Welcome to Devon Energy's Third Quarter Earnings Conference Call. At this time, all participants are in a listen only mode. This call is being recorded. I'd now like to turn the call over to Mr. Scott Cootey, Vice President of Investor Relations.
Sir, you may begin.
Thank you, and good morning. I hope everyone has had the chance to review our financial and operational disclosures that were released last night. This data package includes our earnings release, forward looking guidance and detailed operations report. Additionally, for the call today, we have slides to supplement our prepared remarks. These slides are available on our website, and we will make sure to refer to the slide number during our prepared remarks so that everyone can follow along.
On today's call, I will cover a few preliminary items, and then I will turn the call over to our President and CEO, Dave Hager. Dave will provide his thoughts on the strategic direction of Devon. Following Dave, Tony Vaughn, our Chief Operating Officer, will cover a few highlights from our U. S. Resource plays and provide his perspective on the current market dynamics in Canada.
And then we will wrap up our prepared remarks with Jeff Ritenour, our Chief Financial Officer, covering our financial highlights. Overall, this commentary should last around 15 minutes before we head to Q and A. I would like to remind you that comments and answers to the questions on this call today will contain plans, forecasts, expectations and estimates that are forward looking statements These comments and answers are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance, and actual results may differ materially. For a review of risk factors, please see our Form 10 ks.
And with that, I will turn the call over to our President and CEO, Dave Hager.
Thank you, and good morning, everyone. For today's call, my comments will touch on 3 key messages related to the strategic direction of Devon. Turning to Slide 2, the first key message I want to emphasize is our commitment to our disciplined multiyear development plans. At Devon, we fundamentally believe that a steadier and more measured investment program through all cycles is the correct strategy to optimize corporate level returns, grow our business, generate free cash flow and reward our shareholders with increasing amounts of cash returns. With this disciplined approach to the business, the benefits of any pricing wind fall above our base plan will simply manifest in higher levels of free cash flow for Devon, not higher capital activity.
I am absolutely convinced this balanced operating model is the future of the E and P business and we will be a leader in this movement. Importantly, this bold commentary is backstopped by actions, which has resulted in several value enhancement accomplishments year to date. Our light oil growth is running ahead of plan with no modifications to our capital spending. This combination is a unique success in the E and P space this year. We have taken action to materially improve our corporate cost structure delivering $475,000,000 of savings on an annualized basis.
Our capital discipline has resulted in free cash flow in the second half of twenty eighteen and coupled with divest proceeds, we have generated nearly $4,000,000,000 of excess cash inflows this year. We have strategically deployed a portion of this excess cash flow to reduce debt and we have reached our net debt to EBITDA target of 1 to 1.5 times, nearly 2 years ahead of plan. And maybe the most important highlight of 2018 is the industry leading a mass of cash we are returning to shareholders through our $4,000,000,000 share repurchase program.
All
All Looking ahead to 2019, my second key message is that we are accelerating investment in our world class Delaware Basin assets. Turning to Slide 3, from a total company perspective, we directionally expect our E and P capital to range from 2 point $4,000,000,000 to $2,700,000,000 in 20 19. With this activity, the Delaware will be our top funded asset by a wide margin, with investment increasing by greater than 25 percent to nearly $1,000,000,000 As showcased in our Q3 operations report, the increased activity in the Delaware is an easy capital allocation decision given the massive step change improvement in well productivity returns we have experienced over the past year. Importantly, we have secured the supply chain, infrastructure and takeaway capacity to execute on our development plans. Beyond the Delaware, the STACK and Rockies will also be important growth assets for us in 2019.
With our refined approach to infill spacing, we expect the STACK to be our 2nd highest funded asset in 20 19 and the doubling of activity in the Rockies will also contribute to our oil growth initiatives. Specifically in the STACK, we are very confident we determined the optimum well spacing in this of 4 to 8 wells per drilling spacing unit. This quarter marks an inflection point in both returns and volumes for the STACK. Better days are on the way very soon in the STACK. In aggregate, approximately 90% of our total capital program in 2019 will be allocated to our high growth U.
S. Resource place. This highly focused capital program in 2019 is expected to drive 15% to 19% oil growth from our retained U. S. Assets with total company wide volumes projected to advance at a high single digit rate on a retained asset basis.
Most importantly, this light oil oriented development program is designed to deliver healthy margin expansion and achieve highly competitive cash flow per share growth at today's strip prices. Moving to Slide 4, the final key message I want to convey is that we are on track to deliver on the performance targets associated with our multiyear business plan. While I will not cover all of the details on this slide, I want to be clear, the management team at Devon is not content with the substantial progress we have made to date and we're striving not just to meet, but exceed the goals associated with our multiyear business plan. To do so, we will allocate capital by prioritizing efficiencies and returns above growth. The Delaware will be our top funded asset as we will accelerate investment at our world class U.
S. Growth platform. This plan will transition our product mix toward higher margin barrels and we will maximize the value of this production by effectively managing costs. We will continue to evaluate strategic opportunities to high grade the portfolio. Going forward, as we generate excess free cash flow, we will prioritize the return of cash to our shareholders through the growth in the dividend and additional share repurchases beyond our current $4,000,000,000 program.
With that, I will turn the call over to Tony for additional commentary on our operations.
Thank you, Dave. Today, my remarks will be focused on a few key messages related to our U. S. Growth platform and I'll also provide some thoughts on our current market dynamics in Canada. Beginning with the Delaware Basin on Slide 5, I believe it is fair to state that these world class assets have reached an inflection point with a massive improvement in well productivity achieved in 2018.
While our Wolfcamp wells stole the headlines this quarter with IPs reaching 4,000 BOEs per day, our Bone Spring and Leonard programs have also consistently delivered outstanding results this year. In aggregate, between these 3 prolific formations, our average well productivity in the Delaware has improved by more than 70% in 20 legacy activity in the area. This step change in productivity is driven by the combination of good technical work from our staff and a more focused development program in the economic core of the play. Importantly, we are well positioned to accelerate Delaware Basin activity in the Q4 and into 2019 to further exploit the advantage these top tier assets provide. This plan will result in higher 2018 exit rate targets and will deliver around 40% oil growth in 2019.
What excites me just as much as a strong volume growth is the 10% to 15% decline in per unit LOE rates we expect to achieve in 2019 due to the upfront investment we have made in scalable power, water and oil takeaway infrastructure. Now moving to Slide 6, I'd like to shift my commentary to focus on the next steps associated with our STACK infill spacing program. As you are aware, our initial infill spacing pilots were designed with up to 12 wells per drilling unit to test the net present value upside associated our acreage in the over pressured oil window. With the data we received from our initial 12 well showboat spacing project, we have quickly recalibrated our completion designs and flowback strategy to improve results at both Bernhardt and Horsefly, which were testing spacing of 8 10 wells per unit respectively. Collectively, these infield tests have provided further advanced our understanding of the optimal development approach in the play and as a result, our go forward activity will be sized at 4 to 8 wells per section in the STACK.
As you can see on the map on Slide 6, several of these lighter density spacing projects are achieving 1st production in Q4. Importantly, more than 75% of these wells are targeting the Upper Meramec sweet spot and early results are confirming our view that this is the optimal approach to development. With this program, we expect production growth to accelerate in STACK before the end of this year and this momentum underpins our growth expectations in 2019, coupled with recent well cost declining by more than 30% versus legacy activity in the field, we expect these projects to deliver highly competitive returns. This will be the 2nd highest funded asset in our portfolio next year and with the vast majority of our Meramec resource undeveloped, we have no shortage of highly economic inventory in the STACK to drive future growth. The last U.
S. Asset I would like to discuss is the Powder River Basin, which is what I believe to be the best emerging growth opportunity in North America. With our Super Mario Turner program ready for full field development and strong results from our Niobrara appraisal activity, we are ready to accelerate activity. By early 2019, we plan to double activity to 4 rigs and drill 50 new wells during the year. The vast majority of this activity will be low risk, high return Turner development activity that will drive strong production growth from this asset by mid-twenty 19.
We will also more aggressively delineate our Niobrara potential in 2019 with more than 10 new wells. Our significant Niobrara position of 200,000 net acres provides us the opportunity for a scalable and repeatable resource play that has the potential to be an important growth platform for Devon in 2020 beyond. And finally, in Canada, as we disclosed a few weeks ago, the incremental facility repair work we identified during our turnaround efforts at Jackfish is now complete. Our Jackfish complex is fully operational and in October we were producing at roughly 110% of nameplate capacity. However, with the weakness in pricing in November, we have adjusted our production rates lower at Jackfish.
It is important to note that this proactive action was previously incorporated into our Q4 guidance we issued a few weeks ago. These curtailment decisions are based on real time pricing and we expect to continue to defer volumes in the future should these barrels continue to be extremely undervalued. As you can see on Slide 7, when we look ahead to 2019, we have several initiatives in flight to help protect cash flow. We will continue to opportunistically add financial hedges. We have firm transport contracted for a portion of our volumes to access the advantaged Gulf Coast pricing and I believe it is important to focus on the attractive long term attributes of this asset, which include low declines, minimal maintenance capital and substantial free cash flow generating capabilities.
When it comes to the valuation of this long life asset, these unique attributes should be valued at a premium compared to other highly capital intensive plays across North America. In fact, just last year in a more normalized price environment, our Canadian assets generated over $800,000,000 in cash flow. At this point, I will turn the call over to Jeff for additional commentary on our financial results. Thanks, Tony. I'd like to spend my time today discussing a few key financial highlights for the quarter.
On slide 8, a great place to start is with NGL prices, which were a key driver of our revenue growth in the quarter. Devon is one of the largest producers of NGLs in the U. S. And with NGL pricing nearly doubling as compared to the same period a year ago, we were able to capitalize on this pricing tailwind through our secured flow assurance and access to the premium Mont Belvieu market. Approximately 98% of our volumes have access to Mont Belvieu where waterborne access provides a structural pricing advantage compared to the landlocked Conway market in Kansas.
Across our key NGL producing regions, we have low fixed rates for transportation to the Gulf Coast and we have contractually reserved fractionating capacity for our Y grade barrels. In fact, we currently have excess fractionating capacity secured that supports our growth plans through the end of the decade. In addition to the stronger revenue stream, our quarterly results were also enhanced with excellent capital discipline. In the Q3, our capital spending came in at 9% below the midpoint guidance point. This investment was completely funded within operating cash flow we generated free cash flow in excess of our investments of $249,000,000 in the quarter.
Combined with the proceeds from minor non core asset sales that closed during the quarter, our total excess cash inflows exceeded $300,000,000 in Q3. Moving to slide 9, I would now like to provide an update on the initiatives underway at Devon to strategically deploy the excess cash inflows we have generated year to date. I'll begin with our $4,000,000,000 share repurchase program, which at current prices represents about 20% of Devon's outstanding common stock. As of today, we have repurchased approximately 67,000,000 shares at a total cost of $2,700,000,000 We now expect to complete our $4,000,000,000 share buyback program during the Q1 of 2019. In addition to our share repurchase activity, we are also returning cash to shareholders with growth in our quarterly dividend payment.
Earlier this year, we raised our dividend by 33% and with continued growth in our operating cash flow, owners of Devon can expect both a sustainable and growing dividend over time. And finally, I'd like to highlight the significant progress we made strengthening our investment grade financial position. Year to date with the retirement of upstream debt along with the sale of our interest in EnLink, we have reduced Devon's consolidated debt by more than 40% to $6,000,000,000 Additionally, we expect to further reduce our leverage over the next months with the retirement of an incremental $257,000,000 of maturing debt. With strip prices where they are today, we are within our targeted net debt to EBITDA ratio of 1 to 1.5 times and expect this ratio to trend lower as we execute on our multi year plan. So in summary, we have made significant progress executing the disciplined financial strategy associated with our multi year business plan.
Looking to 2019 and even into the next decade, we will continue to prioritize the return of cash to our shareholders along with evaluating opportunities to further strengthen our investment grade financial position. With that, I'll turn the call back over to Scott for Q and A.
Thanks, Jeff. We will now open the call to Q and A. Please limit yourself to one question and one follow-up. If you have further questions, you can re prompt as time permits. With that operator, we will take our first question.
Your first question comes from Subash Chandra with Guggenheim Securities. Please go ahead.
Yes, thank you. Hi, good morning everybody. My first question is on an update on the non core asset sales sort of so the divested assets you've shown in your ops report, the timing and proceeds, for instance, I think the Midland EOR was something that was expected near term. Second, if there have been conversations with BPX Energy in the Eagle Ford. And third, your thoughts on Canada, which you referred to in your prepared statements, but thoughts on valuation of your Canadian assets given the Husky MEG situation?
Subash, let me try to remember all those. But I think first on the non core On the non core divestments, you can look at Slide 10 of the operations report that gives you more detail on that. But we still have 2 data rooms open, the CO2 floods up in the Rockies and then in the Central Basin platform, our production up on the Central Basin Arch of the Permian Basin. So those data rooms are both open. You can see the scale of those divestments.
We have on the floods in the Midland Basin, we have made a decision to divest the operated portion of that and to retain the non operated portion at this point based on valuations that we received for those assets. So that process is essentially concluded. But that's the remaining those two assets are the ones that will reach the $5,000,000,000 target. Secondly, in regard to maybe Canada, I'm trying to remember the third one here question, but with regard to Canada, obviously I'm sorry, go ahead, Subash.
I was just going to say that third one was, yes.
BP. Yes. And let me cover that one first. And we have had some very constructive conversations with BP early on. We no firm commitments at this point, but we think it is very likely that we'll be moving to a 3rd rig in the Eagle Ford.
And I can tell you that all the conversations we've had so far have been constructive and positive, and we look forward to with them on that position. So really all good news from that front. On Canada, obviously, there's an attractive valuation, I think, that Husky made for MEG. I think you better obviously talk to them on the basis of that valuation and why they made that offer and what made that offer unique for MEG and why they're uniquely interested in the MEG assets. But obviously, we think that is a marker that shows the long term value of the assets that we have up there.
So I think it was an interesting number and it shows the value we have.
Right. Well, thank you. And my follow-up is, could you just elaborate in the STACK pilots, you talked about the flowback strategy in Bernhardt. And if you could elaborate on that and if that particular flowback strategy, which seems to have hurt the performance was also used in some of your other pilots?
We're going to have Wade Hutchings, who is the Senior Vice President in charge of that area talk about that. Wade?
So I think at a high level what I would note is the flowback strategy we used on the showboat program was very similar to what we've done on past wells. We concluded that we may have been a little bit too aggressive on this. What we tested on Bernhardt and Horsefly is a bit more measured flowback approach. The early indications from that are is that it's still in the process of getting oil decline rates broadly looks positive in terms of operational. You'll see us continue to optimize that as we move
Okay. Thanks, everyone.
Your next question comes from Arun Jayaram with JPMorgan. Please go ahead.
Yes, good morning. Arun Jairam from JPM. I had a quick question on how you're thinking about light oil growth outside of the Delaware in 2019. I think you highlighted a 40% oil growth target for the Delaware, but how are you thinking about the Eagle Ford stack and Rockies?
Arun, this is Scott. At a high level, obviously, you hit on it right that Delaware is going to deliver the most significant growth. Obviously, we highlighted in our operations report as well that the STACK will be a contributor to that growth as well from an oil perspective. It's a bit too early for us to give any sort of firm guide with regards to Eagle Ford. We're still working with our partner VP on that particular budget, and that should come out here early next year.
And Rockies, you'll see growth in the Rockies as well, especially as we start to ramp up activity level that Dave talked about and Tony have talked about in their portions of the scripts. So you'll probably see that start kicking in, in the around the mid year time frame. But with regards to the specific targets beyond what we put out for the STACK in Delaware, we'll firm up that guidance here in our Q4 call and with what we typically do, which would not only be capital for each asset but also the amount of wells we plan to bring online that supports that growth profile.
And as you say Arun, the biggest
driver of the U. S. Oil growth is going to be the Delaware Basin. Now
I growth. As you say, Arun, the
biggest driver of the U.
S. Oil growth is going to be
the Delaware Basin. Now I do want to make clear that the we do have some growth expectations in there for STACK oil in 2019 as we are now feel we have understanding much better of what the optimized spacing is And our oil growth that we have built into our 2019 projections for STACK is based on optimized spacing of 48 wells per drilling spacing unit.
Got it. Got it. Dave, you highlighted a series of kind of initiatives to mitigate some of the margin risk that you have in heavy oil. I was wondering if you could maybe comment on the firm transportation to the Gulf Coast as well as the rail potential? And how do we think about the uplift you can get from both of those initiatives relative to what we see in our screens in terms of WCS pricing?
And I'm going to let our real expert here in the room do that, Arun, as Kevin Lafferty is in charge of our marketing efforts.
Good morning, Arun. This is Kevin. First of all, on the capacity comment that we have going to the Gulf Coast and we have previously talked about this, but we have about 10% of our blended barrels that we have firm capacity. It's on the Enbridge system and when they had the open season several years ago on the Flanagan South piece of that. So we are able to move those barrels all the way down to Houston and that's been a part of our portfolio here for several years now.
On the rail side, what we're trying to do here, really the big picture is we're taking a portfolio approach. This is no different than how we have viewed the Delaware or the Mid Con or any of our assets with every single product. So we use a combination of local sales, sales to other people that have firm, financial hedging, export, etcetera. So we're aggressively trying to find rail solutions. And the complexity of it is that it requires transportation of your barrels to a terminal.
You need to have tankage to be able to load into the railcars or the unit trains. Sales, of course, on the other end and then putting all those pieces together to get this to move. But we see rail being a part of our portfolio for several years to come and really to bridge and de risk any mitigation of Keystone XL or Trans Mountain expansion in the future.
Great. Thanks.
Your next question comes from Bob Mora with Citi. Please go ahead.
Thank you. Dave, looking at the stack here, the Show Boat, I know last quarter the IP30s were running only about 15% below your parallel type curve of 1.9 to 2.2 MBOE. Although the IP90s this quarter look further below given a lot higher decline. But the Coyote IP90s look a lot closer to that parent well type curve. So if you go to 4 to 8 wells per section, what range of degradation versus that parent well type curve would you expect here going forward?
And for reference, I know one of your peers here a few quarters ago noted about a 30% degradation in going to 4 wells per section per zone. So how do you view that then going forward in your program?
Bob, this is Wade Hutchings. I'll take that one. First, let me clarify for you that the Coyote area there on the northwest side of the play, really a very unique reservoir. It's actually the lowest Meramec zone. As you saw quarter over quarter, we saw really strong well performance out of all of the wells we've put in there.
We like that area a lot, but our primary focus has been on the core of the play in the volatile oil window, showboat and South, if you will. And the reservoirs there are actually different targets than what we're seeing at Coyote. So we broadly are seeing EUR and even IP degradation in infill mode. That's clear. We're not ready to give a new type curve today because the wells that we have coming online in the 4th quarter are really critical for us to narrow down what this new 4 to 8 well per section well expectation will be.
We of course have an internal model that we're tracking against. The early results we're seeing here in the 1st part of Q4 are encouraging. They're essentially confirming that our approach at this lighter density spacing is working. I think if I just step back a little more broadly and indicate with Bernhardt and Horsefly, those two projects confirmed a lot of what we already saw at Showboat. And so just to remind you of that Upper Meramec performance much stronger than lower.
The impact of parent wells is important. And so being able to space the wells commensurate with where the parents are is critical. And then lastly, we saw more communication between the upper and lower targets than we expected. So as we move forward with the programs that are going to come online in the Q4 and into next year, you'll see us essentially do 3 key things. What we're doing is focusing most of the wells in the Upper Meramec.
As Tony noted, over 75% of the wells in the forward, say, 6 to 9 month program will be Upper Meramec. The second thing we're doing is we're adjusting the spacing for the parent wells in a way that we're trying to mitigate their impact. And then lastly, we're driving our stimulations to a much more tailored limited entry approach that really is fit for purpose for every reservoir target we're landing in. We're confident that that's going to give us results that come back closer to that original type curve expectation. And the last key point is, as we've driven the per well cost lower, we're able to maintain the capital efficiency and rates of return that we expected as we moved into infill mode.
Great. Wade, that's great color. I appreciate that. Second question, just on Canadian production shut ins. I think currently you're shutting in around 25,000 barrels a day and I know that's sort of a month to month decision here as the price differentials move around.
But given that this is SAGD, is 25,000 barrels a day on a quarter of your total production up there sort of the max that you can shut in without really causing issues with how the steaming works up there? Or is there more that you could potentially shut in as you go forward here?
Bob, this is Tony here. I think you've kind of summed it up right is the 25,000 barrel a day curtailment that we have chosen to employ on this month to month decision is really predicated on the wells that we have reduced steam to or those that would be more capable of recovering back to original rate the quickest. And so we feel comfortable that we're not incurring operational risk. We think we're going to be able to put oil back into the pipeline within 5 to 10 days at the time we decide to put full steam back to it. So right now, the 25,000 barrel a day range is really about the area that we feel most comfortable with at this point.
There is ability to increase that that carries on additional risk with that associated with winter type activities, managing the pressure, managing steam chamber and some other variables of that. So just as you initially stated, the 25,000 barrels a day is a real comfort zone for us.
Great. Thank you. Appreciate it.
Your next question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Thanks. Good morning, everybody. Dave or Tony, I wonder if I could take you back to the Delaware for a second and talk a little bit about your plans for 2019. Todd looks like it's going to feature fairly prominently, but as I recollect, the Todd area is over pressured. It's a little deeper.
It's potentially got substantially better well type curves than your development program to date. So I wonder if you can speak to how should we think about the rate of change in your incremental well performance as you go into next year? And I'll take my second question as well as a follow-up if I may.
Great. And then Doug, I'm going to have Rick Gideon. Rick, answer that. Rick is our Senior Vice President in charge of the Delaware, so he can give you the best detail on that.
Hi, Doug. This is Rick Gideon. Great question. As we look into next year and if you take a look at Slide 11 and 12 in our ops report, you'll see we've also had great results out of the Wolfcamp in our Cotton Draw area in our Lusitano. You can see our Wolfcamp averaged 4,000 600 BOE a day IP30s in that given area.
And as you stated, there will be growth in the Todd area. You can see the 2nd Bonestrip Springs. I think you'll see focus in the Rattlesnake area along with the thistle area and Cotton Draw also. So we will be spreading out our program to reduce risk as we execute through there. I think you'll see a pretty balanced program, Doug, between whether it be and I'm going to talk a little bit in pressure tanks, whether it be your Leonard, your Bone Springs or your Wolfcamp, you'll see a pretty good balance as we move through that program.
As far as increased productivity, you've seen the step change improvements in 2018. We're going to continue with those improvements and hopefully continue to see that type of growth as we move into the next year.
Guys, I don't want to press too much on this, but the guidance you've given for next year, you haven't been explicit about exit to exit, I guess, coming out of the Delaware. And this is my follow-up actually, but I wonder if you could maybe just touch on what you think that might look like because given the substantial improvement, Rick, in the productivity, it's a little tricky for us to figure out. Frankly, I think you maybe end up being a little conservative if these type curves play out the way we think they are. But what I'm really getting at is, can you give us some kind of an idea what that exit could look like and whether your flow assurance still covers you on the kind of rates you could leave you could exit 2019 with at that point?
Doug, this is Scott. Obviously, we'll firm up some of those targets as we head into our Q4 reporting for you. What I can tell you obviously is that directionally from just the cadence of the growth throughout 2019, you can expect a pretty steady ramp up throughout the year. Won't give you necessarily any proportions there, but it's a pretty consistent stair step each quarter as you go through 2019, a very healthy profile. But with regards to any sort of specific targets beyond what we provided today, we're still in the process of refining well selection and activity plans, and we'll provide a more holistic update here on our Q4 call.
Scott, can you touch on the flow assurance issue at the exit of 2019?
I'm sorry, Doug, you cut out there.
Sorry, can you touch on the flow assurance at the exit rate coming out to 2019? I'm guessing you're getting added go on, sorry.
Well, yes, I would Kevin can talk about it. But I mean the bottom line is here that we have everything in place to execute the program. But Kevin can talk to you a little bit more about the gas takeaway and processing, etcetera.
Dave is absolutely right. On Slide 13 in the upper right, this is where we lay out a lot of the things that we've done and we've talked about previously, especially on oil. And so we feel really good about that with all the incremental pipes coming online from cactus to you name it over the next couple of years. On the NGL side, we also feel very comfortable even with the Epic conversion that we think there's plenty of NGL capacity and we have access not just getting out of the basin, but also to Mont Belvieu as Jeff had previously described. And on the gas side, even though we don't have firm, we still feel confident and comfortable that we have local sales and sales into the Western Coast going to the SoCal type of markets with people that have firm and they are actively allowing us and telling us that they have room for growth for our 2019 plans.
So we feel good about every single product and we'll be able to get it out and get values as best we can throughout 2019 and beyond.
And of course beyond that we have one of the most extensive water handling infrastructures in Southeast New Mexico and the permits are in place essentially.
Your next question comes from Phillips Johnston with Capital One. Please go ahead.
Hey, guys. Thank you. Just to follow-up on Subash's question on Canada. You guys have highlighted over the past few years Canada maybe an asset that could make sense to eventually monetize while also recognizing the challenge of getting maximum value. I assume that's still the case in the very near term just given the price environment.
But as we look out to a time of improved pipeline and rail takeaway and more normalized pricing, has the appetite grown at the Board level to get more aggressive in pursuing a potential sale?
Well, I can tell you, we have an active discussion about Canada and every other asset in our portfolio at the Board level on an ongoing basis. And the one thing that there are some I would say there are some positive attributes to the Canadian position. We obviously have won the premier positions in the SAGD and our Canadian team has done an outstanding job operating that asset through the years. And it certainly is the type of asset that in a normalized differential environment can provide the type of free cash flow each year that would be very helpful in a portfolio to offset the higher decline on conventional business. Now we obviously recognize that we are not in that environment right now with the high differentials that we are.
And that certainly we have an active discussion on this asset relative to that. We understand, but it is a reality right now that it is one of the more challenged times to even think about monetizing that asset because of the very large differentials that we're currently encountering. So it is a discussion. There's I think there's been if you look at the company historically, we've done about 30,000,000,000 dollars worth of transactions over the last 10 years. So I don't think there's a lack of willingness in general to do what we consider is in the right interest of the company.
It's just a matter of what truly is the right interest of the company given what the asset position is, what the market for the assets are, etcetera, and just making sure we're making the right decision.
Okay. And then, yes, I mean, it's clearly an asset that, as you mentioned, generates a ton of free cash flow in a more normalized price environment and it is low decline. So you obviously can't comment on valuation levels. But in a theoretical sales scenario, would the multiple need to be higher than where your stock is currently trading? Or would you be willing to sacrifice some level of EV to EBITDA dilution just in order to sort of streamline the portfolio to an asset base that has a naturally higher inherent growth rate?
Hey, Phillips, this is Jeff. Yes, of course, we think of all those things as Dave talked about as we evaluate these assets for potential monetization and acceleration of the value proposition. Clearly, to the extent that we can, we look to monetize assets at multiples that are above our current valuation. But there's as you know, there's a lot of complexities and factors that we think through and discuss with our Board, especially on an asset like that, how
eventually be sold, would you be willing to take a mix of stock and cash or would you look for an all cash deal?
Well, I think that gets into the details of the transaction. But obviously, we're longer term interested in returning value to our shareholders. And so we'd have to think about if we took stock, how could we turn that into value for our
shareholders. Great. Thank you, Dave.
Your next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning. Philosophically, when you look into 2019, how do you consider your willingness to raise CapEx in the event oil prices are higher or lower CapEx in the event oil prices are lower? Is that $2,400,000,000 to $2,700,000,000 kind of fixed above which if cash flow surprises to the upside, that all goes to shareholders? And how do you think about the downside case?
We fundamentally believe that a consistent capital program are the or one of the keys to driving high returns on our capital program. So we do not foresee significant changes to the capital program either higher or lower unless we have a tremendous surprise, certainly more on the lower side than the higher side. And of course, the one thing that we're monitoring very closely in regard to that is Canadian differentials and then what impact that may have on the cash flow for the company. But I do not anticipate us raising our capital program as in if prices are significantly higher. That's as we said in the prepared remarks, we think it's more important to have a consistent program.
We'll deliver the highest return and cash flow above that would be directed towards return to the shareholders either through share repurchase most likely through share repurchases and then through time through an increasing dividend.
Great. Thank you. And then my follow-up on the Delaware Basin, one of the things you highlighted was the drop in human LOE costs. Can you talk about the trajectory there and where you see the opportunity for that to go in 2019 or beyond?
Absolutely. This is Rick Gideon again. We talked about the 10% to 15% decrease, which what I hope you remember is over the last few years, we've provided and put in place the infrastructure from an electrical standpoint, from a water handling standpoint and then from a takeaway standpoint, just as Kevin had talked about earlier. But I can tell you over the next quarters, you'll continue to see a step rate change quarter on quarter. And as we move into 2020, the same just due to volume increases and the infrastructure being in place.
Hey, Brian, this is Scott. Just to provide a few figures to that. With regards to our LOE in the Delaware, we've been running anywhere from $7 to $8 probably $7.50 to $8 this year. And so certainly, we'll take a step change down next year. And as Tony talked about in his remarks, it could be upwards of 15% 10% to 15% lower when you look to 2019.
So certainly, margins will continue to expand in that high quality play.
Thank you.
Your next question comes from Ryan Todd with Simmons Energy. Please go ahead.
Great, thanks. Maybe a follow-up on usage of this cash from earlier. I mean, it would appear that at least on our numbers, the decision not to redeploy some of the cost savings from reduced stack activity in 2019 is consistent with your commitment to sustainably grow cash distribution to shareholders. With expected completion of the $4,000,000,000 buyback program in 1Q 2019, how should we think about the potential to maintain an active buyback program going forward versus balance with dividend as a method of returning cash to shareholders?
Yes, this is Jeff. No, that's as Dave said in his opening comments, that's absolutely our expectation. As we generate additional free cash flow in 2019 and beyond, number 1, we're always going to make sure the balance sheet is in a spot that we feel comfortable about. We're good there. We feel really good about the targets that we've hit from a financial position.
Our next look is obviously to talk about the dividend growth with our Board, which we do each year. And then beyond that, it's more share repurchase. So we'll look again to go back to our Board for additional authorization beyond the $4,000,000,000 we've already done to utilize that cash for a return to shareholders.
Great. Thanks. That's helpful. And then maybe one follow-up on the STACK. I know know you said you're not ready to update the type curve at this point, but you have given us a 2019 kind of budget and production profile for the STACK.
Can you maybe give us a rough idea of what you're assuming in terms of well productivity and well costs versus recent results for next year's plan and maybe how that how your confidence and how conservative you feel that number is? And maybe, does it assume a similar oil cut versus the current STACK production?
Ryan, this is Wade. I think a couple of pieces of context for you. The first order control on our performance here is getting the well spacing right. And so all the tests we've been doing, all the work we've been monitoring from industry results have been geared around getting that right. And you're now seeing us narrow in on what really is reverting back to our base case well spacing of 4 to 8 wells per section.
That's the most important thing for us to get right. We're now quite confident that we've got that band identified. In terms of expectations for next year, certainly baked into all the guidance you've saw come out is a revised view of what that lower well spacing, lower density well spacing will yield. We're not going to reveal any new details of the type curve yet. That will come early next year as we get these 4th quarter wells under our belt.
I would say broadly though, we are expecting strong performance out of these future programs, certainly stronger than what you saw far out of our higher density well programs. And so that's what we're going to be tracking internally on both IP EUR and even oil cut. But I think the key is we're confident based on wells that we already have in the ground and producing that when you space these properly, when you offset them from the parent wells and you stimulate them in a targeted way that we'll get strong results. I think from a capital side that was part of your question as well. You'd certainly look to the results that we've delivered on Bernhardt and Horsefly as good guides for the ballpark we're aiming for next year in our infill Meramec programs.
Without going through a lot of detail, of course, as we sit here today, we're nearly halfway through the Q4. And so you can imagine we've brought online nearly half of the wells we plan to in the Q4. And so there is some basis in fact based on the production data that we've seen to date with the wells that we brought on based on these 4 to 8 wells. It's still early
Thanks. I appreciate the additional color.
Your next question comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Dave, to you and your whole team there. I wanted to just chew on this stack spacing testing a little bit more. And you guys have given a lot of detail, but I just want to see if I could add a little bit more to it. You guys talked about going to 4 to 8 wells per DSU. And it also sounds like you are going to be your most of those are going to be Upper Meramec, but they're not all exclusively Upper Meramec.
So can you talk about how many different landing zones you're going to be looking at when you go from 4 to 8 wells? And is it the case that when you're talking 4 wells, it's 1 landing zone and when you're talking 8, it's 2?
Yes. And another I'm Wade will cover this, but I'll help him out a little bit here to start too. Remember the geology changes as you move across the STACK 2. So what is the optimum zone to drill and complete in as you move across the Meramec isn't necessarily the same across the entire play. So that's part of the answer to it.
And Wade, you can go from there.
Yes. Thank you, Dave. That's absolutely true. I think to limit the complexity of my answer, I'll just focus on the core volatile oil sweet spot of the play. There still are literally 3 or 4 landing that we evaluate for every one of those DSUs.
One of the key things though that we've learned from our early infill pilots is that those zones are communicating certainly upon fracture stimulation and it also appears communicating on a pressure basis during production. So now we really are looking at that Meramec interval as one reservoir compartment and that's really influencing how we are moving forward to develop it. Now specifically, you've already heard us note that the Upper Meramec has generally had much better well performance than the lower, particularly as we've moved into infill mode. And so we will bias over 3 quarters of the wells to the upper. But where we see a viable lower Meramec target, we will on a case by case basis put 1 or 2 wells in that in a DSU.
And so yes, you're generally correct. Getting up near the high end of that 4 to 8 well spacing likely means that we would spread the wells across 2 zones. The lower end of that spacing is much more likely to be focused just on the upper Meramec.
Got it. That's helpful.
It's based on the reservoir is what is the answer, which obviously you don't have all the data to see why we make those calls, but that's the bottom line is what reservoirs are developed where.
Yes. And I think the last thing I would add to that Charles is we are also customizing the stimulation approach on a well by well basis depending on if it's an upper Meramec or a lower Meramec well, depending on what the, parent well conditions are in that particular interval. And so we're literally taking every bit of data that we've collected over the last several years and optimizing stimulations on a well by well basis.
Got it. Got it. And Dave, I was
going to say, you've talked about this before in previous quarters, particularly with those Coyote wells up to the Northwest that those are not as tightly spaced because of the reservoir properties. But if I could just my follow-up to that would be, and this may be a stretch, but how much of what you have learned in this in your development experience here in STACK, how much of that is applicable to what you guys are doing in the Delaware Basin? And is it changing your appetite on your development plans in any way as we look at that basin?
Well, I'll let Tony talk to you about this in greater detail. But this is philosophically speaking and this is going to vary from area to area, Barrett, the parent child issues that we're talking about here in the STACK play are not unique to the STACK. They are going to be present and they have been seen in every unconventional play to one degree or another. And what has happened here is we've reached a, let's say, from an aerial extent, it's not as large as some of the other plays. And so you've been seeing historically a lot more apparent well results from, for instance, in the Permian Basin and you haven't reached the degree of maturity in these other basins that you have in the STACK.
And so we are now it also depends the degree to which it applies depends on the reservoir property. So it's not equally applicable in every play, but the basic phenomena is certainly there. And it's something that we are transferring these learnings immediately to all of other plays. Tony, you have a lot more detail than I do on that, but I think it's a very relevant question not only for Devon for the entire industry.
Charles, I think you followed us for a long time, and so you're aware that we participated in multiple unconventional resource plays. And we've been through the same exercise in every single play that we've been in. So we've been transferring learnings from the probably the +5000 lateral wells that we've drilled across our library of information. And we knew this question was coming at us in the STACK play and the positive work that we have done as we've uncovered and feel like we now understand the optimum development scenario inside of really inside of a calendar year for the most part. And so we've reacted quite quickly there.
In comparison to other resource plays that industry has participated in, you saw a much more prolonged painful experience in plays like the Eagle Ford. So we're responding quite quickly. The positive things about the Delaware as Rick mentioned earlier that there's 3 different pressure tanks that the guys have identified and the column of resource there is quite thick and the aerial extent for our plays is more spread than what we have in STACK. And so we feel like the risk associated with learnings in the Delaware is less and it's going to come over time. But the guys have done a really good job and they're quite aware of the learnings that the STACK team has had.
And so we've talked in the past, Charles, about being a very data driven organization and we feel like this is an area that we're able to capitalize on that pretty quickly.
Thank you for that in detail.
Your next question comes from Paul Grigel with Macquarie. Please go ahead.
Hi. I was hoping you guys could touch
on Powder River Basin takeaway as you build into the 2019 program both on gas and oil and then also in the Mid Con and in the STACK on any gas takeaway visibility that you have on potential constraints or how you feel dealt with those issues going forward?
Hi, Paul.
This is Kevin. First of all, on the Rockies, we feel really good just similarly to our other assets that we have ample takeaway. And in fact, I want to highlight on the Rockies page in our ops report that we have contracted our oil price, even though recently it's blown out similar to the Bakken. We have contracted at really good numbers and protected our price there through our contracts. So we feel good about gas, gas processing, takeaway NGLs, the entire product mix up in the Rockies.
Moving to the Mid Con, we do have a lot of gas in Oklahoma and that is something that we have operated here for a long period of time and we know all the markets and the players and the midship pipeline with Cheniere that comes online here in 2019 will provide a lot of relief. So we are working the markets aggressively to make sure that we use our firm sales and every other avenue to clear the Mid Con. Moving over to oil in the Mid Con, we have access to the Gulf Coast via our market link transportation capacity, and we have ample access and availability for NGLs as well. So again, all of our areas, we feel very comfortable and convicted that we have plenty of room for takeaway and pricing for every single product in every basin.
Great. Thank you. And then I guess a higher level one. Could you guys detail what the price deck is for your initial 2019 budget? And then as you think not only into the full 2019 budget, but into the full turn of 2020 plan and beyond, is that a fixed price that you use going forward?
Or is that willing to kind of float with the market, as it may dictate?
Well, when we looked at our about a year ago, we talked about a capital program based on a $50 oil $3 natural gas price and that we wanted to have a steady program based on that. So when you look at and built into that though was the fact that we are going to be building our cash flow as we continue to grow our light oil high margin production. So and even in that flat $50 oil, dollars 3 price deck, we had a little bit higher capital in 2019 than we had in 2018, higher in 2020 than 2019, etcetera. And that's where we are today. So when we look at it, we have really the 2019 program that we have laid out really is consistent with what we thought we were going to do in 2019 a year ago.
And that again goes along with our philosophy that we think that we produce the highest returns when we have consistent plans relative to capital. Now what the actual cash flow is for the company obviously is subject to current pricing differentials, etcetera. But when you look at how we think about capital, it has not changed.
Great. Thank you.
I show we're at the top of the hour. I appreciate everyone's interest in Devon. And if we didn't get to your question today, please don't hesitate to reach out to the Investor Relations team, which consists of myself and Chris Carr. Have a good day.
Thank you. This concludes today's conference call. You may now disconnect.