Welcome to Devon Energy's second 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 Coody, Vice President of Investor Relations. Sir, you may begin.
Thank you. 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. Then I'll turn the call over to our President and CEO, Dave Hager. Dave will provide his thoughts on the strategic direction of Devon, which we have branded as our 2020 Vision, and commentary on the next steps associated with this multi-year business plan.
Following Dave, Tony Vaughn, our Chief Operating Officer, will cover a few key highlights and operating themes that are central to delivering our multi-year development plans. Then we will wrap up our prepared remarks with a review of our financial strategy by Jeff Ritenour, our Chief Financial Officer. Overall, this commentary should last around 15 minutes before heading into Q&A. I would also like to remind you that comments and answers to questions on this call today will contain plans, forecasts, expectations, and estimates that are forward-looking statements under U.S. securities laws. 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-K.
With that, I will turn the call over to our President and CEO, Dave Hager.
Thank you, good morning, everyone. The second quarter was another strong one for Devon. We are executing at a very high level on the strategic objectives underpinning our three-year business plan, otherwise known as our 2020 Vision. For today's call, my comments will be centered on the significant progress we have made year-to-date toward our 2020 Vision, I will also touch on a few of the critical next steps associated with this differentiating multi-year plan. Turning to Slide 2, the next item I'd like to cover today is the outstanding performance of our U.S. resource plays, which have consistently delivered light oil production results above our base plan year-to-date. This outperformance has been driven by the record-setting well productivity we have achieved across our franchise assets in the Delaware Basin and STACK.
During the second quarter, the momentum from high rate wells drove U.S. light oil production 12% higher than the previous quarter, exceeding guidance by a wide margin. With the strong well productivity we've achieved through the first half of the year, light oil production is on track to advance 16% in 2018. This represents a growth rate that is 200 basis points above our original budget expectations heading into the year. Overall, we're off to a great start in exceeding the light oil objectives associated with our 2020 Vision. Importantly, we are delivering this incremental production growth within the confines of our original capital budget guidance range. With our go-forward capital plans, I also believe it's worth highlighting that even with the recent rise in oil prices, we have no plans to add incremental activity in 2018.
While we have a very deep inventory of highly attractive growth opportunities within our portfolio, we fundamentally believe that a more measured investment program through all cycles is the correct strategy to manage costs, efficiently expand our business, and the appropriate pathway to deliver attractive corporate-level returns for shareholders. The next key message I want to convey is that Devon's cash flow generation is trending ahead of our budgeted expectations. In fact, with current strip prices, we expect to increase our upstream cash flow by more than 50% by year-end compared to where we started the year. Furthermore, after expected capital requirements, we are in position to generate free cash flow in the second half of the year.
While the advancement of our U.S. oil volumes is certainly a key contributor to this cash flow growth, our operating teams have also done a great job maximizing the value of every barrel we produce. Some of the best work we have done is on the pricing front, where our marketing teams have provided both flow assurance and access to premium pricing on the Gulf Coast for the majority of our U.S. oil production. Tony will discuss this topic in greater detail later in the call, but after including the benefits of firm transportation and attractive regional basis swaps, our light oil realizations year-to-date are essentially in line with WTI benchmark pricing.
Looking ahead, we are well positioned to maintain this strong pricing in the second half of the year, which is very much in contrast to the weak regional pricing and takeaway constraints that have become a serious issue for many operators. In addition to strong price realizations, another key factor further supplementing our cash flow growth is the aggressive improvements we are taking to our cost structure. With the actions we have taken year-to-date, we are now on pace to reduce G&A and interest costs by approximately $475 million on an annualized basis. These substantial savings, combined with an improved operating cost across our U.S. resource plays, will continue to put downward pressure on our per-unit costs through the end of the decade. With our Delaware Basin and STACK assets rapidly building momentum and operating scale, another critical component of our 2020 Vision is to further high-grade our resource-rich portfolio.
During the quarter, we took a significant step forward with this strategic objective by selling our interest in EnLink Midstream for $3.125 billion. This highly accretive transaction provides a complete exit from our investment in EnLink at a value of 12 times cash flow, a substantial premium to Devon's current trading multiple. With the closing of the EnLink transaction, which occurred in mid-July, combined with other minor asset sales achieved to date, Devon's total proceeds from our divestiture program have now reached $4.2 billion. The next step in this program is to monetize an additional $1 billion of minor non-core assets across the United States by around year-end, which would boost the proceeds from our divestiture program to more than $5 billion. Consistent with the framework of our disciplined multi-year plan, we are returning these divestiture proceeds to our shareholders in the form of a share repurchase program.
In June, our board authorized an increase in our share repurchase program to an industry-leading $4 billion. While Jeff will provide more details on the progress of our share repurchase program later in the call, I will say that our buyback efforts have reached approximately $1 billion through the end of July, given the value we see in our equity, we plan to accelerate the cadence of our share repurchase activity through the rest of the year. To summarize, I could not be more pleased with the execution we have delivered to date on our 2020 Vision. Our light oil production is running ahead of plan. Our margin and cash flow are rapidly expanding. We expect to exceed our $5 billion asset sale target by around year-end, we are returning industry-leading amounts of cash to our shareholders.
Briefly flipping to slide three, while I'll not cover all the details on the slide, I do want to be clear, we are not content with the substantial progress we have made to date. The management team at Devon is laser-focused on optimizing returns and ensuring capital efficiency for our shareholders. We will continue to attack costs and transition our product mix towards higher-margin barrels. We will be disciplined with our capital allocation and generate significant free cash flow. We will continue to evaluate strategic opportunities to high-grade the portfolio, we will continue to prioritize returning increasing amounts of cash to our shareholders. Lastly, before returning the call over to Tony, I do want to touch on a topic we've field a lot of questions on recently, that is our thoughts on BHP's announced sale of its Eagle Ford position.
Overall, it's good to see a quality operator like BP acquire this position. We have had extensive experience working with BP in the past, both as partners in projects and on multiple asset sales as well. Since the announcement, we have not had any in-depth conversations with BP, so it's still a bit too premature to provide any commentary regarding the strategic direction of the assets at this point in time. However, for the near term, we do not expect any meaningful change in the activity levels that underpin our guidance for the second half of 2018. From a portfolio perspective, we do like our Eagle Ford position. DeWitt County is the economic heart of the play, and we have a multi-year drilling inventory that can generate outstanding returns, a stable production profile, and significant free cash flow for Devon.
We look forward to discussing the future of the asset with our new partner, BP. With that, I'll turn the call over to Tony for additional commentary on our operations.
Thank you, Dave. I'd like to begin by covering a few noteworthy operating highlights for the quarter. A great place to start is on slide four with our Delaware and STACK assets. These delivered 54% and 41% oil growth, respectively, year-over-year. This prolific growth was the driving force behind our U.S. oil production beat in the second quarter. The strong performance in the quarter was driven by another batch of prolific well results across the U.S. While the massive Boundary Raider wells stole the headlines last quarter, our Cotton Draw program topped the Delaware Basin highlight list in Q2 with a four-well package that achieved a combined 30-day IP rate of 14,000 BOEs per day. We also had several other prolific wells in the Delaware, with our top 10 wells for the quarter averaging 30-day rates greater than 3,000 BOEs per day.
Our other franchise asset, the STACK, also delivered strong operating results in the quarter. Top wells in the play continue to routinely deliver initial production rates in excess of 2,000 BOEs per day, and the efficiencies associated with the Showboat and other initial infill projects are compressing cycle times and driving first production well ahead of plan. While we are still in the early days of evaluating the performance of our Showboat infill project in the STACK, we have attained peak project rates. The average well at Showboat normalized for 10,000-foot laterals attained 30-day rates of approximately 1,800 BOEs per day. With this upside spacing test from spud to initial flow rates, this project has largely exceeded expectations. However, based on early observations, it appears this development concept is not optimized for rate of return and is likely spaced too densely.
With our initial three infill projects, Showboat, Horsefly, and Bernhardt, we are testing 12, 10, and eight wells per drilling unit. We intend to rapidly deploy the learnings from these initial spacing projects and our extensive library of information to optimize future STACK development plans. When I say optimize, I mean striking an appropriate balance between the rates of return and the net present value with our future activity, with a heavy preference towards enhancing project rate of returns. Next, I do want to make clear that the strong well productivity achieved during the quarter was complemented by expanding margins through both strong price realizations and improvements in our per-unit operating cost structure. Additionally, we were able to effectively control our capital spending, which declined nearly 10% from the previous quarter. In Canada, I want to commend the teams on our successful and safe turnaround work at Jackfish 1.
While the turnaround efforts identified additional maintenance work requirements that delayed the facility ramp-up into the third quarter, this work will improve future operating efficiencies and allow our production to increase as the second half of the year progresses. All in all, our operations have delivered great results year to date, and we are well-positioned to execute on the multi-year operating plans associated with our 2020 Vision. On slide five, a key component of this strong execution that should not be overlooked is the operational planning and supply chain efforts to ensure the certainty of services and supplies necessary to deliver on our capital plans. First, I want to highlight that these efforts have largely mitigated industry inflation in 2018 and have allowed us to execute on our capital plans within the confines of our original capital guidance provided late last year.
With the aggressive steps we have taken to decouple historically bundled services, combined with our teams utilizing a much more diversified vendor universe, our strategy to achieve the best value for our LOE and capital dollars is working quite well. In fact, the vast majority of our services and supply requirements have been locked in through 2019. We are confident in our ability to keep rising industry costs in check at well below market rates through the end of the decade. This value-oriented approach is only available due to our detailed field development plans for each of our asset areas. Moving to slide six, another area where we have done a lot of good work is in our marketing and flow assurance strategy, which provides the majority of our U.S. production direct access to premium Gulf Coast markets.
Specifically in the Delaware Basin, we have been able to price-protect 90% oil volumes through firm transportation and attractive regional basis swaps. From a flow assurance perspective for our in-basin sales, we have contractual guarantees to flow 100,000 barrels per day through our legacy firm sales agreements that extend well into the next decade. All in all, these physical and financial swaps in the Delaware will allow us to maintain price realizations near that of WTI pricing. We are also well-positioned in the STACK play. Through firm transportation on the Marketlink Pipeline, approximately 75% of our oil volumes have direct access to premium Gulf Coast pricing. Also, we have firm transport agreements covering the vast majority of our gas production in the STACK. Coupled with basis swaps, we have effectively protected the price on the majority of our gas volumes.
The last area I will touch on is our attractive WCS hedges in Canada. In 2018, we have roughly half our production hedged at $15 off of WTI. In summary, with this good upfront planning work from our operations, supply chain, and marketing personnel, we are well-positioned to maximize the value of our production in a tight market. With that, I will now turn the call over to Jeff.
Thanks, Tony. For my prepared remarks, I will provide an update on the shareholder return initiatives underway at Devon and discuss the next steps in the execution of our financial strategy aligned with our 2020 Vision. Moving to slide seven, I'd first like to cover how the sale of EnLink impacts Devon's financial statements. With our second quarter reporting, the financial results associated with EnLink will be reclassified as discontinued operations in our consolidated financial statements. Subsequent to the closing of this transaction, which occurred in mid-July, EnLink's financial results will no longer be consolidated with Devon's upstream business. To further assist investors with this transition, we've provided pro forma financials in a recent Form 8-K filing to better highlight the historical performance of our go-forward upstream business. As Dave mentioned earlier, we're returning the sales proceeds from the EnLink transaction to our shareholders through our share repurchase program.
In June, our board of directors authorized a 300% increase in our share repurchase program to $4 billion. At current pricing, this represents over 15% of our share count and is the largest share repurchase authorization of any E&P company in the industry based on a percentage of market capitalization. As of today, we have repurchased nearly 5% of our outstanding shares at an average price of $41 per share, bringing the total cost of our program to approximately $1 billion. For the remaining $3 billion of our authorization, we plan to utilize a series of accelerated stock repurchase programs, otherwise known as an ASR. We expect our initial ASR to commence in early August, once the blackout period related to our Q2 earnings release expires at the end of this week. The ASR programs will allow us to repurchase large amounts of our outstanding shares on an expedited basis.
In fact, we expect to fully complete our $4 billion share repurchase program during the first half of 2019, well ahead of our board's authorization that extends to the end of the year. Detailed forward-looking guidance on share count is provided in our press release issued last night. Looking beyond our current $4 billion share repurchase program, we continue to evaluate opportunities to further increase cash returns to our shareholders. With our disciplined multi-year plan, we expect to generate substantial amounts of excess cash at today's commodity prices via our core operations and planned divestiture activity. We'll utilize excess cash to manage to our stated debt targets and expect to approach our board regarding an increase to our share repurchase program. Lastly, regarding our debt position, we have now successfully reduced our consolidated gross debt to just over $6 billion with the sale of EnLink.
This represents a decline in our debt of approximately 40% year-to-date. At today's commodity prices, we are within our targeted net debt to EBITDA ratio of 1 to 1.5 times. With strip prices where they are today, we'd expect this ratio to trend toward the low end of this targeted range over time, further strengthening our investment-grade financial position. With that, I will turn the call back over to Scott for Q&A.
Thanks, Jeff. We will now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have further questions, you can re-prompt as time permits. With that, operator, we'll take our first question.
Thank you. At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. We'll pause for just a moment to compile a Q&A roster. Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning, everyone. Well, Dave, with your share price reaction today, I hope you're going to get busy with the share buyback. I have two quick asset-related questions, if I may. Probably both for Tony. Tony, first of all, on Showboat. The work we've done in the past, my understanding was that the Lower Meramec kind of thins out in that northeastern portion of your acreage where the Showboat test has been. I'm just curious if you could give us some color as to how many of the wells that you drilled there were in that Lower Meramec area. Did that influence the average production rate? What's the read-through as you move into the thicker part of the section with Horsefly and Bernhardt?
Yep. Thanks for the question, Doug. In our Showboat project, we had about half the wells landed in the Upper Meramec, half in the Lower Meramec. We saw a little bit of an increased performance from the Upper Meramec, and I'm going to turn it over to Wade, and Wade, if you could give Doug a little bit of a description on the surface on where Horsefly and Bernhardt would go, that'd be great.
Sure. Will do, Tony. Doug, again, half the wells were in the lower, half in the upper. We actually saw about a 25% performance difference between those, in that the upper was much more prolific. You're correct. As you move south and west of Showboat into the core of the play, we see the Lower Meramec targets have even higher productivity. As we develop both Horsefly and Bernhardt and other projects like those, we have increased confidence that those zones will work in an infill development scenario. Although they didn't work as well as we thought they would at Showboat, we still feel like they have a great potential across other parts of the play.
Wade, did you get the cost benefits that you were expecting?
Yeah, we broadly have. I think that's the most successful part of Showboat is, on a pace and cost perspective, we met or exceeded our expectations. We were 40 days ahead of plan on Showboat. We saw cost reductions relative to our parent wells. We're even seeing more cost performance on the Bernhardt and Horsefly. Those two projects, which are both all 10,000-foot wells, are projected, and they're pretty much done at this point, to come in between $7.5 million and $7.1 million per well. We're pretty encouraged about the cost efficiencies we're seeing.
Thanks. My second asset-related question, Tony, again, it may be for you, but the Delaware Basin, obviously, you've been still drilling sort of random one-off couple of pairs of wells all over the place in Todd, Rattlesnake, and so on. It looks to us that as you prepare the program going into 2019, the cadence of the completion is obviously an issue it looks like as you move into development mode. I'm curious if you can just walk us through what role the Delaware Basin plays in the dip in your production in the third quarter and how that might ramp as we go into 2019, particularly given how prolific those wells are. Asked differently, it looks like your 2019 program is going to be some pretty strong wells versus a type curve that you've based your 2020 plan on. I'll leave it there. Thanks.
Doug, I'm going to start off here, then I'm going to ask Rick to fill in with a little bit of details there. I think we really haven't been drilling a lot of couple random wells in the Delaware Basin. We have been appraising a little bit, and you heard us announce the Boundary Raider wells last quarter, which were quite prolific. For the most part, probably 70% of our activity in the Delaware Basin is really associated with these multi-zone projects that are going quite well. We're reaping a lot of the cost and schedule benefits that Wade just described in the Showboat project are also happening in our larger multi-zone projects in the Delaware Basin. While these projects can be a little bit lumpy, we've sized them to have fairly contiguous or continuous growth on both oil and cash flow.
We're pleased with what we're seeing right now. We're starting to move some of our work in the Delaware Basin from the traditional Second Bone Spring type activity that we've had to the Wolfcamp, and this is really kind of an effort to optimize the developments of the Wolfcamp horizon there. You're right, you're going to start seeing a little bit of a slowdown in pace of IDs in Q3. That's what caused a little bit of the softness in our forecast in the Delaware Basin. That really picks up at the end of the third quarter, and into the fourth quarter, we'll have a dramatic increase in ID count going forward. With that, Doug, I'm going to let Rick describe just some of the work that we're doing.
Great question, Doug, and this is Rick Gideon. Very much in line with what Tony just said. I'll tell you, right now, when you look at our ops report, we talk about our Seawolf and Lusitano, Medusa, Fighting Okra, Snapping, and North Thistle program. You're seeing that progression into these programs of many different sizes. What I'll tell you that's based on is the great technical work provided by these teams. It's the understanding of the dependent and independent flow units, whether that be in the Leonard Bone Springs or Wolfcamp. What I think you'll see are some different size programs going forward here that we are seeing outstanding results from the multiple horizons, from the multiple flow units, and in our spacing, not just horizontally but vertically.
You've seen some great well results in the Second Bone Spring that tie directly to better technical understanding, better planning, and quite honestly, flawless execution as we move through this. With that, we're able to utilize different flow back techniques, and I think you're starting to see the results of just great teamwork, great planning, great execution, and very good technical understanding.
Guys, I appreciate the full answer, but just to be clear, the Boundary Raider wells, if that's the type of well that constitutes the program in 2019, that's substantially better than the type curve that's set in your current program. Is that correct?
Well, the Boundary Raider wells are special wells, Doug, and we've got some offsets to drill to the Boundary Raider, which are going to be a really good development, and we're going to be kicking that area off later this year. As you look at our current operations report, we just reported some really good wells in the Cotton Draw area, in the Second Bone Spring. Those are also really good wells. I'd say in general, our performance from our wells is better than it has been in the past. The subsurface understanding from the technical teams is just outstanding. This commitment to the data acquisition and being data-driven has really paid off for us.
Thanks.
In general, I think, Doug, the comment is absolutely the Delaware's running ahead of plan.
That's what I was looking for. Thanks, Dave.
Our next question comes from the line of Scott Hanold from RBC. Your line is open.
Thank you. Hey, a follow-up question on Showboat. You did obviously mention there was some, I guess, a bit stronger declines. Was that related to the parent well being obviously three years old in the area, or was it more of the Lower Meramec? If you could also comment on what you saw with the Woodford well.
Sure, Scott. This is Wade Hutchings again. I think there's three big preliminary insights we've taken from Showboat. The first is the difference in performance between Upper and Lower Meramec, which we just discussed. The second really relates to your question, and that is a very clear trend that any of the wells in either the upper or the lower that were drilled in the parent well's shadow, those underperformed relative to any of the wells that were in more of what we'd call the green field parts of those sections. Underperformance would be reflected at both an IP and even a decline level. The third key thing we observed is we're seeing some initial indications that there's more vertical connectivity between these reservoir landing zones than we may have saw in other parts of the play.
Those are really our key preliminary observations so far from Showboat.
Scott, this is Dave. I might add that I think at this point, though, you have to be extremely cautious about extrapolating any results that we have from Showboat to the remainder of the STACK play. It is very early on. We are taking the learnings there, and we're adjusting our go-forward development plans in terms of spacing. The ones beyond Bernhardt and Horsefly, we're adjusting the spacing, as we think that's the right thing to do in the short term. It's not clear that that's the only answer that's going on here. I would certainly be extremely careful that we have had some challenges here at Showboat. We knew we were testing the upper limits of the spacing, that's proved to be true.
We're learning a lot from that, and I think that there's a lot more to learn, and we'll learn a lot more as we proceed through the next several development projects here. To take the results from Showboat and extrapolate a general learning across the entire play, I think it's very premature to do that.
Okay. Understood there. On the Woodford, did you have any comments on the Woodford well?
Yeah. That Woodford well would be one of the furthest north Woodford oil window wells. Right now it's still in a phase where it's still in flow back. We don't really have a lot of hard conclusions to make on the Woodford prospectivity extent at this point.
Okay. Understood. Then in the PRB, it looks like you guys looking to expand your program next year to maybe 4 rigs. Can you discuss what you're seeing there and what we should be looking forward to?
Scott, I think again, the work that we're doing primarily in the Turner is really providing a lot of good insight. We've done some spacing tests there. We're very pleased with what we're seeing. Every well that we bring on is really some of the higher rate of return wells that we have. We're starting to define what the development plan will look like. We're also having some positive results in the Niobrara. We haven't commented on that specifically yet, but both of those parts of our program are developing very well. I think what we're trying to infer is later this year, we'll not only pick up the second rig, but get up to the third rig, then in 2019, expect to be in full development mode there with increased activity beyond that.
Everything that we're seeing in the Powder is developing just to plan.
Okay. It's definitely in the Turner and both in the Niobrara what you're seeing results that you could be active on next year.
Primarily, not to shortchange some of the work that we typically do in the Parkman and the Teapot, those always deliver good results. Really, as we commented in the past, the Turner is more of a resource opportunity for us, and that's what's being uncovered right now. That'll really drive a lot of the pace of activity in the Powder.
Got it. Thank you.
Our next question comes from the line of Bob Brackett from Bernstein Research. Your line is open.
I had a question on your comments trying to unpack this notion of strategic high grading. If we look two to three years into the future, what assets are you highly certain stay in the portfolio, and what assets do you think could find a home for someone else? I have a follow-up.
Hi, Bob. Well, first off, we believe very much in the multi-basin approach, and I think you're really seeing the benefits of that approach right now as we speak. We're having outstanding results in the Delaware Basin. Tony just described some very promising results that we're seeing in the Powder. Overall, we have a strong inventory in the STACK. We have admittedly had a little bit of disappointment here, not tremendous, but it's a little bit in short term. We Showboat with one development in the STACK. With 90% of our development still in front of us, we're adjusting quickly, and we still have some really strong return opportunities in the Eagle Ford as well.
We believe that this multi-basin approach that allows us to shift capital between several high return basins is the absolute rightful approach, and it really optimizes returns versus being overly dependent on one specific play. We look at a lot of different things when we look at what may or may not remain in the inventory. We look at what is our overall depth of our development inventory, what's the intrinsic value of the asset that we may be looking to monetize, and what is its production and cash flow contributions. We look at what are the prevailing market conditions out there. Obviously, we have teams that are very engaged and understand the market from both a buy and a sell standpoint extremely well. When we identify an opportunity to pull the trigger, we're not afraid to do so.
If you look at our history here, we've had about $30 billion worth of transactions over the past decade. I'm not going to telegraph today specifically what may or may not, but those are the key issues that we look at here. We think we have a very strong inventory of where we are, and we'll continue to evaluate conditions as we move forward.
Okay. Getting a little more granular. When you talk about the spacing tests in the Turner, are you aligning those well bores parallel or perpendicular to that old Cretaceous Seaway?
Most of those are running in a north-south direction throughout the play, and we're spacing those. In the areas that we have two horizons in upper and lower Turner, there's a staggered pattern. It's not just about one horizon. It's understanding the different horizons and what the interaction is between the two.
Great. Thank you.
Our next question comes from the line of Brian Singer from Goldman Sachs. Your line is open.
Thank you. Good morning.
Morning, Brian.
In the Eagle Ford, I realize per your comments, you haven't had discussions with the new operator. What rig count or level of activity do you think would be optimal for Devon in an accelerated case? If this were to happen, would you reduce capital elsewhere in the portfolio, or would you use your free cash flow or balance sheet to increase activity in the Eagle Ford?
Well, we're currently running two rigs there, Brian. I think in an optimized scenario, we'd run three rigs, frankly, that's not a large incremental capital spend if you look at the overall size of the company as Devon. It's barely a material question, I guess you'd say, as to whether you'd use drop activity elsewhere or use some of the incremental cash flow. If we're going to do that would be a 2019 event. We anticipate that would not be a 2018 event that we would change the program. Those returns, just to refresh everybody, are as strong as anywhere in our portfolio. Particularly given the fact that we're getting WTI plus pricing on those barrels. That we've done a great job with locking in well above the current market pricing in the Delaware Basin.
Incidentally, obviously also in our heavy oil in Canada, but still not as strong as we see in the Eagle Ford. With those flow rates compared to the costs, they compete extremely well. We don't see rapidly increasing the capital, but we do see one incremental rig would probably be helpful in 2019.
Great. Thank you. My follow-up is with regards to the company's CapEx. You reiterated that you expect CapEx to trend towards the top end of guidance. Could you give us a little bit more color on the push and pull there? What you're seeing on the inflationary front, what you've done from an activity perspective relative to your expectations, and whether the Permian completion crew on for less time during the second half is helping to keep CapEx in check? What you think the risk around the top end of guidance is to the upside and downside?
Brian, number one, I think as we mentioned in some of my prepared remarks, our supply chain and our operating teams have got a three-year plan that we are sticking really close to. It allows us to go out and secure services for an extended period of time and compared to a lot of our peers. We feel like we have mitigated any of the stress or the inflationary factors that others are probably seeing in the 2018 timeframe. We're doing some really good work. We're not outspending the cost and schedule management of our projects, as Wade and Rick have already talked about, have been on track, so we're doing really well there. We think our OBO spend has actually been an increase and a little bit of a surprise to us early this year, and starting to see some benefits from that.
That's really keeping us at the top end of the curve. I think what you'll see is we had a very hot Q1 and have tapered back a bit, as you noticed, a 10% reduction in Q2, and we'll manage our spend in the second half of the year according to our original plan. We just think this exercise is good discipline, and it's there to maximize the return of our projects. Basically, Brian, we're executing our plan a little ahead of schedule. We have a little extra OBO spending. It's not on the cost side, because we're managing that extremely well. The decision not to add a third frac crew in the Delaware was not driven around trying to stay within capital. It was driven by a returns decision.
Basically, we are able to have one frac crew, I think, Rick, you'd say per four rigs that we have working out there, and we're able to keep up with it. If we added a third frac crew earlier, right now for just a few rigs, basically what that would mean is when we come early 2019, we would have two long-term frac crews, one of which probably wouldn't have any work to do given the timing of all of our schedule. From a return standpoint, that doesn't make sense. It makes more sense to stay with the two who can manage the eight rigs. Now, we do see going to three frac crews in 2019 as we continue to increase the activity.
Great. Thank you very much.
Our next question comes from the line of Subash Chandra from Guggenheim. Your line is open.
Yeah, thanks. The Showboat, just curious if the results there have any impact on the prior exit rate guidance in STACK, or if it has any sort of tangible impact on your growth expectations in the intermediate term?
I'd say it has no impact on our growth expectations under our Vision 2020. We have enough projects of different types and a high quality that our Vision 2020 is absolutely, totally intact. Could it perhaps have a minor amount of downward pressure? The question might be asked, too, why didn't we raise oil production guidance, I guess, for the remainder of the year? Admittedly, because of the Showboat issues, we thought it was more prudent, until we see more data and we get the Bernhardt and Horsefly wells on, to not raise production guidance even though we exceeded in Q2. Yes, throughout 2018, I would say that that did impact our short-term thinking on raising production guidance.
We have a very deep inventory of projects throughout the company that the 2020 Vision and our growth that we anticipate in oil production, U.S. light oil production, is absolutely intact. We're seeing outperformance, for instance, as we talked about in the Delaware Basin, seeing some very strong upsides for the Powder River Basin, great returns from the wells we're seeing in the Eagle Ford as well. Maybe a short-term timing impact on production, but absolutely our potential that we chose to guide conservative in regards to, but no implications at all to the long-term vision of the company.
Okay. I appreciate that answer. My follow-up is, I apologize if I missed this in your earlier commentary, the Turner spacing test. What is that architecture? What is the spacing test exactly? Would this be one of the first spacing tests in the Turner in the play?
This is Rick Gideon again. There's been different spacing tests. Again, I want us to be careful on which part of the field we're in, whether you have an upper Turner, a lower Turner, or a middle Turner. We've tested between two and four wells per section in each of those horizons. These latest tests were two wells per horizon or four wells per section in an upper and lower. I think you've seen some competitors do very similar testing, and as I said, we tested at four earlier in the year.
Okay. Thank you for that clarification. Thank you.
Our next question comes from the line of Matt Portillo from TPH. Your line is open.
Good morning, Dave and team.
Morning, Matt.
The first question I want to ask is in regards to STACK completions. You mentioned that you're working to mitigate some of the parent well impacts after viewing the initial data on the Showboat project. I was curious if you could talk about some of the completion changes you might be envisioning, if at all, around proppant loading, cluster spacing, and fluid use that might help optimize development on a go-forward perspective.
Matt, I think we are in the middle of evaluating the specific completion design we had on Showboat, and have already taken those learnings and started to apply them even to Bernhardt and Horsefly, which have already been stimulated. That's a pretty active process for us. I would say the broad trend is we are at a little bit more of a macro scale. We're looking at specific reservoir targets and their rock properties, and we are beginning to more proactively adjust the stimulation parameters based on each of those reservoir targets. Again, some of that's learnings from Showboat, some of that's learnings that we saw in other projects. On maybe a more specific stimulation approach, I would say that what we're doing is we're beginning to apply much more limited entry type approaches.
We've tested a few things in Horsefly and Bernhardt that we think have promise around different technologies that allow us to really target exactly what part of the reservoir, what part of the lateral. In a couple of those, is we've tested some NCS sleeves in one of these projects that we think actually has a lot of potential for us. You'll see us continue to evolve that in much more of a reservoir-by-reservoir specific targeted way.
Great. Thank you. My follow-up is a question regarding Jackfish. I was wondering if you could provide additional color on the maintenance requirements that were identified that took down Q3 guidance to some extent. As we look forward to Q4, any color or context around how we should think about the peak rates mentioned in the ops report?
Matt, I got to remind us, the maturity of our Jackfish-1 project is different than it was probably the last turnaround. In fact, we've been producing J1 over 10 years now. Our turnarounds at J1 were more extensive than they have been at some of the younger projects. You got to remember, we're operating some of these steam lines at 450 to 500 degrees F. In the process of cooling and heating these lines, we tend to see movement, and those lines are designed to move. We have pipe racks to guide those lines through there. During the ramp-up period for J1, after the turnaround was over, we saw an increased stress in one particular area. We immediately took the project back down and went through an extensive evaluation and mechanical integrity inspection.
At the same time we were doing that, we took a good look at one of our oil lines as well. That really deferred our startup at J1 by about 15 days. It also deferred the startup of a couple of new pads out there. We're getting a little bit of a slow start in Q3 associated with those couple of events. As we ramp the project back up, we fully expect to grow back into something near the historical rates that we have seen in the past. Again, you got to always recognize that as these projects mature, there's going to be slightly more maintenance associated with them. The SOR is just slowly starting to creep up, so there's a little bit less steam capacity that we have available to work with. Overall, the projects are working extremely well.
Outside of these two unplanned events, we're back to operating as normal.
Great. Thank you very much.
Our next question comes from Biju Punnachalil from Susquehanna. Your line is open.
Hi. Good morning. Dave, looking through your various spacing pilots in the STACK Delaware Powder, it looks like the approach you're taking is that the initial projects are the spacing is something on the aggressive side, and then you're sort of working backwards. I don't know if that's a fair assessment, but if it is the idea that you can get to the final answer in fewer iterations? Are you getting more information in a pilot that actually has some interaction between wells?
Absolutely. I think you've nailed it. We want to learn early because we recognize in all of these plays that the vast majority of the development is in front of us. We have, just as we did, if you go back even to a few years ago on completions, and when you may have said historically, we're pumping 600 pounds of sand per lateral foot. We could have easily taken the approach to go to 800 or 1,000 and test out what it is there. We took the approach there, says let's go on up to a much higher concentration, up to 3,000 pounds or so, and learn early where the upper limits are, we can dial back a little bit. I think you can take, to a large degree, that analogy and apply it to what we're doing with our spacing tests.
We chose to learn early. Frankly, we also collected a huge amount of data on Showboat project, which we think is going to help inform us as well. We recognized that it was aggressive, the spacing, but if we were going to have an issue, we'd rather learn that early versus just slowly, incrementally up the spacing and get a long distance into the development of the overall play before we really learn what's optimum. There's some pain with this process. We admit that. We're feeling it a little bit today. There's no question about that. We think that overall, that is the right long-term decision and leads to higher returns and higher value in the long run.
Got it. That's very helpful. Do you think at this point, if you're looking at STACK or the Delaware, how close you think you are to that, call it, optimum spacing?
I'm going to let the guys that are a little bit closer. I think you're going to hear an answer that's fairly granular, that it's going to vary still across the play and across the formations. I don't think there is an easy answer. I think we're learning a lot more, but I think we'll continue to learn, but we've certainly accelerated the learning. Wade, do you want to kick it off here? Maybe Rick will make a comment from the Delaware perspective.
Sure. From a STACK perspective, we are systematically testing multiple density frameworks and spacing stacking frameworks. As you saw, the next two projects that'll come online within a couple of weeks here in August, Bernhardt and Horsefly, are testing slightly lower density than the Showboat. We have other projects that you'll see over the next six months where we may only test one layer, the Upper Meramec. That will vary across the play. Excuse me. Ultimately, we think as we approach the end of the year, we're going to have a number of operated tests under our belt that will range in spacing anywhere from six to 12 wells per section. From that, we'll be able to essentially narrow down what the go-forward development plan will look like. I think to Dave's point, that's unlikely to be just one model for the entire play.
We see that these reservoir targets change quality as we move around the play. We know that pressure conditions and even the fluid windows change, we will ultimately have a fairly customized development framework for multiple sub areas of the play. We think as we approach the start of next year, we'll be in a much more solid place to lay that out, both internally and externally.
Biju, this is Rick Gideon. For the Delaware, very similar. What I'll tell you is it's dependent, as stated, whether it be in the Todd area, Thistle, Cotton Draw, Rattlesnake, or Potato Basin, the five areas that we talk about. What I'll tell you also is it ties very much to flow units. It's not just a single horizon, it's not just a spacing. It's the staggered pattern. It's in the Leonard, whether you have A, B, and C. How many wells does it take to most efficiently drain that and have the highest rate of return while preserving value? In the Bone Springs, we're probably the most mature, as we talk about it, Leonard following. Rattlesnake is where we're doing a lot of the testing right now in the Wolfcamp, which is probably less mature on the spacing.
As we take a look at the Wolfcamp, we have to keep in mind that we're looking at your third Bone Springs, your Wolfcamp X and Y, your Wolfcamp 110, 120, and 130 as one single flow unit. As we model that, we have to understand the stimulated rock volume by the types of jobs we're pumping and what is that horizontal and vertical reaction between those wells.
Biju, this is Tony. On the operated side alone, we probably have a library of 6,000 horizontal wells that we worked in, and the majority of those have had parent-child relationship issues that we've worked through. We're going to continue to learn in all of these plays. The technology continues to change. The guys are getting smarter. New data just leads to new developments. We're seeing some of the best completions we've made in the Eagle Ford today. We're seeing some of the best completions we made in the Cana-Woodford project towards the end of 850 wells. Same thing in North Texas and the Barnett. We're seeing some of the best wells now after 3,000 or 4,000 wells have been drilled. This is not a single answer that you're going to hear from us. We're going to continue to learn and grow.
Very helpful. Appreciate that detailed answer. Thank you.
Our next question comes from the line of Paul Sankey from Mizuho. Your line is open.
Everybody excuse me. Based on everything that you said, thanks for all the detail, it does seem that it's difficult for you, for a couple of reasons, to accelerate in the Eagle Ford or the Delaware, much more than the pace you're already running. I wonder, does that mean that we're very dependent on results coming through in the way you've described? I totally understand that you're saying that there's 90% of the work still to be done, do you think that the risk has become higher on the STACK in terms of its importance for you and Vision 2020? Thanks.
No, Paul, I don't feel that way. We do plan to have escalating program in the Delaware Basin as we move into 2019. We haven't laid out the specific plans, I think we're anticipating having on the order of three or four more rigs working out there. That's directionally the way we're thinking right now. We're looking at adding more rigs in the Powder River Basin. Tony talked about that. No, I don't think that's true. I think that we've had outstanding results in both of those areas as well. The Eagle Ford, we're not counting on for significant growth, but we do think we can stay, keep production flat there with three rigs, and we think that will be optimum. Having said that, we do anticipate STACK is going to continue to grow as well.
I don't want to talk down the STACK at all, because we're learning very quickly, and we're adjusting, and we anticipate a very successful STACK program going forward. It is going to be an important part of our future.
Understood. Thank you, David. Can I just ask a follow-up, which is totally unrelated, really? Has your hedging strategy changed subsequent to Vision 2020? Thanks.
No, it hasn't. No, we fundamentally think that first off, that we want to have a consistent and predictable capital program because we think that having a consistent program where you're not ramping up activity or not ramping it down is how you deliver the highest returns. If you rapidly increase the capital program, you may not be ready from a technical standpoint or an infrastructure standpoint to be able to deliver optimum returns. If you ramp down the capital program, you lose some of the efficiencies that you get with a certain level of scale on these. You want to have multiple rigs working, for instance, on an individual development. You lose some of those efficiencies if you ramp it down significantly.
With that thought process in mind, we think it's important to underpin the cash flows of the company to make sure that we have a certain level of consistency in cash flows to be able to fund the capital program. We are doing this through a systematic program largely where we're reaching out 18 months and hedging production at any given time. We do leave some room for discretionary hedging as well, but it's all within the context of underpinning the confidence in what prices we're going to receive. Obviously, we're hedging on the differentials too, which has provided quite a bit of benefit for us this year in terms of pricing. We think that's fundamentally important to deliver consistent, strong returns with our programs.
Thank you, sir.
Our next question comes from the line of David Heikkinen from Heikkinen Energy Advisors. Your line is open.
Good morning. Thanks for taking the question. One thing I was curious about is the importance of sequencing your drilling, then completions, then putting pads on production, kind of across the section and then across multiple sections. Any differences of required sequencing between what you've seen in the Delaware STACK and now the Powder?
Hi, David. This is Rick Gideon. Absolutely, there's some difference in sequencing, and the teams do a great job on the planning side of this, whether it be with our frack crews, rigs, or other services. It's very dependent on how many horizons you're going after in the Delaware. We've done some tests where you're hitting six different horizons. What I'll tell you is through our learnings and understanding the flow units, you'll see some areas, especially in the Delaware, where you'll see some smaller projects where we develop one flow unit, move away, and then come back and develop the next flow unit to better utilize our surface facilities and infrastructure within the field, as well as water, et cetera. I think as we move through this, you're going to continue to see how we change, based on spacing, but based on flow units also.
Just to follow up on that, how do you think about the scale of required capital and working capital then that is invested and what's required for a company the size of Devon can fund it, but maybe smaller companies that becomes pretty important and pretty meaningful as you think about that six-horizon development, and the number of wells potentially. Have you done any math on how much capital you actually put into the ground before you turn it on production?
We've done a lot of math on, I'd say, what is the optimum size development to optimize the rates of return.
I think we probably have the capital to fund whatever is the right answer. We do think that there is an optimum size in many cases, to what optimizes the rates of return.
Yeah. This is Wade. I would just jump in real quick and say we're absolutely focused on the fact that time is money, and so we're very much focused on eliminating as much float in the schedule or white space in the schedule as we can.
To Rick's point, this often is a very technical set of judgments. For instance, on the two Showboat sections, there were six pads, and the team had a very specific order of which pads to stimulate and which pads to flow back, in what order because of the impact that they would have on surface operations and even subsurface operations. It's an area of intense work for us.
That's helpful. Just one final, what are your current well costs? You gave us the Delaware, or you gave us the STACK. What are the Delaware and Eagle Ford current costs?
Dependent on the horizon in the Delaware, again, dependent on We're in the $7 million range on a lot of these, down to five. Is it about five and a half on some of the shallower zones? We're very early as we move into the Wolfcamp, we are seeing progression of that lowering.
David, the Eagle Ford wells lately, we're putting a little bit larger sand loading in these wells, they're running about $6.5 million.
Thank you.
All right. We're now at the top of the hour. We appreciate everyone's interest in Devon today. If we didn't get to your question, 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.