oil per day. So I'll close my formal comments back where I started a few moments ago, WPX is on track.
At this time, we can open the line for questions. Operator?
Questions and Answers:
Operator
(Operator Instructions) Our first question comes from the line of Subash Chandra from Guggenheim. Your line is open.
Subash Chandra -- Guggenheim -- Analyst
Yeah, hi. Good morning. Rick, my first question is really a generic one about the industry. I thought I'd ask it because you're a deep thinker on this space, but with all this M&A that's gone on I guess this week, one of the interpretations is that, as sort of the SMid-cap companies delineate and then they get through acreage retention mode, the burdens of pad development require bigger balance sheets in the manufacturing phase. And I'm just curious if that's a thesis you would buy into, or if you had any generic thoughts about the M&A wave we've seen.
Richard Muncrief -- Chairman and CEO
Yes, Subash. That's a great question. I think from our perspective, over time scale will certainly matter. I think every transaction has its own characteristics and it's hard at this point to broad brush everything. But these plays there's probably four, five basins around the country, regardless of commodity mix, where the core really is I think separates itself from the rest of the acreage. And so if you're not in that, then I think you have to be very, very thoughtful about how you can compete. And that balance sheet that you talk about, I mean that's foundational. You have to have a strong balance sheet to be able to execute.
I think there are some other things possibly going on, and that's the discipline that has I think been -- we've all witnessed with our sector and in people being much more thoughtful not taking on debt to grow, not issuing a lot of (inaudible) recently to grow, those sorts of things. I think a lot of -- lot of folks if they're in a position where they can't grow very easily, they have to think about what their strategic alternatives are. In some cases, it is to -- it is to consolidate with others.
Subash Chandra -- Guggenheim -- Analyst
Okay. Thank you. That's good. And just curious about the -- this is a WPX-specific question now. The oil guide that you have out there, out until 2020, I was pleasantly surprised you're holding the rig count flat to deliver the 25% to 30% in '19. I'm curious if the 2020 guide, what sort of step-up in activity, at least rig wise, it has, if any.
Richard Muncrief -- Chairman and CEO
Yeah. We assume that as we get into 2020, probably the start of the year, late '19, early '20, we will be adding probably two rigs to hit that range. And it's all -- in our mind, it's going to be all about living within our means and our cash flows, and that's going to be -- we'll see how that goes with commodity pricing and everything else.
One thing that we're all excited about is, as you'll recall, Subash, we're about 80% hedged this year, about 40% hedged on our volumes for next year, totally unhedged in 2020. And I think that that bodes well and that's real important for us. So we'll see how the -- how commodity prices play out, but we are going to say stay disciplined.
Subash Chandra -- Guggenheim -- Analyst
Great. Can I sneak one more in, just for Clay?
Richard Muncrief -- Chairman and CEO
Sure, go ahead.
Subash Chandra -- Guggenheim -- Analyst
Thanks. Yeah, so the Pecos County, Clay, some of the studies I guess I've seen when published, when folks do fiber-optic and sort of this deep-dive analysis is they sort of see a fracture network develop that they didn't picture from the surface, and it's maybe a level of complexity that they didn't expect or level of complexity they're not sure would even repeat itself acre to acre, that sort of thing. Do you -- is that what you -- it doesn't sound like that's what you experienced, but does that have merit as well?
Clay Gaspar -- President and Chief Operating Officer
Yeah. We definitely watch the swarm -- the fracture swarm, essentially what we think we are stimulating, but we see that lots of places from microseismic. And again, it's -- and it's an inferred measurement. We see -- when we sense these micro-fracture or these microseismic events, we know that that rock has been altered. What we don't know is has it been stimulated, will it contribute to the ultimate production. Contrast to what we did around the fiber-optics and really watching kind of perforation, our perforation understanding, are those getting treated or not, how we try different fluids, we try different concentrations, we try different sands, different perforation strategies. That's really where the magic came together for us, by real-time watching the group of wells that we had that we think is very representative. This is right in the middle of Stateline. This is at the heart of our activity for the next many years. We think this core and these results will be very instructive for us, and we'll be able to extrapolate that to the heart of our field.
Subash Chandra -- Guggenheim -- Analyst
Thanks, guys.
Richard Muncrief -- Chairman and CEO
Subash, let me just interject something real quick. I believe you referred to that as Pecos County, but it's actually the Pecos State is in -- that's in Loving County just to be clear.
Subash Chandra -- Guggenheim -- Analyst
Right. Sorry. Got it.
Richard Muncrief -- Chairman and CEO
Southern end of our Stateline acreage.
Clay Gaspar -- President and Chief Operating Officer
Yeah. The boys in West Texas pronounce it Pecas(ph).
Richard Muncrief -- Chairman and CEO
Pecas(ph).
Clay Gaspar -- President and Chief Operating Officer
They will correct it.
Operator
Our next question comes from the line of Neal Dingmann from SunTrust. Your line is open.
Neal Dingmann -- SunTrust -- Analyst
Morning, guys. Congrats. Rick, I've been waiting to ask you and the team this one from a broad perspective. What are you going to do here mid next year, later next year from a broad sense with all this cash you're going to be kicking off. Well, I'm thinking about return to shareholders, growth, just from a broad perspective. Again, I'm just glad I can ask that question now.
Richard Muncrief -- Chairman and CEO
Yeah. Thanks, Neal. It's something that we have engaged with a lot of our share -- large shareholders with, small shareholders. We try to keep really a good pulse on people who don't own us. And I think that the reason we laid out this discretionary spending plan, if you will, was we were getting a lot of questions along the same line, what are you going to do with the proceeds, this cash. And so I think what we want to do is we want to -- we want to just show the optionality that we have. We have a deep inventory. We have some great opportunities to reinvest in our business. And that's very, very appealing to me.
We also if you -- if you look at some of the estimates that are out there, they probably aren't too far off the mark of what the WhiteWater and the Oryx systems proceeds could potentially be. We're going to have -- we're going to have some cash left over, and I think that's -- that in my mind is what I really like is having that cash on a balance sheet that gives us some optionality to do one of several things. Now the reality is the Oryx II will be probably later in the year. We're going to get a read on what commodity prices do. We're going to get read on what investors' appetites are, but suffice to say, it's going to feel very good to reinvest in our business, entertain the thoughts around a dividend, possibly share buybacks, those sorts of things later in the next year.
Neal Dingmann -- SunTrust -- Analyst
Great color. And then maybe one for Clay here. Just looking, Clay, at that slide 17 on the presentation today where you guys break out. And again, it's never been about lack of locations or inventory with you all. That's for certain. Just my question, though, around that is what's kind of in the assumption as you now are getting full field(ph)development in a lot of your areas in both plays? And as you see spacing going forward, is there potential for even materially more location. So I guess kind of a two-parted there. Just how you potentially see potential upside and maybe just address downspacing in the plays from a broad sense, if you could.
Clay Gaspar -- President and Chief Operating Officer
Sure, Neal. I think you're talking about Delaware.
Neal Dingmann -- SunTrust -- Analyst
Yes, sir.
Clay Gaspar -- President and Chief Operating Officer
Okay, great. Yeah. So as we think about we know we have a tremendous -- we have talked about 6,600 potential locations. Those are -- that's potential. And we get a lot of companies talk about these huge numbers. We're really focused on is kind of drill-ready locations that compete for capital and are risked(ph)fully burden sense(ph), so what would we really put the dollars to. And so what I'm excited about on Third Bone Spring is really it's kind of crossed that threshold from that potential group where we have a high degree of confidence. I think even on the last call I kind of talked about this is something that we see really kind of maturing to now tipping over into really competing in that gold standard at Wolfcamp A, things that we would fund today.
Now there's work to be done. We have single delineations. We don't have answers yet on how we would fully space this out. We don't even have answers on potentially how many landing zones there would be in the Third Bone Spring. And so a natural question is, OK, what -- what's the new inventory, how many wells did you add. I would say it's on the order of hundreds of wells that has probably upside from where we see today as we think about additional landing zones and the spacing tests that will come in time. These are wells that really we want to make sure we have multiple years of high-quality inventory out in ahead of us. And as Rick talked about, we will be adding rigs in the future. We want to make sure that that quality -- high-quality well count inventory is never a burden to our ability to continue to invest back into the business.
Neal Dingmann -- SunTrust -- Analyst
Great. Keep up the great work, guys.
Clay Gaspar -- President and Chief Operating Officer
Thanks, Bill.
Richard Muncrief -- Chairman and CEO
Thanks, Bill.
Operator
Our next question comes from the line is Brad Heffern from RBC Capital Markets. Your line is open
Brad Heffern -- RBC Capital Markets -- Analyst
Hey. Good morning, everyone. Question on the Third Bone, I was wondering how that fits into your thoughts around cube development. I know you've thought historically maybe the X/Y and A are in the same cube. Is the Third Bone in another cube? And then also can you talk about what the spacing test, which spacing that's testing?
Clay Gaspar -- President and Chief Operating Officer
Yeah. Thanks for the question. So we still believe the X/Y, upper and lower A is a flow unit. In some locations the B will be included in that flow unit. We see the Third Bone as a separate flow unit. As I mentioned back to Neal's question, we believe that there will be multiple landing zones. To really get full development mode, we're going to do a few different spacing tests. You can imagine kind of six wells per landing zone, eight wells per landing zone, and see how those shake out, and then also do some vertical spacing tests, how many landing zones is the right ultimate value creation.
So I would say we're still a little early to project that and talk too confidently about that. Just know that that's some of the additional investment that we'll be making, some of the work that we want to do to prepare for full development modes, which I would guess is still 1.5 year, 2.5 years away from us being able to really put the rig count to full development and understanding with how we develop this incredible potential.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Thanks for that. And then shifting over to the Bakken, can you walk through what your exposure is to the local market there, and any thoughts around if we see pipeline expansions or newbuild pipelines coming in in 2019 if that's something that you would commit to, like you have in the Permian?
Clay Gaspar -- President and Chief Operating Officer
Yeah. Happy to do that. Tell you what, I'll let Greg Horne, our Vice President of the Midstream and Marketing answer that. He's probably got a more first-hand view.
Greg Horne -- Director of Midstream Services
Sure. Thanks, Clay. Brad, let me preface the answer to the question by noting first that our marketing strategy in the Williston is really no different than it is in the Permian. We employ a mix of pipeline capacity that we transport barrels on. We've got term sales and then we do have some exposure to the local markets.
So it's probably worth, at the risk of sounding like a broken record from maybe a lot of the other the Bakken calls this week. It's worth noting again that there is heavy seasonal refinery maintenance right now and the pad to the Midwest refinery complex anywhere from about 800,000 to 1 million barrels is offline. If you kind of compare that to where we've been over the last couple of years, last year around this timeframe is about an 89% utilization. Two years ago it was almost 92%. So we're currently right around 75%. So pretty historic numbers for a turnaround activity.
Maybe to answer your second question first, then I'll get back to our exposure. In terms of supply and demand balance in the Bakken, pipe outlets are around 1.3 million barrels a day. We've seen rail around 300,000 barrels a day here just recently. That's probably up from about 150,000 barrels a day a year ago. So you combine that with production that's kind of bouncing around, getting close to that 1.3 million barrel a day number. It says that there's plenty of capacity to get the barrels out. So it's really kind of a demand issue and it's a seasonal demand issue. And the crack spreads certainly tell the refiners to run all-out when they can.
So getting back to your base question of what's our exposure, we move about 15,000 to 17,000 barrels a day down to Cushing on pipe capacity that we own. We've got about another 20,000 close to it barrels a day -- I'm using gross numbers -- we use those in marketing because we're responsible for marketing all the barrels -- move about 20,000 a day on term sales that are linked to WTI.
So that kind of leaves you with a balance which is right around 20,000 a day that achieves, what we call, a Bakken-DAPL index, which looks more like a local index, can kind of trade pretty close to Clearbrook at times. Interestingly enough, physically we can only move 4,000 barrels a day to Clearbrook through capacity that we lease. But that doesn't mean that other barrels -- that other 20,000 don't get some exposure.
So all in all, it's about -- 40% of our Bakken portfolio is a local index, which about 20% of WPX as a whole.
Clay Gaspar -- President and Chief Operating Officer
And it should be noted that not too long ago that was actually a premium. Yeah.
Greg Horne -- Director of Midstream Services
Yeah. I mean in summer you saw Clearbrook trade at a premium. We've been talking to folks that have worked with refineries who are now at other producer spots and marketing spots up in North Dakota, and they feel pretty good about Clearbrook here in a couple of months. So we'll work through it here the balance of the year, but we're not scared of kind of where the differential is today.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Appreciate all the color. Thanks.
Operator
Our next question comes from the line of Michael Glick from JPMorgan. Your line's open.
Michael Glick -- JP Morgan -- Analyst
Just one question on discretionary CapEx. I mean I know a lot depends on the timing of a potential Midstream sale, but have you run any scenarios on how rig adds could impact growth in 2019?
J. Kevin Vann -- Executive VP and Chief Financial Officer
Yeah. And Michael, this is Kevin. And really when you think about rig adds next year, given that that discretionary capital is contingent upon us getting through some of these monetizations, I would anticipate if we were going to do -- if we were going to add a rig or two next year, it would be during the last half of the year, if not the last quarter of the year, and it wouldn't really generate a whole lot of additional EBITDA and cash flows for next year. Maybe put a little bit of capital for the back half of the year but not a whole lot for next year.
Michael Glick -- JP Morgan -- Analyst
Okay. And I guess just last one, in the Williston, could you maybe talk about how the geology changes moving from North Sunday Island south across your acreage?
Clay Gaspar -- President and Chief Operating Officer
Sure. Happy to do that, Michael. This is Clay. We tested -- we talked about the results of the Otter Woman which was really exceptional results. You can see on the map, it's a little further south than North Sunday Island. So I think that's kind of indicative of kind of that a large percentage of our remaining inventory. Right now we've just started flowing back the Howling Wolf wells. That is really our southernmost test that will test kind of the furthest extreme.
There's no question. As you move south, it gets a little thinner, the geology is not nearly as hard as the North Sunday Island is. We try to be abundantly transparent on the exceptional nature of North Sunday Island. But if the Otter Woman and the early results of the Howling Wolf are indicative of the balance of the inventory, or a substantial proportion of the balance of the inventory, we're really excited about that. And I think that's what we were trying to show with my last slide for today. So more information coming next quarter on Howling Wolf, but really excited about the -- what we're seeing so far.
Michael Glick -- JP Morgan -- Analyst
And then if I could sneak one more in. I mean just any plans on some of your non-op kind of Northern Delaware acreage regarding divesting those or trading those?
Richard Muncrief -- Chairman and CEO
I would say right now we're probably more inclined to trade those into closer to some more our core positions. That's probably a preference right now.
Michael Glick -- JP Morgan -- Analyst
Got it. All right, thanks, guys.
Richard Muncrief -- Chairman and CEO
Thank you, Michael.
Operator
Our next question comes from the line of (inaudible) Securities.
Analyst -- -- Analyst
Hey, guys. I was hoping to kind of follow up on the -- basically the recent sort of deep-dive microseismic work that you did. You talked about making some adjustments. I know there was obviously some industry secrets and things like that involved here. But just high-level, what can you kind of tell us in terms of how you've sort of made these changes here. I mean is it really more of a cost saving thing? Is it more of a well performance thing? What can you kind of tell us sort of toggling between those two variables there?
Clay Gaspar -- President and Chief Operating Officer
Both components, as I mentioned on my prepared remarks, we were really making adjustments to see how far can we push this to enhance well performance. In the same time maybe we push the other direction, save some money, and not impact production performance. And so we toggled some or(ph)both. I would say some of the things we were looking at different types of proppants, different sizes of proppants, different sources of proppants, the carrying fluid, how the proppant loading 0.5 pound per gallon, 1.5 pound per gallon, what does that really look like, how does that affect the perforation clusters.
And so as you can imagine, you can pump a lot of sand away, but if you don't get it into all of the perforations, you're leaving significant resource behind. So that's kind of the secret sauce is figuring out what's the right recipe so that we are continuously and smoothly stimulating that whole wellbore. And so having the fiber-optics and being able to watch and listen every single perforation cluster along the way gave us incredible insight, and having multiple wells, multiple swings at this, we could try different perforation strategy. We could try different hole sizes. We could do cluster to cluster lengths. Wow many clusters in a stage? There's a number of things that we tried real-time. We would learn something and say, OK, well if that worked, let's try this. And so that was kind of the nature of what we've been doing really for the last six weeks on this location.
Richard Muncrief -- Chairman and CEO
I'll also interject that I've never seen a project -- I've been involved in several microseismic projects across the country. I've never seen anything that showed the real-time results that we have. And that's why hopefully you'll pick up on Clay's excitement and our excitement about that -- about that knowledge and what it could potentially mean for enhanced recoveries going down the road.
Analyst -- -- Analyst
Okay. That's helpful. And I guess maybe just jumping over to the Bakken here. Obviously I guess it's no secret that you guys are sort of depleting your North Sunday Island inventory here in the fourth quarter. So just wanted to get a sense of how that impacts sort of the production growth as we work our way into 2019 in the Williston. Is that going to start to sort of slow the growth down as you move to some of these other areas? I mean how should we think about that?
Richard Muncrief -- Chairman and CEO
So, our base plan is three rigs running in the Williston and our base plan is still nice growth year-over-year from '18 to '19 for the Williston. Now, as you mentioned, we don't have a 27 more North Sunday Island wells to roll in. And so we have to overcome the decline of these really world-class wells, that's part of it. But we really believe that the inventory that we have wells like the -- that we'll be drilling throughout '19, will not only compensate for that base decline. But also continue to provide growth, as I said, year-over-year.
Analyst -- -- Analyst
Okay, thanks a lot guys.
Richard Muncrief -- Chairman and CEO
Thank you, sir.
Operator
Our next question comes from the line Jeff Grampp from Northland Capital Markets. Your line is open.
Jeff Grampp -- Northland Capital Markets -- Analyst
Good morning, guys. Staying up in the Williston, I know in the past you guys were a little bit hesitant to adjust your type curve given that a lot of the outperformance was from North Sunday Island. But given even the non-North Sunday Island wells are still comparing nicely to the curve, was just hoping to get your updated thoughts on any potential changes to the type curve that you guys might be making as we get into yearend here.
Clay Gaspar -- President and Chief Operating Officer
I think it's a very fair question. As you pointed out, as we're looking at the North Sunday Island wells, we didn't want to move the curve up to that and mislead our belief that the balance of the inventory would look like North Sunday Island. Now, as we gain more swings of the bat down in the southern part of our acreage, with continued performance like this, it does put pressure on us to move the curves up. Give us another quarter, let's take a good look at it, I don't know if we'll have enough information from the most southern test, but I think once we get our arms around that, I think we'll be able to better represent at least the next few years of drilling and our expectations there.
Richard Muncrief -- Chairman and CEO
I'll also interject that there are two other operators, one privately held and then Exxon actually is just to the east of us. Both of which -- both of those companies have a fair amount of activity adjacent to us. So in addition to what Clay -- what he's talking about, we're going to have more data coming in that would support moving that type curve or not moving it, yeah.
Clay Gaspar -- President and Chief Operating Officer
Yeah. Excellent.
Jeff Grampp -- Northland Capital Markets -- Analyst
All right. Great. That's helpful color. And can you guys talk about -- I know with the JV gas plant online, that reduces the reliance on third parties here. But going forward, is there really any reliance from your operated volumes in the Delaware on third-party processing or is it pretty much all on the JV system now?
Clay Gaspar -- President and Chief Operating Officer
Yeah. We always -- we love to have interconnects. We have a myriad of agreements in place so we can take offload gas, we can offload our gas. We do have probably 10% or so of our gas, just depending on where it's at, going to other processors. So there's always an exposure in the background. But I can tell you, the big deal for us, the amount of gas that we have today going through the Stateline facilities and the additional gas that we're piping in that direction gives us great control and really reliability of understanding that market.
Jeff Grampp -- Northland Capital Markets -- Analyst
All right. Appreciate the time, guys. Thank you.
Operator
Our next question comes from the line Derrick Whitfield from Stifel. Your line is open.
Derrick Whitfield -- Stifel -- Analyst
Good morning all.
Richard Muncrief -- Chairman and CEO
Morning.
Derrick Whitfield -- Stifel -- Analyst
Perhaps for Clay. Referencing your technical and analytical work on page five, what are your views on timing and sequencing impacts as it relates to full field development? I assume pressure cells(ph)define the units. But how do you sequence it beyond that?
Clay Gaspar -- President and Chief Operating Officer
If I understand the question, are we going to alter our -- essentially the number of wells we're putting on a pad, is that kind of in the right ballpark?
Derrick Whitfield -- Stifel -- Analyst
It is, Clay. And then also which -- in which order the zones are completed.
Clay Gaspar -- President and Chief Operating Officer
Yeah. So one of the earlier callers asked about kind of our flow units and how we're grouping these wells. This is an important lesson. I talked about the CBR 22 pad that we brought on early '17. That was an area that we learned it's not just Wolfcamp A, upper and lower that's in communication. That X/Y is really part of that flow package. So that was an important lesson we learned two years ago. And we've rolled that in as part of that flow unit.
So I still believe the X/Y, upper A, lower A is one flow unit. Where we're landing this Third Bone Spring this particular zone, I think is outside of that flow unit. We have pretty good bit of confidence, but we'll continue to test that theory. We'll also land in different zones, really understand horizontal spacing, vertical spacing, and really how that comes together.
So, I would say, foreseeable future, 2019, maybe even into '20, expect us to really continue to plow ahead on that upper, lower, Wolfcamp A, X/Y flow unit. And as I said, in some areas that Wolfcamp B is part of that as well. So that's going to be a predominant part of our development. As we continue to learn about the Third Bone Spring, the ultimate development cadence and style, that'll fold into the mix as well just giving us that significant amounts of more high-quality, derisked, ready-for-the-bit inventory.
Derrick Whitfield -- Stifel -- Analyst
Great. And then as my follow-up, could you confirm that the strong increase in implied Q4 gas and NGL volumes that's simply just a function of increased gas processing?
Richard Muncrief -- Chairman and CEO
That's correct.
Derrick Whitfield -- Stifel -- Analyst
Thanks. Thanks for your time, guys.
Richard Muncrief -- Chairman and CEO
Thank you.
Operator
Our next question comes from the line of Kashy Harrison from Simmons Energy. Your line is open.
Kashy Harrison -- Simmons Energy -- Analyst
Good morning, everyone, and thanks for taking my question. So the first one for me, for Rick or Kevin, it looks like your base case 2019 outlook is incorporating call it $65 WTI. I was just wondering if you could discuss how your plans would evolve if oil prices went to $55 or if they went to $75. Just some thoughts on how your plans would evolve with the commodity prices.
J. Kevin Vann -- Executive VP and Chief Financial Officer
I think we've run scenarios, obviously, as most companies do. If you were to see a $10 or a $15 reduction in commodity prices next year, I don't think it's going to really change our 2019 drilling program. I think the real question there would be what the forward curve does past 2019 as we think about investments in '19.
And I think if you see commodity prices run to $75 or above, that's obviously going to generate quite a bit more free cash flow. And if that were to happen, I think we would just go back and look at some of those discretionary investments that we talked about, those opportunities, and we would evaluate them. But we wouldn't necessarily just immediately add rigs because we're starting to realize in $75 oil. And that goes back to the question, what's that forward curve doing, and what -- because most of your investment return really is going to come 12 to 18 months after that initial hole is drilled and investment is made.
Kashy Harrison -- Simmons Energy -- Analyst
Got you. Got you. And then second one for me, just one for Clay. Appreciated the color on some of the challenges associated with the third-party during 3Q. I was just wondering if you have any bigger picture views on fractionation capacity in Texas, how you see that trending over the next several years, and how you've positioned yourself to perform in that environment.
Clay Gaspar -- President and Chief Operating Officer
I'll take a stab at it, then I'll ask Greg Horne if he has -- if he wants to add any color. I think fractionation, we are not out of the woods yet. I think there's still a lot of pressure on the industry. We were very proud to talk about our 27,500 barrels a day of capacity moving to 52,000 barrels. We think that's very important. It is way in the money as you start looking at essentially if you want to contract something like that today. And as you know, the market is very tight. So first thing has to happen is that additional capacity has to come online.
There's projects in the works. We're very tied into that. We understand that very much firsthand. We watch that really closely. Real happy with where we're at. Real happy to have our plant online so we can actually use this capacity. Beyond that, I think at some point the market ultimately balances.
Greg, other comments?
Greg Horne -- Director of Midstream Services
I think that's a pretty comprehensive look at it. Good morning, Kashy. I think that we being not out of the woods yet is the industry collectively.
Clay Gaspar -- President and Chief Operating Officer
Yes, correct.
Greg Horne -- Director of Midstream Services
I think WPX is in a really good position with the contracts we've got. So it seems like every week we're reading about new fractionation that is being board-approved(ph)by various midstreamers. I think the Enterprise announced another one again yesterday. So, I feel like from an industry perspective, it's going to get there by 2020, but '19 will be interesting for the industry but, again, our position is really good.
Kashy Harrison -- Simmons Energy -- Analyst
All right. That was it for me. Thanks for taking my questions.
Clay Gaspar -- President and Chief Operating Officer
Thank you.
Operator
Our next question comes from the line of Nitin Kumar from Wells Fargo. Your line is open.
Nitin Kumar -- Wells Fargo -- Analyst
Good morning, guys. How are you? Just a quick question on the service cost side of things. As you have put this plan together, you're keeping the rig count flat, what are the puts and takes in the field especially in the Permian in terms of service cost?
Clay Gaspar -- President and Chief Operating Officer
Yeah. So I'm glad you brought up the capital because this really didn't come across in the prepared remarks or slides. We talk about seven rigs this year, seven rigs next year. It looks very flat. When you really dive into the month-by-month analysis, we actually started the year in Permian with five rigs, two rigs in Williston, and then we ramped to the three and seven. So we'll continue that. And again, rough numbers, very flat for '19, but obviously '19 is a full year of three and seven. So there's a little bit of cost delta between the two years that you really have to kind of dive in a couple layers under to look into.
The second piece is we did -- we brought in some additional inflation into the mix, about a 5%, 7% number across the board. If you looked at it today, I would probably say we're a little bit on the conservative side there. Some of the negotiations we're having, the conversations we're having with some of our service providers, we feel pretty good about beating what we have in the system. So we'll see how that plays out.
I can tell you, the last 18 months have been pretty tough inflationary-wise around the industry. We fought a good fight. We have great service company providers that have been good partners through the whole deal. We continue to always look for those opportunities to high grade and align with the hungriest, best opportunities out there, but we'll see for 2019. So far, I feel really good about what we have in and us being able to achieve or beat those numbers.
Nitin Kumar -- Wells Fargo -- Analyst
Great. Thank you. And just, Rick, you made a comment you'll be producing six figures of oil next year. You also commented in your release that you had 90,000 barrels in October, if I'm right. So how quickly do you get to that 100,000 barrels? And maybe I'm just trying to get to what is the trajectory of that growth in '19? You're not constrained for any pipelines or anything like that. So just trying to understand, how should we think about the year as it goes along?
Richard Muncrief -- Chairman and CEO
It looks like to me, the way we have it modeled out, it's going to be pretty uniform up and to the right, a pretty nice growth trajectory. And so, we'll have nice exit volume next year if you look at the range that we laid out, 25% to 30% year-over-year growth. But it's going to be I think fairly -- a pretty smooth flow, not real lumpy.
Nitin Kumar -- Wells Fargo -- Analyst
Great. Thank you. I'll leave it there.
Richard Muncrief -- Chairman and CEO
Thank you.
Operator
Our next question comes from the line of Betty Jiang from Credit Suisse. Your line is open.
Betty Jiang -- Credit Suisse -- Analyst
Thanks for the market color earlier on the fractionation capacity. Can we just get some color on what were the chain of events that actually happened with your third-party processor that resulted in the shut-ins or the increased flaring? Like how much notice did you have before you saw the production impact?
Clay Gaspar -- President and Chief Operating Officer
Yeah. Happy to provide a little color on that. So we had interruptible space. So we had -- I think some people would say, OK, we have our processing box checked. In reality, it was interruptible. So you don't have a guarantee of space. Even with that guarantee, if it was firm, what some of the plants are experiencing today is they cannot get the NGLs out to the fractionation plants, the facilities. And so the whole plant ratably gets pulled back and everyone receives equal share even if you do have fractionation -- excuse me, firm transportation associated with that plant.
So we were kind of little guys on the market. We were always the ones for last I would say easily six months, probably longer than that. There was a disruption in the plant, if there was something tightening in the market, we were the first ones to get kicked off. So you can imagine, that's very rough on our operations. You're constantly bringing wells up and back. You've got great new wells coming online. They're constrained by one piece of capacity or another.
So that's why even on the last call I talked about a significant change to our operations, not just on gas and NGLs, but oil as well, us being able to really take out some of the constraints throughout the system that we can't even see and really appreciate today. Let me tell you, some of those projects are well under way. So really excited about that.
I think specifically to this disruption in September, we were rocking along. Last quarter I talked about our plant coming online. We started bringing gas to the plant very end of August. We had some debugging and some bottlenecking to do inside the walls of the plant itself. That took a little bit longer than I think we would have all hoped, and it really wasn't until the end of September that we really had things up to where we wanted.
Now during that critical month of September, if our third-party processor could have taken our capacity, you really wouldn't have seen a noticeable change, it would've been a non-event. So what's happening is we're kind of bottom line or bottom end of the folks that they want to serve, because we had very inexpensive interruptible fees, and then the whole market started seeing this fractionation constraint. This plant was particularly hit. They had a pullback on constraints, affecting us differentially because we were interruptible. Our marketing team went to the market and did a great job of doing some trades kind of around the country to figure out how can we get these NGLs to storage and not have to flare them.
So the processor told us, hey guys, we can take your gas, but we can't exit -- we can't get rid of the NGLs, so everybody is coming down. We said, look, what if we have a home for the NGLs? They said, fine, you figure that out, we could take your gas. So that's why we ended up with this gas in storage.
I can tell you, it was so much better than having to flare the gas, but even the results we saw today, obviously we're real frustrated with, because just the timing of our plant and the timing of this disruption were just weeks of overlap, this would have been a grand-slam quarter for us and we would have all started these questions with congratulations, Rick, good job on the quarter, instead of, hey, let me go to my question. Hope that answers your question.
Betty Jiang -- Credit Suisse -- Analyst
Yeah. No, thank you so much for that great color. And then my follow-up will be, would you be able to accommodate third-party volumes on the (inaudible) gas processing system? And if so, how should we be thinking about the cash flow impact -- cash flow benefit to WPX?
Clay Gaspar -- President and Chief Operating Officer
Yeah. Great question. I mentioned earlier about all of the offloads. This is the mark of a great system that we can offload our gas if we have any disruptions, they can offload their gas, others can. And so we expect to fill this plant in very short order with -- at interruptible service, as I mentioned, that we had before. Our second plant, we expect to come on second quarter. I can tell you we have big plans for that second quarter plant as well.
I won't get into the details of the cash flow projections associated with the joint venture. But just know that we have those modeled in and we feel really good about the operations, really excited that we had the foresight a year-and-a-half ago to think through some of these opportunities. And I really see this as a significant opportunity for WPX shareholders to continue to benefit.
Betty Jiang -- Credit Suisse -- Analyst
Great. Thank you.
Operator
Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your line is open.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Good morning. Thanks for getting me in. And since you're feeling deprived of brags, I'm going to tell you that I really appreciate the way you got this 2019 base guidance out for this call. It's really helpful.
Richard Muncrief -- Chairman and CEO
Thank you, Jeff.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Since you declared it to be commercial, when are you prepared to put a preliminary number on the inventory increase from the Third Bone Spring success?
Clay Gaspar -- President and Chief Operating Officer
Yeah. I would say it's -- we're still a little bit out. The first question is the spacing test and then the second question is number of landing zones. I can tell you, during 2019 we'll be testing both of those questions. Sometimes the answer comes really quick. It becomes clear very quickly, I should say. Other times, you just need a few more swings of the bat. So it's hard to say. Maybe a year from now I'll feel really good about it. It might take a year-and-a-half or two years before we're really able to say, OK, consider half of our rig count or some significant portion of our rig count plowing down the inventory as we are in the Wolfcamp A. But the good news is, we have plenty of Wolfcamp A to keep us plenty busy.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay. That's fair. Slide nine, the Pecos test slide. It looks like it shows that you had tests in the X/Y, the upper and the lower Wolfcamp A. I was just wondering, is this project completed and that's all you're testing or are you going to test any other zones in the pilot?
Clay Gaspar -- President and Chief Operating Officer
Yeah. You can only take so big a bite. That's the critical zones. Again, that's our bread and butter, the gold standard, what we really wanted to understand. And so you're right. X/Y, upper A, lower A, that was the focus of the test. Spacing, staggering, as I said, so much about the intricacies of how we pump the stimulation, that's really what we wanted to know. But yes, it was focused on that portion of the hydrocarbon column. Now, the core goes all the way from the Third Bone all the way down into the Wolfcamp B. And so we'll gain much more understanding from the core analysis, the petrophysics larger than just this targeted interval.
Richard Muncrief -- Chairman and CEO
One of the things we'll do is we'll compare and contrast this with some of the other projects we've been evolved with, take some of our lessons learned. And then I would not be surprised if we don't start contemplating doing a similar test in the Third Bone. Clay had mentioned we had several potential landing zones, and we're real excited about that. And so we just have to balance that with capital discipline, because these projects are not cheap. And so stay tuned. We're real excited about what we're seeing.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
And with that you've actually kind of anticipated something I was going to ask as a follow-up which was, is this pilot and the success of the pilot, is it a template for what you might potentially do for something like Third Bone Spring? And you mentioned cost, I'm wondering if it might be even -- I mean, since you've lifted this one and everything went well that you might even be able to do it even a little bit more efficiently the next time.
Clay Gaspar -- President and Chief Operating Officer
Yeah. I would say, this is not the last significant data gathering project we do. I'll just go back to my prepared remarks, know that we're going to be very disciplined and challenging the team with how do we create value from this investment. As we would with any other investment we make, be it midstream, be it G&A, LOE, these all -- every one of these dollars have to create value. What I'm so excited about and the reason we put out a dedicated slide on it is, this is some of the best return investment dollars that we've spent in a very long time.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay. I appreciate it.
Richard Muncrief -- Chairman and CEO
I'll interject one -- one additional thought, and that is, one of the -- the funnest part of our business is exploration. And when you can explore like we're doing here on existing acreage and it's almost a guaranteed positive rate of return, that is a good deal. And I'm convinced over time that this Third Bone is going to be a big, big deal for us.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Right. And if I could sneak one real quick last in. You mentioned earlier in the call, I think, Kevin, did about some acquisitions in Stateline. I was just wondering, are you still able to acquire additional acreage or is this more like picking up increased working interests or royalties or something like that?
Clay Gaspar -- President and Chief Operating Officer
Jeff, you've heard me brag about the land team on a few calls that I would say are specifically around Stateline. That's where we are really seeing the benefit both in the Bone Spring zone, which we haven't talked about a whole lot historically. These are all set up for 2 mile laterals. When we get to that plowing of the ground, harvest mode for the Bone Spring, know that it will be essentially all 2 mile laterals set up for long lateral development. We'll have the great benefit of infrastructure, that's really already built from the Wolfcamp A. Think of our infrastructure from the midstream as this JV that we've been so excited about today. All of this essentially is kind of free entry cost as this second round of development comes through. So, back to the acquisitions, I don't expect that we have a whole lot of kind of dollars out the door acquisitions in and around Stateline, but we continue to make really good progress with these mutually beneficial trades that we see with a lot of our great neighbors that we have in that great neighborhood.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay. Great. No, I appreciate that. Well, thanks. Thanks very much, and look forward to particularly those results in the Southern Bakken.
Clay Gaspar -- President and Chief Operating Officer
Yeah. We do too.
Richard Muncrief -- Chairman and CEO
Thank you.
Operator
Our next question comes from the line of Brent Koaches from Raymond James. Your line is open.
Brent Koaches -- Raymond James -- Analyst
Good morning. Thanks for taking my question. Just wanted to clarify, on the discretionary investments, are those contingent on selling both of the midstream assets you mentioned or will you kind of adjust that on the fly?
J. Kevin Vann -- Executive VP and Chief Financial Officer
This is Kevin. We'll continue to adjust that based upon the success. And it's really not just those two investments. I think if you look across our midstream portfolio, yeah, those are two obvious candidates for divestiture and monetization and seeing some pretty significant proceeds come in from those next year, but we've got other opportunities, other midstream investments that give us kind of some flexibility with how much we do with discretionary investments and then also how much additional cash flows we create through those processes.
Brent Koaches -- Raymond James -- Analyst
Okay. And I know you said you're looking at the two-rig addition probably in the second half of the year, but with some of the other potential projects, is there any -- like, what's the priority list as far as discretionary investments go? Is it midstream, is it acquisitions or just kind of how you're thinking about that?
J. Kevin Vann -- Executive VP and Chief Financial Officer
I would like to say that we're pretty agnostic to the discretionary investments. I mean, if you look at what our midstream and marketing team has done, there's some pretty amazing multiples that we anticipate to realize on the invested capital that we've got in some of these projects. At the same time, we understand that our core business is upstream, and we'd like to create a little momentum going -- a little more momentum going into 2020, but that will depend on, as I said earlier, a number of other factors including what commodity prices and -- are looking like in the back half of '19, going into '20, as well as just the status of these opportunities.
Brent Koaches -- Raymond James -- Analyst
Very good. Thanks very much.
Richard Muncrief -- Chairman and CEO
Thank you.
Operator
We have no further question at this time. I will now turn the call over back to Mr. Rick Muncrief, our CEO, for his closing remarks.
Richard Muncrief -- Chairman and CEO
Well, thank you very much for your time today. I know we went a little long. Thanks for staying with us. We do appreciate all the interest, the enthusiasm about our story. And feel free to reach out to us if we can help in any way. Take care. Have a great day.
Operator
Ladies and gentlemen, this concludes our conference for today. Thank you for your participation. Have a wonderful day. You may disconnect.
Duration: 73 minutes
Call participants:
David Sullivan -- Director of Investor Relations
Richard Muncrief -- Chairman and CEO
Clay Gaspar -- President and Chief Operating Officer
J. Kevin Vann -- Executive VP and Chief Financial Officer
Subash Chandra -- Guggenheim -- Analyst
Neal Dingmann -- SunTrust -- Analyst
Brad Heffern -- RBC Capital Markets -- Analyst
Greg Horne -- Director of Midstream Services
Michael Glick -- JP Morgan -- Analyst
Analyst -- -- Analyst
Jeff Grampp -- Northland Capital Markets -- Analyst
Derrick Whitfield -- Stifel -- Analyst
Kashy Harrison -- Simmons Energy -- Analyst
Nitin Kumar -- Wells Fargo -- Analyst
Betty Jiang -- Credit Suisse -- Analyst
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Brent Koaches -- Raymond James -- Analyst
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