Scott Coody - Devon Energy Corp. David A. Hager - Devon Energy Corp. Tony D. Vaughn - Devon Energy Corp. Jeffrey L. Ritenour - Devon Energy Corp. Wade Hutchings - Devon Energy Corp. Kevin D. Lafferty - Devon Energy Corp. Richard A. Gideon - Devon Energy Corp..

Robert Scott Morris - Citigroup Global Markets, Inc. Arun Jayaram - JPMorgan Securities LLC Ryan Todd - Deutsche Bank Securities, Inc. Charles A. Meade - Johnson Rice & Co. LLC Subash Chandra - Guggenheim Securities LLC Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Doug Leggate - Bank of America Merrill Lynch Brian Singer - Goldman Sachs & Co. LLC Jeffrey Campbell - Tuohy Brothers Investment Research, Inc..

Good morning. Welcome to Devon Energy's First Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will a question-and-answer session. 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 and good morning. I hope everyone 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 today's call, 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. With today's call, I will cover a few preliminary items. Then our President and CEO, Dave Hager, will provide his thoughts on the key takeaways from the quarter.

Following Dave, Tony Vaughn, our Chief Operating Officer, is going to cover a few key operational highlights and review our infill development strategy in the STACK. And then we'll wrap up our prepared remarks with a brief financial review by Jeff Ritenour, our Chief Financial Officer. Overall, this commentary should last around 10 minutes.

Then we'll open the call for Q&A. I would 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 law.

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.

And with that, I'll turn the call over to our President and CEO, Dave Hager..

Thank you and good morning, everyone. For the purpose of today's call, my comments will be centered on four key messages. Turning to slide 2. The first key message is that we are raising our 2018 guidance for U.S. oil production due to the outstanding operational performance we are experiencing in the Delaware and STACK.

With this production raise, the midpoint of our updated guidance for 2018 U.S. oil production now represents an estimated growth rate of 16% compared to 2017, up from our previous guidance of 14%.

The improved outlook is driven by higher well productivity, as our development activity is focused in the economic core of the Delaware and STACK, and the efficiency gains we are achieving at our multi-zone developments.

With our initial multi-zone developments, we have executed these projects with greater efficiency than planned, which is compressing cycle times and pulling forward incremental activity into 2018.

Given this outstanding execution, it is likely upstream capital spending will trend toward the top half of our full year guidance range, benefiting our production profile in 2018 and 2019.

I want to emphasize the only reason CapEx is trending towards the top end of guidance is because we're completing our plan 2018 program quicker than anticipated, and we'll most likely accelerate some 2019 program into 2018. This is a good news story.

The next key point is we have the marketing arrangements and supply chain in place to deliver on our growth plans. With regional takeaway constraints becoming a serious issue for the industry, our marketing plan has provided us both flow assurance and price protection across all areas of our asset portfolio.

Specifically in the Delaware Basin, through firm transport on the Longhorn Pipeline, we have access to premium Gulf Coast oil pricing and have regional basis swaps near WTI pricing covering the remaining production sold in the basin.

These physical and financial hedges are becoming increasingly valuable with Midland differentials currently trending towards $10 off WTI. Given our advantaged location in Southeast New Mexico, we also have good line of sight to move our Delaware gas production, as we flow our volumes directly to the West Coast completely avoiding the WAHA hub.

In the STACK, we have direct access to Cushing for WTI pricing. And we have firm transport agreements covering the vast majority of our gas production. The firm transport of gas in the STACK and our basis swaps provide effective price protection in 2018. The last area I will touch on is our attractive WCS hedges in Canada.

In 2018 we have roughly half of our production hedged at $15 off WTI. On the supply chain front, the service market is certainly tight right now, especially in the Permian Basin.

However, our supply chain team has proactively secured rigs, supplies, and pressure pumping services in our high activity basins at competitive prices to execute our capital plans in 2018 and 2019.

The multi-year develop plans and commodity hedging program we've designed for the Delaware and STACK have provided Devon the opportunity to secure longer term relationships at below market rates with top providers.

So to summarize, Devon is in great shape to deliver on our growth initiatives, as our marketing and supply chain are providing certainty of execution. The third key message is that Devon will efficiently grow cash flow throughout the remainder of 2018.

With current strip prices, we expect to increase our upstream cash flow by approximately 35% by year end compared to first quarter levels. This will be driven by three factors.

A key contributor to our cash flow growth is an increase in higher oil margin production in the U.S., where we are on pace to deliver exit rate growth of approximately 30% in 2018.

Next, we expect higher margins in Canada over the remainder of 2018, due to WCS prices recently improving by more than $10 per barrel compared to the lows experienced in Q1. The third factor contributing to higher margins over the remainder of 2018 is the aggressive steps we are taking to improve our cost structure.

With the ongoing restructuring of our workforce, along with the recent tender of high interest debt, we are now on pace to reduce G&A and interest costs by $175 million annually. And my final key message is we successfully advanced several shareholder friendly initiatives during the quarter.

In March, our Board of Directors approved a 33% increase in our quarterly dividend and authorized a $1 billion share repurchase program, which we are on pace to complete by year end. Jeff will provide more details on these initiatives later in the call.

Looking ahead, as we generate free cash flow from operations and asset sale proceeds, we will continue the return of cash to our shareholders through our share repurchase program and growth in the dividend.

Given the potential for significant cash inflows through asset sales, I'd like to provide additional clarity to our portfolio simplification strategy. Moving to slide 3. As we discussed at length in the past, given our resource rich asset base in the Delaware and STACK, we see the potential to monetize in excess of $5 billion of noncore assets.

And while we've already achieved $1.1 billion of noncore asset sales to-date, we have multiple initiatives underway at various levels of maturity to further simplify and focus our portfolio footprint. To be clear, we're not going to become a Delaware and STACK pure play. But we are targeting a more focused asset portfolio.

We are actively pursuing larger asset transactions. And we are concurrently marketing roughly $1 billion of smaller, noncore assets sales throughout our portfolio. While there are a lot of initiatives going on, I do want to emphasize that we're working each of these opportunities with a high sense of urgency.

And with this point I'll turn the call over to Tony Vaughn for additional commentary on our operations..

Thanks, Dave. I'd like to begin by covering a few noteworthy operating highlights on slide 4. A great place to start is with our Delaware and STACK assets, which delivered 20% plus oil growth in the quarter, a driving force behind our Q1 oil production beat. This strong growth was driven by record setting well productivity.

For the quarter this activity was headlined by two stunningly prolific Boundary Raider wells in the Delaware Basin that achieved a combined 24-hour IP rate of approximately 24,000 BOEs per day, of which approximately 80% is oil. 24,000 BOEs per day. These are the highest rate wells brought on in the 100-year history of the Delaware Basin.

The STACK also delivered outstanding new wells with the most prolific rates belonging to four wells from our Coyote development that delivered average 30-day IPs of 4,400 BOEs per day per well. We also had a strong quarter of efficiency gains, as we shifted towards multi-zone developments.

In the Delaware, this included record drill times at Boomslang and drilling improvements at Seawolf that translated into savings of $800,000 per well. In the STACK, our Showboat execution was exceptional, as we attained first production 40 days ahead of plan. Overall, a great start to the year for our capital programs.

And these outstanding well results reflect the quality of our underlying asset base and our staff's top tier operating capabilities. I'm very proud of the effort that they have put in this quarter. Moving to slide 5.

I'd like to focus my remaining commentary on a subject that is of great interest to our investor base right now, and that is our STACK infill spacing strategy. As many of you who follow the play closely know, our STACK acreage position resides in the economic core of the play within the volatile oil window.

This sweet spot delivers the best combination of high oil productivity and lower well cost. Devon's asset quality, technology leadership, and technical understanding of the play have consistently produced best-in-class well results in the play, which compete very well for capital within our high quality asset portfolio.

Now that our leasehold drilling is largely complete, the next step for our STACK asset is to optimize the infill spacing with our multi-zone development projects. With more than 95% of our Meramec resource undeveloped, the next three projects – Showboat, Horsefly, and Bernhardt – are designed to inform our future development strategy.

These projects will test development concepts, including well densities of 9 to 12 wells per drilling unit, and are designed to improve returns through multi-layer well stacking, intra-layer well staggering, and further completion design improvements. The most advanced of the initial infill projects is our Showboat development.

Showboat is in the early stages of flowing back. And we are excited with the efficiency gains and cost savings we achieved compared to the legacy parent well drilling results. Drilling times were 30% faster, and we had a 2 times improvement in completion stages per day due to the benefits of zipper fracking.

Due to these efficiencies, we achieved cost savings of $1.5 million per well at Showboat versus legacy activity in the area. For a better understanding of vertical and horizontal communication between wells at Showboat, we are staggering well tie-ins over the next two months and expect to obtain peak rates by mid-year.

Even with conservative well productivity assumptions for our next three infill projects, we are projecting burdened wellhead returns of 40% at today's strip pricing. These will be great projects for Devon.

With a lower capital and LOE cost associated with these multi-zone developments, we expect our go-forward infill development returns to be superior to the historic well results in the play.

And in addition to the strong project level economics, I would like to emphasize that we have a huge runway of resource and inventory, providing a multi-decade growth opportunity for Devon.

We have 130,000 net acres in the core oil window of the play with most of these acres possessing multiple landing zones that are highly economic at today's prices. We have conservatively risked our Meramec inventory at six wells per surface section. But we fully expect infill drilling results to increase our inventory over time.

And with that, I will turn the call over to Jeff..

Thanks, Tony. As Dave mentioned in the opening, I will provide an update on the shareholder return initiatives underway at Devon and will touch on our debt position and interest cost.

However, first I'd like to cover the new revenue recognition accounting rules that changed the way our financial statements present certain processing fees for natural gas and natural gas liquids. Historically, these processing fees have been recorded as a reduction to revenue.

But beginning this quarter, the fees were recorded directly to production expense. This accounting change had no impact to earnings or cash flow, but the change did result in increased upstream revenues and increased production expenses. Our historical results have not been restated in our financials.

But we have provided a table in our earnings release restating the historical result so the quarter-over-quarter trend is evident. Moving to slide 6. In March, we announced our $1 billion share repurchase program.

To date, we have repurchased 6.2 million shares of stock at an average price of $33 per share, bringing the total cost of our program to $204 million. We expect to complete this stock repurchase program by the end of 2018. In addition to our share repurchase authorization, our board also approved a 33% increase in our quarterly common dividend.

The new quarterly dividend rate will be $0.08 per share, compared to the prior quarterly dividend of $0.06 per share. From a dividend policy perspective, we are targeting a manageable payout ratio of 5% to 10% of our upstream operating cash flow.

With our upstream business well-positioned to efficiently expand cash flow for the foreseeable future, we expect to reward shareholders by sustainably paying and steadily growing the dividend over time. Turning to our debt position.

We successfully repurchased $807 billion (sic) [$807 million] (15:42) of notes in the first quarter, reducing our gross upstream debt to $6.1 billion. Strategically, this repurchase focused on higher coupon maturities in an effort to lower our go-forward interest expense by $64 million annually.

Looking ahead, with the retirement of the $277 million debt that will mature over the next nine months, we will have completed our $1 billion debt reduction plan. And with that, I'll turn the call back over to Scott..

Thanks, Jeff. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have further questions, you can reprompt as time permits. With that, operator, we'll take our first question..

Your first question comes from Bob Morris with Citi. Your line is open.

Bob Morris?.

Good morning. Very nice results this morning, Dave..

Thank you, Bob..

As things are running ahead of schedule and you look to pull some activity forward from 2019, I know previously you were planning on dropping three to four rigs at year end.

Is that still the case? Or are you going to keep all 20 of the current rigs that you have operating going to the end of the year now?.

Well, we're still making an assessment on that, Bob, and exactly what we're going to do.

The thing that we like so much is that we have, with these multi-zone developments, that we are seeing such efficiencies by maintaining the same rigs, the same crews, that we are actually executing our program quicker than we – we knew there was going to be efficiencies. But we're seeing even more than we anticipated.

The costs are lower and the efficiencies are greater. So what we are really focused on overall are the returns. And we don't want to risk degrading those returns by dropping very efficient rigs and crews.

And then picking up potentially new rigs and crews at the beginning of 2019, where we don't see as much efficiencies as we're currently seeing with the program. So that's the thought process we're thinking through. We have a decision to make here.

And we're making the comments, we're kind of guiding towards the top end of guidance, because we think that probably some of this were going to continue on. But exactly how much of it, we're still making a final decision. It has to do with the maturity of the projects.

But a key point I want to emphasize, it's a returns based decision to make sure the projects are ready and balanced out with the efficiencies we're receiving with these rigs and crews, versus the risk of losing that if we drop the rigs..

Sure. That makes sense. Thanks. And my follow-up question is, you had a small, but very interesting joint venture you announced in the Barnett Shale.

And is that something you'll continue to look to do more of, given what the environment is for natural gas asset packages out there in the market? Or how do you think about that, versus stability to continue to monetize the Barnett and doing more of these such deals? Does that necessarily preclude you from continuing to look to monetize the Barnett, even parts that might be subject to some of these sort of deals?.

Yeah. Great question, Bob. And I want to be clear. This does not change anything with regards to the potential long term strategy of what we do with the Barnett.

This is just we think a very creative business opportunity to take an asset that has identified development opportunities and to form relationship with a great company, such as DowDuPont, where we essentially are now bringing them in on a promoted basis to drill some wells that otherwise we would not execute.

So it'd just be an asset that we're not maximizing the value of with these pud opportunities just sitting there. So we are bringing them in with the promote. It makes the returns to Devon competitive with the rest of our portfolio. So it's we think a great way to bring value forward in the short term.

But in no way does this change our optionality or decision process in regards to what we'll do with the Barnett in the long term. We're still working through that. Obviously it's more challenged at these lower natural gas prices.

Also provides benefit to EnLink, which accrues back to us as well obviously by additional provided incremental EBITDA, of which we are the majority benefit. So we think it's a real great shorter term solution and decision that brings value. We like DowDuPont.

And there may be possibilities that we can expand this relationship in the future for similar type situations..

No, that's great. Thanks a lot, Dave. Appreciate it..

Thank you..

Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open..

Yeah, good morning. Tony, I was wondering if you could talk a little bit about the three spacing pilots. And you mentioned that you kind of conservatively risked the production from these pilots. And I was just wondering if you could maybe comment a little bit around your risking for the projects..

Yeah, Arun, I think we've commented in the past that we've got quite an extensive library of information and participated in about a dozen different pilots in the play. These are three more projects that we have that are going to fill in some key data points with us.

I have to tell you – and I'm going to turn the call over to Wade Hutchings in just a minute, who is managing that asset base for us. But, Arun, there's more to it. It's a more complicated question when we manage these unconventional reservoirs than just simple spacing. And Wade will be able to dial into that a bit.

But we fully utilize this database that we have. We built the 3D earth models. We put a lot of time and attention into the technical competency that we put into it, at least to the optimum design and also leads to the granular attention to execution that we have in our technical groups.

You're seeing some prolific well results in both the Coyote areas and across STACK, and the same thing in the Delaware Basin. None of that's really by accident. It's all by just competency and technical fact based work that the guys are doing.

So, Wade, why don't you describe a little bit more what you're trying to get out of the pilots? Maybe even explain a little bit of how we work in the greenfield and the brownfield type areas..

Sure. Thank you, Tony. When we look at these three projects that we've highlighted here, we certainly have a range of spacing that we're testing, all the way from 12 wells per section in Showboat to 10 wells per section at Horsefly, and then 9 at Bernhardt. All three of those projects are in the core of the Meramec play.

All three of them are landing in the best reservoir, which is essentially what we call the Meramec 200. And then they all are staggering wells in between a couple zones just lower than that core reservoir. So they're all testing roughly the same reservoirs but at slightly different staggering and well spacing.

And we anticipate learning a lot from these, in addition to the other industry and non-operated investments we've made. Ultimately, we're testing a lot more than spacing though, because we recognize that the stimulation approach in an infill mode needs to be different than it was in the parent HBP mode.

And so we're testing multiple things in each one of these projects. We'll certainly give you a lot more detail on that as those projects come online. But we're really looking at how do we optimize the stimulation spend to get the most value out of each of these projects.

The Showboat particularly is one where we've invested a lot of science dollars around monitoring the pressure between wells and between layers and trying to determine if the tweaks we're making to our stimulation design are being effective or not..

That's really helpful. I wanted to shift gears a little bit, talk about the asset sales program. Dave, you highlighted kind of multiple packages, maybe $1 billion of potential proceeds. We also note that I think 28,000 acres of that is in kind of the central Delaware Basin.

But as you receive some asset sale proceeds, what is the first call on that cash to the extent you get to that $1 billion? How do you plan to invest that capital?.

We see the bulk of that going to share repurchases..

Great. Thanks a lot, Dave..

Your next question comes from the line of Ryan Todd with Deutsche Bank. Your line is open..

Great. Thanks. Maybe if I could follow-up. I appreciate all the detail you just gave on Showboat, focused a lot on the below ground stuff. You clearly had a very encouraging performance on cost and efficiencies on the larger development there.

Can you talk a little bit about above ground, what you've seen in terms of your ability to drive down cost and capture efficiencies? And what you think that means for your programs going forward?.

Ryan, this is Tony. I think we've talked over the last probably two years about this multi-zone concept. And we felt like all told, we had the ability to increase our valuations about – up about 40% in comparison to the historic or the legacy type development concepts that you see across these basins.

And we fully expect to have not only just surface efficiencies associated with quicker and more efficient permitting with larger permits being established at the onset, because we have a full surface description of how we're going to flow into the centralized production facilities.

We are designing these, and a concept we have here is really a drill-to-fill concept. And so what you will see in these general areas is we'll build a centralized production facility that'll be able to handle multi-pads as we go forward.

And so while we will not design for a peak rate on a given pad, we'll design for a very efficient and cost effective design that will maximize the rate of return for that project. And then as additional pads come on, they will flow back into that same centralized production facility.

So if you start looking at the burdened cost for all the developments that will ultimately flow into a common centralized tank battery, it's not going to be the $750,000, $800,000 per well when we were just doing the conventional legacy type work. It's going to be much more efficient than that.

And it varies project-by-project, but it'll certainly be below about $0.5 million per well. And that just continues to gain efficiencies as we go forward, because these centralized production facilities are structured to be around for a long period of time as the wells in the given area come on and maximize that space..

Thanks.

And so what you've seen so far, is it in line with the 40% uplift that you kind of envisioned over the past couple years?.

Actually, Ryan, we knew we were going to be learning into this space. And we've completed one, the Anaconda Project in the Delaware Basin. We're virtually through the Showboat project in STACK. And we have other projects going on. We're actually accelerating our learnings much quicker than what we anticipated. So we're quite encouraged with this.

We know this is the direction that we're going to go. We're already starting to look at – potentially we have about 30 different projects that are in one stage of our project management or another. And so we're approving projects and reviewing projects right now all the way out into mid and late 2019. So this is really a well-oiled machine.

And the efficiencies associated with this concept are coming quicker and are probably larger than what we originally anticipated..

So, Ryan, Tony described a surface facility savings. Obviously we've previously talked about the drilling cost savings as well. And then also we are seeing real efficiencies on the hydraulic fracturing side too.

And, Wade, I think you have a stat probably just for example at Showboat on the stimulation side of how much more efficient we are with that versus historical..

Sure, Dave. Specific to Showboat, what we found there was essentially we completed the stimulation of that project in about essentially two-thirds of the time that we had planned. So we anticipated some of those efficiencies, as Dave noted. But we were pleasantly surprised that we found even faster learning curve than we had anticipated.

And really want to give the team a lot of credit for that. I mean a lot of hard work out in the field executing these programs and being willing to lean forward and try to do things a different way to get better results. So we essentially drove our stages per day up by 2 times from what we had done in the past.

And that really accelerated the early production that we saw from this project so far..

Great. Thanks. That's very helpful. And then maybe a quick follow up. We appreciate the incremental clarity on takeaway capacity and pricing out of the Permian Basin. I mean can you – it looks like you're quite well situated until, as we look from now into through the bulk of 2019.

Can you talk about how you see – how you balance the need for the potential to sign up for incremental FT out of the Permian beyond that, versus maintaining longer term flexibility?.

Yeah. And I'm going to ask – we have several people here we're going to let talk, because they're the real experts on this. And so, Ryan, I'm going to ask Kevin Lafferty, who heads up our midstream and marketing business here, to give you a little more granular answer on that..

Thanks, Dave, and good morning, Ryan. Yeah, as we noted in the ops report on slide 13, we have put ourselves in a really good position. And this is a strategy we have in place with all of our key products across all of our plays both in the U.S. and Canada.

So we use a combination of both physical or firm transport and financial hedging to really mitigate risk of both flow assurance and making sure that we can have dollars go to the bottom line. So as we've noted on slide 13, especially for the Permian and starting with oil, so we transport on Longhorn.

And that gets a certain amount of barrels out of the basin and over to the Magellan East Houston marker, where the pricing, as Dave noted in his comments, is stronger. And we're actually building out our MEH hedge book as well, just to lock that in and have certainty of cash flow there.

And then the rest of the sales, we have a little bit to go in the local refineries. And the key here, and it's an intangible for us, but our marketing group both in the U.S. and in Calgary do a really good job of building relationships with key people.

So we are selling our products, not just oil but gas as well, to other people that have firm transportation to make sure that our product is going to get to market. And then of course we highlighted that we have financially hedged both in 2018 and 2019 at just under $1 and then $0.50 a barrel.

What we see though is that you have a whole another wave of pipes that are going to come online in 2019, probably starting first with the Cactus line in mid-2019, and several other projects have been announced.

So this strategy solidly gets us through this period of tightness, where again as Dave commented, the differentials have blown out pretty substantially. And then we will continue on this strategy, shipping, downstream, and/or financial hedging as we go forward..

Thank you..

Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open..

Yes. Good morning, Dave, to you and the rest of your team there. I would like to ask, I know you guys touched on the Boundary Raider wells, those really remarkable wells in the Delaware Basin.

But can you talk a little bit about what led you to target this area? And perhaps elaborate a bit on how those results came in versus your pre-drill? And what if anything has changed on your view in that zone or that area or in any respect?.

Sure, Charles. And I'm going to ask – again we have several people in here. We're going to ask Rick Gideon, who is our Senior Vice President in charge of the Delaware Basin and Rockies, to comment further. But I just want to make one thing really clear before he goes into his comment. You didn't ask this, but I'm going to make it really clear.

This is not due to us opening the chokes up really wild to get a huge 24-hour IP. This is truly an exceptional area, where we're seeing not only great wells with strong pressures, but also you can anticipate the EURs on these area – wells in this area to be two to three times what our normal type curve is out there.

So this is truly an outstanding area that we have discovered.

So, Rick, you want to talk a little bit more about it?.

Absolutely. Thank you, Dave. And great question, Charles. I was hoping somebody would ask about these wells. How did we find them? Well, I'll tell you. I think we have the best technical teams in the industry working these basins. And these teams are focused on identifying the best parts of these basins or the sweet spots.

So when we went into this, this was an identified sweet spot. We were aware these wells would be much better than typical wells. I think they surprised us a bit that they were even better than what we thought. As Dave indicated from a choke management, we did nothing different than we typically do on any of our wells from a choke management standpoint.

None of these wells were opened to full open chokes. They were managed in order to maintain the value of the reservoir. And as we've identified this, as we said in the operations report, we have additional wells we'll be drilling in this area over the next 1.5 years..

And I guess, Rick, has it changed your view on other sweet spots you've identified in the Second Bone Springs, or is it – are there things you're going to be doing differently going forward, having seen what these wells actually delivered?.

I think it's confirmed our view. I don't know that this changed our view. We knew what we were looking for. The teams did a great job again in identifying the different metrics to make these better wells. On top of that it was the outstanding execution of these wells and the ability to flow these back into a large battery and test them.

So I don't know that it changed it, but it did affirm our views. And I think we'll continue to identify these throughout all of our basins..

And, Charles, maybe to help out, give a little context of I think where you may be going with this too. First, there is obviously a great area. We are going to have to build out the infrastructure more in the area. And we're going to be building that out commensurate with drilling the wells. We think we have about 25 wells in this area.

We can't say they're all going to be this good, but we think they're all going to be well above our type curve. And we feel really good that we've identified a sweet spot here.

The production impact of this is going to be more a – and the biggest part is going to be more of a late 2018 on into 2019 and beyond type impact, just given the timing of the drilling of these wells and actually bringing them online.

So it obviously has impacted a little bit here our results already by that and other wells allowing us to raise our production guidance. And frankly, we see some upside to our production guide, U.S. oil production guidance as we continue to execute throughout the year.

But the bulk of the benefit will be late 2018, 2019, and beyond as we bring these wells on.

So, Tony, you had one more comment on that?.

Yeah, Charles, it's hard for me to keep quiet on this. We've talked to you quite a bit over the last couple years. But really made this data driven approach, a big shift in our mentality about three – probably three, four years ago. It's really coming to fruition right now. And so as Rick mentioned, these weren't random events. These were well planned.

And we're seeing this across all the areas that we work, not just in the Boundary Raider localized area, not just in the Coyote area. But you're starting to see what we've always claimed and since late 2015 and beyond.

We've always been number one in IP90s, which we feel like is the best time to approach and estimate the ultimate recovery and value of a well. So we're starting to see an expansion of our results going forward. And so we couldn't be prouder from a leadership perspective of the technical work that our teams are really doing.

We think this is really culminating some good across the board type work..

Well, Tony, Dave, and Rick, thanks for all that added commentary. It's helpful..

Thank you..

Your next question comes from Subash Chandra with Guggenheim. Your line is open..

Yeah. Hi, just maybe a dumb question. But in the presentation, page 8, I just want to clarify something where you say, actively pursuing larger asset transactions.

Is that a distinct bullet point from the bullet below it, about the $1 billion that's out there for sale? Or is there – or is it a just intro to that bullet? So just trying to understand if there's other asset sales that are in the initial stages that are not described on that page. And secondly, if it disqualifies acquisitions..

Well, it is a distinct bullet. So that we are – and let me try to frame the whole question up. So when we say we anticipate more than $5 billion of potential asset sale proceeds, we have executed already on the first $1 billion of that. And that culminated in the Johnson County sale in the Barnett.

The second $1 billion are what we are marketing this year. And that is high multiple properties, such as the acreage that we have on the Texas Delaware side. It's not part of our long term development plan within the Delaware, but we think has a significant value. You don't have a lot of production there.

We think it has significant value in the marketplace, so obviously that's a very high multiple property, since it's primarily undrilled acreage. So that and some other asset sales are the second $1 billion. And we're going to plan to execute that largely here in 2018.

Beyond that, we are looking at some strategic transactions of larger magnitude and actively working some of those as we speak. We are purposely being nonspecific on what those are, because we are saying that the primary growth engines of the company in the future are the Delaware Basin, the STACK, and the Rockies.

We are looking at other areas where frankly we see undeveloped opportunities that we may not be maximizing the value of within our own portfolio, because of the extreme high quality that we have of development opportunities.

But yet, they're other opportunities that other companies, may be worth more in their portfolio than are worth in our portfolio. So we are currently in discussions on some of these larger transactions. Now the reason we aren't being more specific is because in several of these situations there's a limited buyer universe frankly.

And so we want to make sure that we maintain the power and that we have – and we have optionality around which of these we may actually execute on, to maximize the value that we receive for the shareholders. So we have some ideas around it.

We're going to be – I'm going to continue to be non-specific on that though, so that we can maximize that transaction value. And we do have options obviously. We don't have to go one way or another. We have options on which way we may go.

But we are actively pursuing other opportunities of a more strategic nature to reach that $5 billion number in total..

Okay. Thank you.

My follow-up is, any more color you can provide on the proprietary completion techniques you've identified before in STACK? And maybe an update on whether it was applied in some of these wells this quarter? And whether it's being applied in the Delaware?.

This is Rick Gideon. Absolutely, we continue in both areas to progress the tight spacing of clusters, the number of clusters, the rates, the sand volumes, the sweeps, multi, multi variables. Again, our technical teams currently model these. We watch the production and flow back and continue to optimize these.

So very similar in STACK and Delaware, the different techniques we're using, you're seeing it in the results of all of our wells. That, tied along with the real-time monitoring of our completions and the real-time monitoring of our flow back, is providing the better wells that you're seeing..

Yeah.

Rick, I'm curious if it's still a discrete application? Or if we should assume that's sort of being applied across the program?.

It's being applied similarly across the program. I never want you to think that every completion we pump in every horizon across every basin is the same. Everyone has a discrete part to it, but they're all very – way that we're executing..

I think the key thing is that we are communicating constantly across all of our business units. So there, we have completions experts that look across the entire company. And so they may apply different techniques in different areas, but it's out of knowledge of what is the best technique for each of those areas. It's not due to lack of communication.

And the other thing is I've heard described, and this is my explanation of it. That sometimes you hear people talk about frac 1.0 or frac 2.0 or things like that.

To my mind the best way we do it internally is almost like frac continuous, because we are constantly updating our actual techniques based on the real time information that we're receiving on all of our completions. And so it is – we have a continuous improvement program that is truly real time, even on individual wells.

And so it's hard to describe it as a discrete one change that we've made, and we're going to go with that change across the entire program, because that's not the way we work. The way we work is through our 24/7/365 drilling and well control room and flowback room that we are constantly updating how we're doing it. So....

Yeah. Well, great update, guys. Thanks..

Your next question comes from the line of Matt Portillo with TPH. Your line is open..

Good morning, guys..

Morning, Matt..

From a gas perspective you've been able to secure a strong level of flow assurance by transporting volumes to the West Coast in 2018.

As your and industry volumes accelerate regionally, and as capacity west-bound likely toughs out, how does Devon view its medium term strategy around gas marketing and the potential need for FT to clear the basin?.

Hi, Matt. This is Kevin Lafferty again. First of all, let me walk through, all the way through the value chain just to try and be clear about this. On the upstream side – and when I say that, I'm referring to getting the gas from our wellhead and site to the gas processing plant.

We think that there is an ample amount and a strong amount of new build gas processing that's happening both in New Mexico but largely even on the Texas side, which really gives us plenty of access to gas processing. So we don't see any constraints there at all.

When it gets to the residue side, Dave's comments, really the way that we market our gas and the benefit we have being in New Mexico, is that we can tie-in relatively easy to very large pipes. This would be El Paso and Transwestern and Northern Natural and others that tend to go west and move a lot of volume out west.

And so any limitations that we would have are really mitigated just because of location and geography. So we have contemplated whether or not we need to look at firm, and different projects are being built. We're pleased to see the Kinder Morgan project, Gulf Coast Express, move forward and have shipper commitments.

And there are a lot of other projects that are going to follow that to get gas out of the basin. So right now we feel like we can sell into other people that have firm capacity. But we look at taking firm on gas the same way we do on oil. And we're always considering those projects and what it means for us..

Great. And my second question is a follow-up to some of the color you provided on cost savings. We've seen pretty material savings announced on Anaconda and Steamboat from an efficiency perspective. I was wondering how much that's factored into your 2018 capital program.

And as you continue to progress your learnings, how is this kind of factored into your long term views around your free cash flow guidance?.

Matt, this is Kevin again. I'm first going to start and then hand off either to Tony or Dave here. But let me first talk about our procurement and supply chain strategy. So this is – and we've talked a lot about our decoupling efforts. This has been a differentiator for us.

We still see going from Q4 of 2017 to Q4 of 2018, while the industry is inflating at double digit type of numbers, especially in the Permian, because of all the increased activity headed to the Permian, we have largely taken control of our own destiny.

And we still see a low single digit type of inflationary number, because of our approach and the debundling and how we've locked in contracts and secured services. So for us when you combine that with the efficiencies on the drilling in the frac side, we literally see no inflation for the rest of our 2018 program.

And as we've stated on pages 13 and 19 in the ops report, we continue to lock in these services and contract out throughout 2019 as well to really place ourselves in a good situation..

And, Matt, maybe going specifically to your question. Kevin gave you a great description of overall what we're doing. But specifically to your question, I would say largely what Kevin talked about is baked into our capital comments already.

So it's really more about the efficiencies that we're getting in the projects with those being executed quicker than anticipated. This just means we have the opportunity to do more activity than we anticipated. And that's where, as I said before, we're looking at a decision point based on returns as to what the right decision is on that..

Thank you..

You next question comes from the line of Doug Leggate with Bank of America. Your line is open..

Thanks. Good morning, everybody. Dave, I wonder if I could go back to the STACK development plan longer term. I guess I must be the only one that's still confused with 12 wells per section in Showboat, but 6 wells per section on your assumed inventory. Clearly there's some upside risk there.

How do you think about the development plan going forward as it relates to not leaving any of those sections undeveloped? Because obviously if you're going to pursue a Showboat, Bernhardt, Horsefly type of model going forward, the risked backlog, location backlog presumably has to go materially higher.

Can you just frame that for me?.

Yeah. And it's a great question, Doug, as one that our teams wrestle with to come up with. And there's no perfect answer to that question. But I think the thing I would say first is that we are more focused on returns and rate of return of our project than anything else.

Now having said that, it is we do look at the overall NPV or NPV per dollar invested in the project. And if we're seeing a degradation of the NPV per dollar invested in a project, then that's when we get to the point where we say, well, our spacing or whatever else we're doing has perhaps reached a limit. And then we shouldn't go any further.

Now early on, it's important to remember, we're so early on in the appraisal and the development of the STACK play, where 95% of the wells are still in front of us. So we are testing the limits on some of these. And then we'll optimize more as we move forward.

But in general, it's a program that focuses on returns, NPV over I and maximizing from that standpoint, not only on spacing but all the other things, all the other factors that come into it. So there is upside obviously. I mean we're doing 12 wells per section in Showboat. They don't all look like Showboat necessarily.

Then there's going to be variability across the program. But obviously there is we think longer term upside to the six wells per section.

Wade, do you want to add anything to that?.

I think the only thing I would add, Dave, is that it's important I think to understand the recent historic development of the play, in that a lot of the early estimates for the play and even our last set of official guidance around six wells per section, that was done under the context of, in each section there's clearly a best reservoir target.

And as we have prosecuted the play and appraised the edges and appraised different landing zones, the upside we saw is that more than one landing zone in most of these sections is productive and economically competitive. And so clearly that likely will increase overall inventory for the play.

And so we're obviously purposely testing that in each of these developments this year. When we finish those, we'll be able to kind of put our pencil down and provide revised guidance around what we think our inventory numbers will be and what our actual full field development plan will be in the core of the play..

Guys, I don't want to labor this point. But just to be clear, Wade, you enter a process of updating type curves over the last year or so. I'm guessing that's just a grossly over simplistic way of looking at this full field development. But I just want to be clear.

Was that a full field devolvement type curve? Or was that like a single parent test type curve that you had given out previously?.

Well, this is Scott. I'll explain the nature of the type curve. And then maybe Wade could provide some additional context.

But the type curve that we put out over a year ago was predicated on largely a parent leasehold drilling with some modest infill spacing assumptions in the upper Meramec zone, which is the top reservoir target in the volatile oil core. That being said, I'll hand it over to Wade, and any context of how you think about it going forward..

Yeah, I think that your comment about a single type curve been overly simplistic is spot on. Because as I've noted, we now have multiple landing zones that we're going to target in each section. Those different landing zones have slightly different reservoir properties.

We also are mindful that we've shifted from a parent well, developed – or a parent well approach to now we're doing full field infill development. And I really reference back to Dave's comments around trying to maximize the return and capital efficiency of every dollar we spend.

So ultimately, we are likely going to be willing in some places to take a little bit lower EUR per well, as we can drive even lower capital costs per well. And so we're really working to find the sweet spot balance there..

Very, very clear..

All right. Just say, Doug, don't forget about the capital efficiencies. We are – these are great questions around the type curve. But also the capital efficiencies that we're getting with these developments are really driving the returns higher..

Yeah. I think your partner, Continental [Resources], laid it out pretty well last quarter. I think we know where we're headed with this. Scott, that wasn't question two. My follow-up is really just a very quick strategic question, Dave. I don't want to put you on the spot too much on your strategy, your strategic asset sales and so on.

But I wonder if I could just ask you to just opine quickly on your strategic commitment to Canada and the current EnLink ownership structure. And I'll leave it there. Thank you..

Doug, as you might suspect, that's a great try from you. But I'm not going to get any more specific than I currently described on it. And so we have a lot of options around it. We understand these options really well. But I don't think it's in our best interest to be any more specific..

Awesome. Thanks for taking the question. Thanks, guys. Bye..

Your next question comes from the line of Brian Singer with Goldman Sachs. Your line is open..

Thank you. Good morning..

Morning, Brian..

Going back to that probably debate from a great position with regards to efficiencies and CapEx. Definitely hear you, you don't want to lose the operational efficiencies and synergies.

Are there other areas within the capital program that become less core as a result of the efficiencies you're seeing in certain plays? And as you think big picture, when you see efficiencies or for that matter greater cash flow from higher oil prices, is it better to push growth in CapEx higher over the longer term? Or rather maintain growth with less CapEx, leaving more room for free cash flow and share repurchase?.

Hey, Brian, this is Jeff Ritenour. Yeah, I would say the latter. I mean that certainly is our game plan and approach. We're expecting to generate significant growth in cash flow as we work through the remainder of this year. As Dave talked about, we may trend towards the higher end of our capital program.

But we expect to generate significant free cash flow. And right now we have that excess free cash flow earmarked for share repurchase and return to the shareholders..

Great. Thanks. And then I don't believe anyone has asked an Eagle Ford question. It's noticeable that you expect a bump higher in production during second quarter. I think you've commented in the past some of the best rate of return wells are in the Eagle Ford.

Is that still the case? And while realizing there's a partner involved in the capital decision process, what do you see as the limitations to yourselves or anyone else running those assets, increasing activity?.

Brian, we like the Eagle Ford. It does have the highest margin production in the company. It's got probably some of the most prolific returns of anything we do in the company. And it's extremely predictable. So we do like that.

I think we've talked in the past that we have a fairly narrow horizon associated with just the lower and the upper Eagle Ford opportunities. We're continuing to prosecute those. And you're seeing some IDs come on here shortly that will boost production over the previous quarter.

In addition to that we're getting a lot of maturity about the opportunities associated with the Austin Chalk and also an opportunity that we call redevelopment, where we can go back in and lay some wells and mitigate some of the partial pressure depletion we've had from some of the existing wells.

And so all told and on an unrisked basis, we still think there are 500, 600 wells out there that we're still chasing with additional data. The relationship with BHP is very close and very tight. We feel like we're aligned on the technical side. They're going through a process right now. We have a couple of rigs working and some frac crews in the field.

And we'll continue really about the pace that we are at right at this point. But we will be pushing and excited to see some data points come in second half this year, early 2019 in the Austin Chalk and the redevelopment concept. And we feel like that's going to open up a new opportunity for us in the project..

Great. Thank you..

Your next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is open..

Good morning..

Morning..

Congratulations on the quarter..

Thank you..

Could you talk about the Second Bone siltstone a little bit. Seems like it's a new play that you brought out this quarter.

How is it geologically unique, thickness, typical commodity mix? And in particular is it an additional Second Bone zone? Or is it substituting for some other [Second] Bone zone that maybe drops off elsewhere?.

Yeah, this is Rick Gideon again. It's an additional Second Bone zone. I will tell you, it depends on where you're at in the field on the thickness. It's a siltstone that sits at the top of our – between our First and Second Bone. It depends on where you're at. But we're seeing good permanent porosity in this given area, enough H, as you see.

I think we've called out a couple of wells there in our Boomslang area of around 1,700 BOE per day. As we take a look, the size of the prize, it won't span across the entire basin. But it is prolific enough that we will continue to develop in this area..

Okay. Great, yeah, that's helpful. And my second question, I was surprised to see the Parkman and the Teapot activity is driving growth in the quarter, plus the attractive low well cost. Because I thought the Rockies program was primarily focused on the Turner, so that may have been my mistake.

But I was just wondering, is there an increasing interest in these other zones? Or were these wells sort of one-offs?.

This is Rick Gideon again. Those wells are not one-off. We are continuing to focus on the Turner. While we're in our early appraisal in the Turner in our spacing, we're continuing to execute on our Teapot and Parkman wells, which we've executed historically on.

You'll see us continue to bring some of those into the program, as we work up and down those channels and continue to bring on additional Turner wells..

But is it safe to say that – because I know that you've talked about longer term you'd like to get to the point where you can get into some sort of manufacturing mode in the Rockies. And that's a little bit troublesome, because it tends to be sweet spots.

But is the overarching plan at this point to try to find the largest Turner area that you can develop in a way similar to what you're doing in the STACK and in the Delaware Basin? Then maybe exploit some of these Parkman/Teapots as little sweet spots when they come up? Is that sort of the way to think of it?.

I think you stated that well. I would say we're looking at multiple Turner areas and multiple horizons in the Turner. So we're looking at how we can best develop, and you've seen some of our spacing tests in the upper and the lower Turner.

Let's not forget we're still looking at the Niobrara in that area also, which we think could have very large upside. But as we continue to execute through those programs, you will see some additional Parkman and Teapot..

Okay, great. That's very clear. I appreciate it..

And we're now at the top of the hour. We appreciate everyone's interest in Devon today. And if we didn't get to your question, please don't hesitate to reach out to the Investor Relations team at any time, which consists of myself and Chris Carr. Thank you, and we'll talk to you soon..

This concludes today's conference call. You may now disconnect..