WPX Energy, Inc. (NYSE:WPX) Q3 2019 Earnings Conference Call October 31, 2019 10:00 AM ET
David Sullivan - Manager, IR
Richard Muncrief - CEO & Chairman
Clay Gaspar - President & COO
Kevin Vann - EVP & CFO
Conference Call Participants
Derrick Whitfield - Stifel, Nicolaus & Company
Brian Downey - Citigroup
William Thompson - Barclays Bank
Joshua Silverstein - Wolfe Research
Gabriel Daoud - Cowen and Company
Neal Dingmann - SunTrust Robinson Humphrey
Leo Mariani - KeyBanc Capital Markets
Subhasish Chandra - Guggenheim Securities
Kashy Harrison - Simmons & Company International
Biju Perincheril - Susquehanna Financial Group
Jeffrey Grampp - Northland Capital Markets
Brian Singer - Goldman Sachs Group
Good morning, ladies and gentlemen, and welcome to the Q3 2019 WPX Energy, Inc. Earnings Call. [Operator Instructions]. As a reminder, this conference may be recorded. I would now like to turn the conference over to your host, Mr. David Sullivan, the Director of Investor Relations. Sir, please go ahead.
Thank you. Good morning to everybody. Welcome to WPX Energy Third Quarter '19 Call. We appreciate your interest in WPX Energy. Rick Muncrief, our CEO; Clay Gaspar, our COO; and Kevin Vann and, 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 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're important and integral to our remarks, so please review them. So with that, Rick, I'll turn it over to you.
Thank you, David, and thanks to each of you who're joining us this morning on the webcast. Today, we're going to recap another strong quarter here at WPX, we'll give you an update on the fourth quarter and show you where we plan to be five years from now. Our third quarter results were strong and compelling backed by consistent execution on our great assets by smart, capable and focused team.
Up in Williston Basin, we're now approaching 2,000 consecutive days without an employee lost time accident, that's almost 5.5 years. I can tell you our team across the company takes tremendous pride in this.
Out in the Permian, we continue to cut our flaring rates even further. As a matter of fact, last week it was down to just 1.5%. That's incredible progress, and it shows up in the growth for physical gas volumes. We also align our people practices to recognize and retain our talent.
On November 11th, for the 2nd straight year, we're giving our employees who served our country in the armed forces a day off with pay for Veterans Day.
So thank you to everyone here at WPX who served our country as well as many of you who are on this call. Let's turn to Page 2 and recap the great third quarter. One of the things you all know about WPX is that we walk the talk. We outline what we're going to do then we do it. We said we'd generate free cash flow in the second half of the year, we're doing exactly that, starting with $42 million in the third quarter. We continue to believe that figure will rise to approximately $100 million, even with lower commodity prices.
For the third quarter, our capital expenditures were $264 million, right in line with our plan. We also tightened the range for the full year, keeping the midpoint exactly where it was. We're also getting more production from the same dollar. Last quarter, we raised our full year oil outlook by 4%, and now we're doing it again for the fourth quarter expecting yet another 4% bump.
That will push us past our exit rate projections for the year. As you recall, we originally forecasted and estimated 5% to 10% exit rate growth from year-end 2019. Now it looks more like 15%. This is good news for now and for later as we enter 2020 with more momentum than we expected. More importantly, we can generate free cash flow next year at $50 WTI and $2.50 NYMEX.
Let's turn to Page 3. Here is a picture of the actions we're taking to benefit our shareholders. We foreshadowed this in February, we've got a great amount of detail simply to give ourselves some flexibilities to see how opportunities in the market unfolded. When they did, we acted. And now you can see the details in full color.
So far this year, we paid down nearly $300 million of debt, bought back nearly $60 million worth of our shares, reshaped our debt towers to save roughly $4 million per year in interest and are now generating sustainable free cash flow. So when we say WPX has never been positioned financially or strategically, our actions bear proof. This is the power of having a world-class portfolio in the two best oil-producing basins in the Lower 48, coupled with our consistent execution. We're methodical, decisive and tenacious in our execution.
Now let's turn to Page 4. We realized that everyone's interested in our 2020 plan and we'll announce these details in the next couple of months. Today, however, we want to go a step further and take you behind the scenes to see the plans for the future that we have at WPX. Five years ago, we laid out a vision for his company to work toward by the year 2020. We exceeded most of what we wanted to do even when commodity prices collapsed to lower than 50% to where they were in 2014.
Now as we look at the most important metrics that will drive investor interest over the next 5 years, we think what you see in front of you allows us to compete against any sector, not just energy. This includes implementing a meaningful dividend, targeting 7% to 10% free cash flow yield and driving our debt-to-EBITDA leverage metric from where it stands today at about 1.5 turns down to approximately 1.0. This is, in very precise and defined terms, our game plan for creating additional shareholder value. Not only is this important to communicate externally, but also internally as well. We want our entire organization to know we have a well thought out plan and we'll work diligently over the next several years towards these goals. This is how we're going to assess our performance. It's a very targeted and attractive byproduct of how we plan to successfully manage our portfolio.
Can we do it? I believe so. Absolutely. It will depend on consistent execution, strong capital efficiency and remaining opportunistic. We've established a track record of doing very well in each of these areas over the last several years. Now let's turn to Page 5, and I'll hand it now over to our President and Chief Operating Officer, Clay Gaspar.
Thank you, Rick. And good morning, everyone. This quarter is a major milestone for WPX. Over the last five years, we've made some bold moves, weathered some really tough macro conditions, and today sit healthier than ever with an incredible outlook.
I would like to personally thank all of our stakeholders, including our investors, vendors, landowners, partners and especially our employees who have taken this incredible ride with us. In a few minutes, you'll hear Kevin talk about the great financial results for this quarter, including the much-anticipated free cash flow numbers. But even more important than how we've gotten here, or even the quarter's results is the vision that Rick just laid out for the next five years. This represents several lofty goals that we will achieve just as we've done on so many other long-term goals. The third quarter results, along with the fourth quarter guidance, allowed the full 2019 results to come into focus and they look great.
We expect to hit the midpoint of our February capital guidance and at the same time generate higher-than-expected oil production. Our initial midpoint oil guidance for 2019 was 98,000 barrels of oil a day. With our updated guidance, we've increased this midpoint 5% to 103,000 barrels a day.
As Rick mentioned, we're now forecasting a 15% exit-to-exit growth rate, again, with no impact on capital. We know that the absolute numbers are important, but just as important is the shape of the curve, which dictates the influence of the base production rolling into the new yea. The strength going into the fourth quarter provides great momentum rolling into 2020.
These goals are set sometimes with technical attention against each other. For example, sustained free cash flow -- sustained production growth and free cash flow. Sometimes the tension comes between short-term and longer-term goals. In isolation many of these goals are very easy to make. The free cash flow generated in the third quarter is not a won and done or an isolated goal for WPX. Anyone can just shut down capital activity for the short term and generate substantial free cash flow. The free cash flow goal that we have is set -- that we have set is married with substantial -- with sustainable and profitable -- profitably growing our business. We expect to generate approximately $100 million in free cash flow in the second half of '19 and at a $50 WTI we expect to generate sustainable free cash flow for 2020 and beyond.
Now let's turn to Slide 6 and discuss our impressive performance driving well cost down. Well cost certainly doesn't show up in the short term the way it always -- it does actually in the capital number, excuse me, let me repeat that. The well cost certainly shows up in the short-term in the quarterly capital number. It takes a bit longer for those costs to work through the DD&A math and ultimately show up in earnings. If you take a look how far we've come and drive down -- driving down DD&A, you can begin to see our progress in drilling better wells for lower costs, or in more generic terms, just making better investments.
On third quarter call last year, I discussed the technical work that we were doing on the Pecos State pad in the Delaware. Just to remind everyone on this six well pad, which included the Upper and Lower Wolfcamp A, the X/Y intervals, we utilized fiber optics, microseismic, chemical tracers, geophones and external pressure and temperature gauges, which allowed us to monitor the effectiveness of our stimulation and watch how changes to the frac design impacted each perforation cluster, leading us to more effective frac design and importantly, a cheaper frac design.
Since initial flow back, we've been monitoring the interactions of these wells real time from the external pressure gauges and that has improved our understanding of the drainage and parent-child relationships.
The graphs on the bottom half of the slide shows the actual drilling, completion and facility costs, including artificial lift per lateral foot completed for each quarter, since the third quarter of 2018. The Williston graph is on the left and the Delaware is on the right. These graphs highlight the financial impact of the Pecos State technical learnings and the dividends that this work is paying in both basins.
In Delaware, our cost per lateral foot is down 26% from the third quarter of 2018 for an average 7,500-foot lateral. As I mentioned on previous calls, we've applied these learnings from the Delaware to the Williston and the result is a 13% decrease in those capital costs.
The cost savings in both basins are primarily driven by the changes we have made to frac design, fluid stage and proppant schedule because most of these savings are related to changes, we have made to how we pump the frac jobs. They're agnostic to commodity price and should be durable even into a higher price environment.
As we further optimize our frac design, drive for further efficiency and modify our casing designs, we expect these costs to continue to improve, especially in Delaware.
Now let's turn to Slide 7 to talk about the exciting Third Bone Spring results. On the right side, you can see very strong results we've seen on five different pads, focused on the Third Bone Spring in the Delaware Basin. These wells are all two mile laterals, the CBR 6-7 2-well pad has cumulative production of approximately 365,000 barrels with approximately 55% oil cut.
We haven't given out our type curve for Third Bone Spring yet, but four of the five pads are trending above the 2 million BOE and the one pad is trending just above the 1.5 million BOE. These results give us greater confidence that the Third Bone Spring [indiscernible] as productive as economic as the Wolfcamp -- the Upper Wolfcamp, which includes the Upper and Lower Wolfcamp A as well as the X/Y.
We're actively working on what the ideal spacing and number of landing zones are for this price environment and should be able to communicate that sometime in 2020. As I mentioned on the previous slide, we've driven well costs significantly down over the past year. Our two mile well cost is just below $9.5 million for drilling, completions and facilities. We continue to see the momentum in 2020 for cost to decrease, especially in the 50 to 55 WTI world.
We continue to see strong crude realizations in the Delaware. For the quarter, we realized $55.96 per barrel of oil. It was just $0.50 off of WTI pricing for the quarter. As Gray Oak comes in mid-fourth quarter, we should continue to see strong realizations in the Delaware hovering around WTI for the foreseeable future. I want to reiterate a point that Rick made regarding natural gas flaring. I was at a university earlier this week, and a professor made a passing comment about those oil companies in West Texas are happily flaring gas. I can tell you it struck a nerve with me. Nobody is happy with flaring. We take this very serious in both Williston and our Permian operations. Last quarter, I mentioned that we've stayed in full compliance with the tight and getting tighter gas capture rules in North Dakota. Rick mentioned that we're as low as 1.5% flaring in the Permian. To get to this point, we've invested hundreds of millions of dollars in the infrastructure, and we've been focused on this for years.
I'm very proud of our culture, being great stewards of the resources that we're charged to manage and that includes the natural resources as well as the financial resources.
Now let's look to Slide 8, and I'll more about what's going on in Williston. In the first quarter call, we showed early time results of our 2019 drilling program compared to 2018. Now with 180 days of additional production, the results continue to outpace very impressive 2018 numbers. We continue to demonstrate that our Williston position is a true economic epicenter of the basin.
As I mentioned earlier, the tactical and technical learnings in the Delaware have also improved the economic performance in the Williston wells. The current well cost in Williston is $6.7 million, which includes drilling, completions, facilities and artificial lift. We believe these are basin-leading costs and overall well-leading economics. You can see the impressive results continue to demonstrate it by the Bird Bear Pad, and we'll continue to demonstrate this in the wells that we're drilling today.
Now I'll turn it over to Kevin Vann, our CFO, for the financial update.
Thank you, Clay. With the well performance we're seeing in both basins, coupled with your team's management of well costs, WPX's sits in an enviable spot in the industry. In addition, WPX strategic management of the midstream and marketing picture has differentiated our price realizations and has limited the amount of our flared natural gas, as both Clay and Rick mentioned. The themes today are pretty straightforward consistency, continuous improvement and sustainability. All of the WPX team take execution to heart, regardless of whether it's operational nature or on the financial side of the house. What you see in the third quarter is part of the basis for our long-term optimism.
Turning to Slide 10, as Rick and Clay both indicated earlier, we generated over $40 million in free cash flow for the quarter and expect approximately $100 million over the last six months of 2019. Also despite the decrease in the average realized prices for all commodities over the last 9 months, our adjusted EBITDAX increased 29% from $775 million last year to a little over $1 billion for this year. For the quarter, adjusted EBITDAX was up 22% over the same period last year. At 108,600 barrels per day, our oil production is 30% higher than the same period of 2018.
As you often see in the Williston, our third quarter results were outstanding. The team enjoyed great weather for the first two months of the quarter, and then faced some really wet conditions in September. When comparing to the second quarter of 2019, our oil production was up 11%. As we've mentioned in the past, the timing of the large multi-well pads in Williston contributed to the lumpy quarterly growth.
At nearly 227 million cubic feet per day, our natural gas production for the third quarter was up 41% versus the same quarter of 2018 and up 10% since the second quarter of this year.
The Delaware Basin led the charge on our gas growth as we had our Stateline processing capacity online for the full quarter this year versus the same quarter of last year. From a sequential quarter perspective, we were in ethane rejection for most of the quarter, which also led to the higher natural gas volumes.
Our NGL production of 27,000 barrels per day was 97% higher than the third quarter of 2018. From a sequential quarter perspective, we were down 1%, however, and again we were not recovering ethane for most of the quarter.
At a 173,400 equivalents barrels per day, our total production is 40% higher than the third quarter of last year. For the third quarter, we are reporting an adjusted EBITDAX of $352 million, which is $64 million higher than the third quarter of prior year. For us, these results demonstrate the quality of underlying assets and the execution by the team. In the face of lower commodity prices, we were still able to grow EBITDAX by 22%.
We are also reporting an adjusted net income of $38 million versus $29 million in 2018. The improvement was driven, again, by the higher oil volumes. However, there were other noncash items that impacted the quarter as well. First, depreciation, depletion and amortization was $48 million higher this quarter versus 2018, which resulted from higher production volumes. However, our DD&A rate per barrel at $15.11 continues to improve. Last year, that rate was over $17. I can remember when the rate was over $25 per barrel for WPX. I know DD&A is a noncash charge for the period. However, to me it speaks volumes to the quality of your rock and how you're managing your cost.
Also unlike some companies, we have not recorded a significant impairment affecting our DD&A rate. Lease operating expenses and the GP&T were $28 million and $23 million higher this quarter than last year and again were primarily driven by the higher oil volumes.
Our capital expenditures incurred for the third quarter totaled $264 million. Of this amount, approximately $233 million relates to drilling and completion activity for operated wells and $22 million for midstream infrastructure.
Turning to Slide 11. I'm very pleased to announce that we are raising our fourth quarter oil production guidance to 109,000 to 111,000 barrels per day, up 4% from an estimate we provided during the second quarter conference calls. This also increases our full year guidance to 102,000 to 104,000 barrels per day. Despite this increase in production, as Clay mentioned, we are not changing our fourth quarter capital guidance of 260 million to 275 million, which keeps our full year guidance unchanged as well.
This increase in our fourth quarter production estimate results in an increase in our 2018 to 2019 exit rate to approximately 15%.
Now turning to Slide 12. I'm very proud of the entire WPX team and their bias for action as we hit a really optimal spot in the debt markets this quarter. The timing was about as close to perfect as you could want [indiscernible]. With the issuance of the $600 million of 5.25% notes and the subsequent repurchases of higher coupon debt, we have not only decreased our annual interest expense, but now our next significant maturity is not until 2023. Also as Rick mentioned earlier, we have reduced long-term debt by approximately $300 million this year and leverage is close to 1.5x. We got to this point by having top-quality assets and remaining disciplined to our goals.
Sometimes, we were questioned about our CapEx and particularly the investments we were making outside of D&C. As you can see now, those investments allowed us to monetize certain midstream and midstream equity investments that may have put some pressure on CapEx short term, but have helped reduce leverage long term.
I'd like to go back and look at what I said last year during each quarterly call. As I read my transcript from the third quarter of 2018, I noted that I was looking forward to 2019 when we would be finding our CapEx from our own internally generated cash flows. I also remember saying that we had goals of leverage down to 1.5 turns. We didn't need high oil prices. We have prudent risk managers here at WPX and made the hard decisions with our balance sheet that later became clear as to why we made them. I'm proud of the WPX team and proud we're executing year in and out on what we say we're going to do.
I'll now turn it back to Rick for some closing comments.
Thank you, Kevin. It's truly an honor to be part of this creative, hard-working organization. Our team is motivated, open to new ideas and are willing to roll up their sleeves to get the job done. We've proven that time and time again. We've also presented a bold vision today for where we want to go and what we want to accomplish for our investors and our employees. We're excited by the challenge and the opportunity.
We know what it requires, and as always, WPX will be defined by our courage, our focus and our results as we execute our plan.
At this time, we can open the lines for questions. And I'll turn it back to you operator.
[Operator Instructions]. Our first question comes from the line of Derrick Whitfield from Stifel.
And congrats on a strong quarter and the introduction of your five year vision. Perhaps for Rick or Clay, regarding your base decline initiatives in your five year vision, could you generally walk us through the progression of declines under that initiative and confirm that it does not comprehend secondary or tertiary recovery as a mitigating factor?
Yes, great question. This is something that we have owned wholeheartedly. This year we've talked about our base decline peaking and of course, that's on the back of some very substantial growth over the last few years, and it's just math. We all understand exponential declines and hyperbolic declines and how that manifests into ultimately base declines. And so as we think about our 45% base decline that we've experienced in 2019 and we roll that forward into '20 [indiscernible] kind of hovers around 40% and [indiscernible] working its way down. Now this is all assuming a $50 to $55 environment, which is a very nominal growth out during that period and would naturally occur as you have fewer and fewer. Or lower percentage of your total production is that wedge production, and you have more of it in just a little bit more season-type wells. And so no secondary recovery, no shenanigans with buying or selling assets. It is just a natural course of really, really strong portfolio that we have in-house today.
That's great, and perhaps as my follow-up. If I look at chart, your D&C charts on Slide 6, those are quite impressive. Do you have a view on what your maintenance capital would be to hold Q4 '19 production flat assuming Q3 capital efficiency levels?
Yes, I think Q3 capital efficiency, first of all, I think we'll continue to do better than that, assuming this price environment, I think, we have our eyes on continuing to work that down. We've talked about $800 million to $900 million in the past. I think that kind of rallies towards the lower side. Well performance continues to improve and then the cost per entry of each well continues to go down that obviously supports it. I'd put it on the low end of the $800 million to $900 million that was talked about before.
Our next question comes from the line of Brian Downey from Citigroup.
Maybe following up on that one as you -- on Slide 6 with the impressive cost controls, as we think about that in the next year, could you maybe mention any further cost-cutting runway and if any of that impacts some of the potential CapEx guidepost as you think about 2020 as we all refine our capital efficiency estimates.
Yes, Brian, happy to do that. This is Clay again. The -- as we think, about 2020, obviously, we haven't gone through that with the board yet, as Rick mentioned. In the coming months, we'll give a little bit more or a lot more granular detail on it. But just directionally, I think, looking at what we're doing in the third and the fourth quarter, I think, that impressive work that we're manifesting in the well costs I think should continue. There is a few other things that we have our eyes on, that we've tried out during the year. I think some of these tests are really working quite well, a different casing design in the Permian is an example as we fully bake that into 2020. That's a few hundred thousand dollars a well, call it, $200,000 to $400,000. There is some things we're doing in regards contracting to sand, that continues to work in our favor, specifically in the Permian.
And -- tell you what, it's the same team brilliant ideas, continue to be creative. There are other things that are coming our way as well. So we'll continue to work towards that. I wouldn't guide too far below where we're at today without having all of those things in hand, but know that we have some -- we keep some things in our back pocket, and we'll continue to try and be really creative on how do we continue to improve our investment options.
That's helpful. And then taking a step back, the bulk of your oil growth this year has come from the Williston Basin. So I'm just curious as we put together the pieces of the strong Delaware well performance in the slide deck, the Third Bone Spring results and the cost reductions, how should we think about Delaware oil volumes, in particular trending as we head into next year?
Yes. So I think, Delaware, I mentioned in the previous question about the base decline it's a perfect example of what's happened in 2019. You're essentially at your apex of your base decline. We're running 5 rigs, but remember these are 50% oil wells, they take our state-of-the-art 22-day, two mile wells, cycle-through pretty nice. But it's about 1,000 barrels per day per quarter increases what we're seeing in that environment, 45-plus percent base decline, you're offsetting all of that and then continuing to gain ground. As I mentioned, rolling into 2020, even in the same rig program, you don't have as much base decline to make up for, and so that helps boost that production growth a little bit, and of course, as we start talking and detailing out capital plans that number certainly has the capacity to go up as far as rig count, if we so chose to do that.
Our next question comes from the line of Brian Singer of Goldman Sachs.
Following up on the Williston, Slide 8 shows the consistent well performance improvements that you've seen. Can you talk about the sustainability of that as you go into 2020, 2021? How you see the inventory shaping up relative to the type curves that you've shown and any opportunities too that you'd be looking for to extend that?
Brian, great question. I think we had this probably same plot this time last year. Really excited about the great 2018 results and I think I threw out the warning there that look, this is some -- on the back of some North Sunday Island, absolutely, world-class rock. That they're not making any more of that. We're kind of spent through that inventory. We have a little bit more here and there, but it's -- this is kind of maybe our apex of the productivity of these wells. And then my team goes and blows it and outperforms 2018. I'm incredibly excited about the work in 2019. There is so much that goes into it. We're not improving the geology obviously; you know that well. It's creativity around stimulation, how we flow these wells back, thinking about artificial lift and all of those disciplines coming together to make sure that up-time is maximized, productivity is maximized, and all -- do this with a cost focus in mind to ultimately yield tremendous return. As I look forward into 2020 and beyond, I don't see a significant fall off in geology from 2019. I think we have kind of tested what we're going to be testing similarly in 2020. I don't know that I can predict another vertical step in that -- in the shape of that curve for 2020.
But I have full faith that the team is going to be able to continue to perform at this very high level, continuing to watch costs, and ultimately, continue to provide incredible full rate of returns on these investments.
Our next question comes from the line of William Thompson of Barclays.
Rick or Clay, I understand that your base declines are higher in the Delaware than in the Williston, which makes sense given you entered the Delaware only in mid-2015. I guess, going forward, would you look to toggle activity back to Delaware to help mature that asset. How should we think about balancing activity and growth between the two basins, knowing you've less inventory runway in the Williston?
Yes. So we have -- in my view, we have toggle activity in the Delaware. That basin from the inventory, from the capabilities of what we could do, we could run a heck of a lot more rigs. We've chosen to really live in the mantra of financial discipline, capital discipline. And doing so, you've seen that production increase very moderate over the last several quarters.
And so your base decline is flattening out pretty substantially, and that's what's baked into the plan going forward. Now I'm not saying we'll never add rigs to the Permian, of course, we will when the timing is right. But we're going to do so in a very thoughtful fashion, continue to generate free cash, and then continue to watch that base decline, such that the overall company's base approaches that 30% that we outlined in the five year plan.
I'm sorry, the premise of my question is just kind of toggle from Williston back to the Delaware, but I appreciate the answer.
This is Rick, interject something to it, when Clay talks about -- recently we have seen the apex. Remember we had laid a couple of Permian rigs down at the start of this year. And so you think about 5 rigs, trying to offset the decline from a 7-rig program, it really, I think, extenuates the circumstances. But we are, as Clay said, you're going to see a shallower base decline.
So we do have the opportunity to toggle some rigs back as you see improving cash flows, just being very thoughtful. But once again to Clay's point, we've been very, very focused on returns and you cannot deny that the returns that we see in the Williston are not only the best in our entire portfolio, but I would put them up against anybody's -- the best in anybody's portfolio. So we're staying disciplined. And so you'll see in the next couple of months what our plans are in 2020 as we get those locked down.
Okay, look forward for that. In terms of the five year vision, just want to clarify if these are targets for 2024, 2025 or could some of these objectives be reached ahead of the time frame. You've previously suggested your preference to let the base declines moderate before instituting a dividend. You mentioned getting closer to 40% base declines in 2020. At what level do you think it's right to sort of announce a dividend?
Well, I think, two things, we say five years from now. So I think when you would look at kind of year-end 2024, it's not too dissimilar than what we did back in late 2014, when we laid out a five year plan. That when we had the [indiscernible] 2020 vision that we attached to it. And that's when we had the takeoff point had been the previous year. In 2013 WPX produced domestically 16,000 barrels of oil a day for the year. And that plan was built all around growth and switching from a gas commodity dominated portfolio to one that's oil-dominated. And our goal by 2020 was to be at 80,000 barrels a day. We had a lot of people that really doubted that. And so it gives you a lot of satisfaction to see that operationally we did exactly what we laid out that. As a matter of fact, we exceeded that. So if you think about now what we need to do not only as a company, but as an industry and that's decelerate growth and really focus on returns and cash back to shareholders, those sorts of things. And that's why we've laid this out. So I think from our perspective, we're going to -- we will probably look at implementing the dividend in the next 2 to 3 years. I think that you're going to see a flatter decline. And as we've mentioned, we -- with the equities trading where they have, that's why we implemented this opportunistic share buyback program., So first thing is first, we'll be very thoughtful about that, but the five year plan simply is a framework and the goals that we plan on building the -- continuing to build the company around with that being the outcome in 2024 year-end.
Our next question comes from the line of Josh Silverstein from Wolfe Research.
Just following up on those last comments and something Clay had said earlier, one thing that's missing from that five year outlook is the growth rate. I think that you guys were still targeting to try to of be a 10%-plus grower next year, how does the long-term growth rate fit into this?
Well, that's something we'll continue to fine tune, Josh. We have the capabilities certainly to do that, but we want to make sure first things first that. We're getting the message loud and clear from investors that, that while growth is still something to look at, people want value, people want returns, and so that's what we're certainly trying to deliver for investors. And so -- but I do think that you'll see some of the growth rates that you've talked about and we can certainly deliver the 10% annualized, 15% annualized, but we wanted to -- but I don't know that we have to go to that level. Matter of fact, less than that is -- could be -- if you really want to truly focus on free cash flow generation that's what you need to do.
I wanted to see how you guys address the Williston inventory within this time frame as well? Does that basin go to a flat profile and the growth then comes from the Delaware basin just to extend the inventory there? And I know you guys also have $100 million annual land spends. Is this something that could be used to replace the inventory up there as well?
Josh, it is a good question. The worst-case scenario if you don't add a single acre. And this is just -- we drill up our inventory over the next few years, and this becomes just a very, very strong free cash flow generating asset that requires no capital, that's the worst-case scenario. I can tell you we have a very talented, dedicated team looking to build inventory even on our existing acres that we have or going out and transacting in some areas. There are some creative things that we can do there. So I'd say just stay tuned, we've got a good team working that, and I'm -- we've got a lot of confidence in them.
Josh, if I could add just one quick point on that. As we think about this five year vision, it doesn't contemplate any material adds. There is no changes of portfolio and there is no kind of goofiness on -- like negative growth to get there or anything like that. Think of the consistency of our messages. This is the same plan, same team, heading in the same direction. We just wanted to articulate essentially boundary conditions of our strategy. And as we think about the importance of growth, we thought it was an important message, not to include it on this slide indicating for the more generalist investors. I think they can relate to these. All of these outside a little bit of the base decline. I think everything else, every one of these other factors could be slapped on any other S&P 500 company, and I think it would be pretty aspirational for them.
Our next question comes from the line of Gabe Daoud from Cowen.
I appreciate all the prepared remarks and the five year vision. I was wondering, I guess, if you could just dig a little bit more into these assumptions. I guess, just around gas and NGL realizations. And you kind of hit on this on the last call, but I guess, how this shapes or changes your view, if at all, on acquisitions?
Well, as far as -- there is two questions there. One is around the realization of NGLs and that sort of thing. I think you've seen from a macro perspective, NGL prices have pulled back. Up in the Williston, we've actually got some better gas recoveries recently. However, our gatherer up there is a still building out some of their NGL infrastructure. So we've actually had to do some trucking of some volumes and it kind of hurts a little bit your realizations as well. But as far as the second part of your question around acquisition, we'll continue. We get this question a lot around our thoughts on M&A. And we'll always be thoughtful about this. Certainly, with a portfolio we have, we don't need to -- it's not a have to do things. We'll continue to be thoughtful and look and evaluate, and we'll just see if that lands anywhere. But I can tell you whatever we do, whether it's adding rigs, dropping rigs, buying assets, selling assets, it all has to be supportive of this five year vision that we have out there. And so I think it's probably the most simple and clear answer I can give you.
Awesome. Thanks, Rick. And then just a follow-up, I guess, Just given the co-development pads that you've put on production earlier this year and just some of the other CBR pads, could you maybe just talk a little bit about how some of the results there have changed your thinking, if it all, on spacing in the Permian moving forward?
Yes, very thoughtful question, Gabe and I appreciate that. We didn't cover that in too much detail in our prepared remarks. But last quarter, we went on too little bit deeper, I would say, it's a continuation of that message. We think 4 to 6 wells per landing zone for Stateline Wolfcamp A -- kind of the Upper Wolfcamp seems to -- in this price environment -- in this cost environment, seems to provide the right overall return for us.
We continue to explore that, is it 4, is it 6. We've been wider than that, we've be looser than that, tighter than that, and we continue to explore how not just the well spacing, but the stimulation. The landing zone to landing zone delta makes a difference, thickness of the reservoir and several other kind of second-order considerations as well.
Your next question comes from the line of Neal Dingmann of SunTrust.
Rick, I think you've asked around this, but maybe asked a little bit different way. Just curious to hear just general thoughts -- M&A thoughts in the context of potential opportunities as pressure is placed on the private and public operators to liquidate assets out there in order to maintain some adequate debt metrics providing you some opportunistic. So just wonder how you view that today in context of everything else you've been saying?
It's interesting discussion and narrative. Number one is I think that we need to and we will have consolidation in our industry. I think that almost everyone readily agrees to that. I think what companies really have to be thoughtful is, if you are a publicly traded company, you need to make sure that you're doing something that's not just to add scale. And we are not proponents that bigger is always better. We're proponents that better is always better and if that means you stay the size you are, or do you need to bolt-on something that truly makes you better than it's fine. And that's not just us, that I think, it goes for any company.
I do think that there are companies that -- that are -- both on a public side and on private side they need to really strongly consider rolling themselves into a stronger entity. But that's going to be their call and how that all plays out. But as far as us, we do think number one that consolidation needs to happen in our sector; number two, it is a tricky to make sure that is a truly accretive and not just something to build scale or and build inventory. And number three, for us, it really needs to tie into our five year plan. And if we can look ourselves in the eye and say, this transaction supports that, I think, that's something we probably have to give at least some degree of consideration to.
Okay. Great answer. And then Clay, maybe shifting gears a bit for Clay. Clay, you all suddenly appear to have about the lowest Bakken well cost I've seen in play today. Could you discuss maybe the factors that enabled you to do this and is there even a possibility of improving these additionally?
Neal, I agree with you. Looking at the well costs, I can't find anybody that's challenging us in that regard. That's certainly on the backs of the some really, really, really inventive, creative, hard-working team members, here in Tulsa and up in the basin itself. Because that extends into the over the LOE side as well really, really happy with what we're doing on the LOE. When you really extract out our numbers compared to the pure play guys that you can really compare the company to company on, I'm incredibly happy with that. And I can tell you, you all know this, Neal, it always hasn't been that case. So we have made huge improvements. I think when a team like this has shown the trajectory of continuous improvement, you just don't bet against them. The question earlier for well performance, I hate to doubt my team. I just don't want to throw out a vertical type curve and say, hey, these things just go straight up forever. Same thing with well costs. Well costs continue to chip away, continue to make strides. LOE, Rick mentioned the safety culture there. I mentioned in the last quarter the incredible gas capture and environmental work that the team is doing. This is -- I mean, it's a holistic approach. It's not -- let's not paint the tanks and let's get real cheap on whatever it is for the short-term win. This is very much a long-term focus, true value creation team, and I think greatly exhibits the ideals of the WPX culture.
Your next question comes from the line of Leo Mariani of KeyBanc.
I was hoping you could provide just a couple more thoughts around the uses of free cash flow over the next handful of years. If I'm kind of reading your remarks correctly, it may sound like it's going to be a few years before the dividend gets implemented. So should we just be thinking more in terms of stock buyback with that free cash flow over the next couple of years until you guys are ready to kind of get the dividend rolling?
Yes. This is Kevin. And I think, as you think about our free cash flow as we put the share repurchase program out there for a reason. We've obviously said that it was going to be opportunistic when we repurchased our shares. But the exercise that we do every day is we're coming in when we're not in a blackout period, and we're looking at what we believe our NAV to be versus where we're trading that day, and we're bouncing that up against what's our projections for free cash flow for that quarter. So first and foremost, I'd say that's -- we've got a $400 million stated goal out there, but it's always -- and I'll say it's contingent upon the time, the timing of which is always contingent upon where our stock is trading versus what we believe our NAV to be. We were opportunistic over the third quarter and into the fourth quarter, buying back 60 million shares. But when you think about longer term, I kind of look at those tents of our five year goals really to be -- we're not going to compromise leverage, and we're not going to compromise some of those other goals in order to do things that kind of I look at as potential uses of that discretionary cash flow.
We wanted -- We're committed to returning value to shareholders. And when I think about a dividend. Yes, you'd like to see that decline rate come down, you'd like to see the variability, basically, of your cash flows go down. But we also have been -- we've proven that we're good risk managers when it comes to how we're going to lean into some hedges. And leaning into hedges gives me comfort that we -- the more we do in opportunistic markets, the quicker we can lean into a potential dividend as well.
Okay. That's a great color. And obviously a few questions already on the M&A front, but just to kind of look at it little bit differently, I think, you guys still have some significant midstream infrastructure in the portfolio, which you're going to be adding to over time. How do you kind of think about that in terms of the five year plan and vision here?
Well, I think as we've said in the past. It gives us some optionality, the five year plan, that you saw up there, we didn't really contemplate any divestitures. We didn't contemplate any acquisitions or -- that's just a base plan with a static portfolio we have now. The reality is, at some point of time this infrastructure may fit better in someone else's portfolio than ours, and it could be that the monetization of that's the right thing. We just have to make sure that it's not a pay me now or pay-me later type deal, where we get some cash in the door now only to see significant margin erosion over the next number of years, forever really.
But it is very valuable piece of our portfolio, it's absolutely not seen in our equity price today. It's not recognized, but it's -- it's something that we'll always be looking at potentially the best path forward, be it monetization or keep it in the portfolio.
Your next question comes from the line of Subhasish Chandra of Guggenheim Partners.
The badlands area, is there an update there or is it still too early watching those wells?
Yes. Subash, it's Clay. I would say it's too early to ring the bell and say they're ready to drill in the portfolio. We're working those pretty hard. We have some production from them. But as you know, we've talked about the remoteness of that group of wells, and so it takes pretty good capital injection for some infrastructure along with just the support of the drilling costs themselves. So we're working on that. We continue to look. Again, we got our -- the best and brightest focused on this to crack the code. Have a high degree of confidence that if it can be done, it will be done. But I would give still a little bit of caution, we're not now ready to ring the bell on that one just yet.
Got it you. And then my second question is, on the gas hedges for 2020. Just that the Permian dips haven't really improved that much at least in the forward curve, et cetera. How do you, are you content sort of with the takeaway you have? Or do you think you need to work to hedge book there some more?
This is Kevin. We're going to continue to work the hedge book. I mean, realistically, obviously, the -- on a longer term basis, the cash that we expect to realize in as we -- as the portfolio transitions more and more to the Delaware, on an overall basis there is going to be more gas coming into the portfolio. So it will be subject to a higher cash flow risk there. For the next year, it's still relatively small percentage of our overall revenues and cash flows. But at the same time, you'll see us lean into some of those -- lean into some 2020, 2021 hedges over the next several months.
Your next question comes from the line of Kashy Harrison of Simmons Energy.
Just one quick one form me. Clay, great work for you and the rest of your team on just driving costs lower and lower. We've taken a look at the second half '19 CapEx run rate of $265 million a quarter give or take, and I was wondering if, for example, you were to hold the same level of activity in the Delaware and the Williston flat into 2020, if that would be a reasonable proxy for that -- for the 2020 program ?
Yes, Kashy. We're at kind of a steady-state mode now. You saw it in the third quarter, you'll see it, again, in the fourth quarter numbers, this $265 million run rate for the current activity is sustainable. If we chose to do that, kind of just run forward, obviously, you'd be looking at that x4 for the year. But again, let me just caution, we haven't got a budget approved from the Board yet. We're doing that in a few weeks, to have the really wholesome discussion, and there's a lot of things on the table. We have a very good dialogue, we get challenged from all sides as the way good Board should challenge a management team, and we'll see where that shakes out.
Your next question comes from the line of Biju Perincheril of Susquehanna.
Going back to the base decline discussion in the Delaware basin, beyond the natural improvement from slower growth and perhaps the wider well density that you mentioned, can you talk about any other variables or maybe on the completion front from your state test that could help with the decline?
I don't know. I'm trying to give a thought around the completions tweaks that would change base decline. I'm not drawing anything there. But I do think on the production side, artificial lift, how quickly we can get these wells to [indiscernible] offset. Having to shut in wells for offset fracs, either our opportunities or offset opportunities, all that significantly impacts the base decline and it also impacts our base production. And so those are the things that how we manage that over time, how we improve that. I think we'll continue to get better. Now as we think about the first couple of weeks of base decline, how aggressively we flow these wells back, that something we talked about very thoroughly. We've been more and more aggressive kind of working towards a more aggressive flow back. I can tell you in some parts of the business I think it may make sense to be less aggressive and kind of flatten that decline out. That would translate into an overall flatter base decline. So those are the things that we talk about quite a bit. I would tell you that all in the mix of things that we're looking at.
We're always trying to get better at, but those are probably a little bit second order to the big thing, which is just when you're growing, 50%, 60% a year, on the backside of that you got a really steep basically. You've got a bunch of big new wells in the mix, and those dominate that decline. As you get fewer of those, relatively speaking to the total production, that's just not -- your base decline matures, and that's what we're working now as we're a little over 100,000 barrels a day company, but we're relatively immature 100,000 barrels a day. As we roll forward for a few years that overall production number will go up modestly, but that base decline, and the maturity of that type of production goes up pretty dramatically.
That's helpful. And then the 4 to 6 wells per section density that you mentioned, when do we start seeing those wells coming -- being brought online?
Yes, we have some online now. I would say relatively -- or really, I don't have the first half of those widest space wells -- what their vintage is. But yes, we have them online now. We've been working this spacing for quite a bit. Our initial thought, and my push was let's go tight quick. Let's figure out where that line is. Step on the other side of it and then we can dial back at any time. And so we're really -- we're really watching that. And again we have to be very cognizant of commodity price. When you're chasing $65 barrels, you can get much more aggressive, and it's the right thing to do to be more aggressive. When you're in kind of this $50, $55 environment, you need to be more thoughtful about what you're willing to invest? And that full cycle return, how does that really pan out as you dial this back and one with $1 or the other.
Our last question comes from the line of Jeff Grampp of Northland Capital Markets.
I was curious if I'm looking at Slide 6 here and seeing the cost reductions you've gotten, particularly in the Delaware. I was curious, how lateral length has maybe changed over the past year, if that's been a benefit at all to the cost structure, and maybe if you can just kind of give us a flavor for average lateral length this year versus what the 2020 program could be?
Our lateral length has improved -- has lengthened a little bit year-over-year. 6,800 feet and I'm trying to remember that number from last year, last year 6,800 feet?
In that ballpark. 7,500-feet this year. So there is there's a little bit of benefit from that. But I would say when you're looking at quarter-to-quarter, it's not that -- that's not the big driver. It's an excellent point though because I wanted to emphasize. As you push this into two mile laterals, which all of our peers talk in different terms, if we were just talking in two mile laterals -- completed lateral foot, state-of-the-art what we're actually doing that number is actually closer to $900, $950 per completed foot. So there is opportunity as we further drill -- we drill further, continue to push on to more two mile laterals, work more those into the mix, that number continues to naturally work its way down. And again in Stateline, where the focus of our activity is, almost all of those are two mile laterals. And so you're getting a really good feel closer to that, the $950 per foot. The average we're talking about for the third quarter, we'll throw everything in there, that's every trouble well and downtime and any issue they call that in, that's the number you're seeing represented there.
Okay, great details. And for my follow-up switching over to the Bakken, I was curious beyond the one year production chart that you guys provided in the slides. Is the outperformance that you're seeing and maybe if we just look at maybe 2018 versus 2017 since maybe there's enough data there. Is the outperformance continuing to that degree? Is that narrowing at all? And I guess, asking just to try to get a sense of acceleration versus higher recovery factors, if you guys have any opinion on that yet?
Yes, at some point it is acceleration. We're -- the recovery factor is exceptionally high for a resource play. It's not exactly a shale that we're drilling up there. These are very high recovery factors, but you're starting to bump up against that. And so what we're looking at now is how do you bring that value forward, create more NPV from that well, and you certainly see that. We think looking at a 365-day look, if you're still materially outperforming, at day 365, that's probably a good investment, even if it costs more. In our case our costs have either maintained or dropped down. And so it's obvious benefit on both sides of the question. As I think about '18, kind of second-year performance or '17, second year to '18 second-year performance, they start to narrow a little bit, but '18 is still substantial relative to '17. You still see a pretty significant gap. And again that significant gap in '19 relative to '18, I would expect second year performance for it to narrow, but there's such a nice running start, 270 days or so in, that it's not like the lines cross on 366 days and then you really degrade recovery after that.
And I would now like to turn the conference back to Rick Muncrief.
Thank you very much. I want to thank everyone on behalf of the management team and the company for joining us today on this call. We look forward to talking to you in about three months. Take care, have a good day.
Ladies and gentlemen, this concludes today's conference call. Thank you all for joining. You may all disconnect.