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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning. Welcome to Devon Energy's Fourth Quarter and Full Year 2017 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, and good morning. I hope everyone has had the chance to review our financial and operational disclosures that were released last night. This data package includes our earnings release, forward-looking guidance and detailed operations report. Additionally, for the call today, I want to make sure everyone is aware that 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 and then 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 how we expect our business to perform over the next three years. Following Dave, Tony Vaughn, our Chief Operating Officer, will provide detailed commentary on our fourth quarter production results, along with other key operational themes. And then we'll wrap up our prepared remarks with a review of our financial strategy by Jeff Ritenour, our Chief Financial Officer.
Turning to slide 2. 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 related to these statements, please see our Form 10-K.
And with that, I will turn the call over to our President and CEO, Dave Hager.
Thank you, and good morning everyone. As Scott mentioned earlier, Tony will cover fourth quarter results later in the call. My comments today will focus on our outlook for 2018 and the strategic direction of Devon over the next several years, which we have branded as our 2020 Vision.
However, before I get into my prepared remarks, I want to address a topic that we have received a lot of questions on, and that is why we have not authorized a share repurchase program. Let me be clear. As we generate more cash through our operations and asset divestiture programs, we will reward our shareholders through higher dividends and opportunistic share buybacks. However, our near-term priority is to use a significant portion of our large cash balance to reduce the debt associated with our upstream business.
Why is this our top near-term priority? With our world-class Delaware and STACK positions shifting to full development mode, it is absolutely critical that we possess a top-tier balance sheet in order to maintain consistent activity levels through all cycles. Commodity prices go up and down, but our plan to execute on a steadier and more measured development program through all cycles will optimize returns and value associated with our development programs.
And while we certainly could have authorized a couple billion dollar share repurchase program today and had our stock price positively respond to this type of announcement, it is not the correct move for Devon right now. Our business is performing at a very high level, and with the continuation of current commodity prices, coupled with imminent asset sales during 2018, I am confident in stating that there will be increasing shareholder returns this year.
Moving to slide 3. With our world-class assets in the Delaware and STACK shifting to full-field development, I can confidently state that Devon has reached an inflection point as a company. With our low-risk development programs focused in our top-tier U.S. resource plays, we expect to deliver a dramatic step change in capital efficiency while delivering attractive corporate-level returns.
In 2018, we plan to invest approximately $2.3 billion in our upstream properties with the majority of this capital concentrated on high-return developments in the economic core of the Delaware and STACK. This focused development plan allows us to bring online greater than 25% more wells than in 2017 for a very similar amount of capital investment. Additionally, this program is self-funded at our base planning scenario of $50 WTI pricing.
On a retained asset basis, our capital plans in 2018 are expected to drive U.S. oil production growth of roughly 14% compared to 2017. Importantly, the trajectory of Devon's U.S. oil production profile is expected to steadily advance throughout the year and exit 2018 at rates greater than 25% higher than the 2017 average.
I do want to be clear on this. We have no shortage of highly attractive growth opportunities within our portfolio and could definitely grow at much higher rates in 2018 if we chose to optimize top line production with our capital allocation. However, we are absolutely committed to doing business differently in the E&P space and we are optimizing our capital allocation to maximize corporate-level returns while delivering capital-efficient cash flow growth.
We fundamentally believe that a steadier and more measured investment program through all cycles is the correct strategy to efficiently expand our business and maximize Devon's valuation in the marketplace as opposed to pursuing maximum production growth in any one given year.
Turning to slide 4, while Devon's business outlook in 2018 is very strong, I am much more excited about the expanding profitability and improving returns our business is capable of delivering on a multi-year basis.
However, before I get into the specific performance targets associated with our three-year plan, I do want to cover the strategic principles that underline or underpin our business model and will guide our behavior over the next several years.
First, to maximize and steadily expand the cash flow of our upstream business, we will continue to deploy leading technologies to optimize the productivity of our base production wedge. We also will aggressively work to improve our per-unit cash cost to get the most value we can out of every barrel produced.
And while maximizing cash flow is a top priority, we are in a depletion business that requires significant reinvestment. Given this dynamic, continuous improvement and capital efficiency will separate the winners and losers in this highly competitive space. And at Devon, our ability to stretch every investment dollar further is one of our top competitive advantages going forward.
With our industry-leading multi-zone development techniques at the Delaware Basin and STACK, we are positioned to deliver not only dramatic improvements in capital efficiency, but also substantially increase the net present value of our acreage through improved recoveries and more efficient operations.
With our Delaware Basin and STACK assets rapidly building momentum and operating scale, we are committed to simplifying our asset portfolio by selling less competitive assets. While we'll not go into the details of which assets we are currently evaluating to sell, we will be patient and sell assets only at the right price and as market conditions allow to ensure we bring forward the appropriate value for our shareholders.
Another critical objective is to further improve our investment-grade financial strength. Our goal is to achieve a net debt-to-EBITDA ratio of 1.0 to 1.5 times and maintain the ratio in a sustained $50 WTI price environment.
As I touched on to begin the call, another very important strategic intent of our 2020 Vision is our commitment to returning increasing amounts of cash to shareholders. Jeff will provide more details on both our debt targets and the return of cash to shareholders later in the call.
Moving to slide 5, we expect the strategic principles supporting our 2020 Vision to advance several key performance targets over the next three years. Keep in mind, with these targets we're simply showcasing how we expect our business to perform under a flat $50 WTI and $3 Henry Hub price deck. As we all know, industry conditions will evolve, and when they do, we will recalibrate our actions to optimize returns and capital efficiency.
First and foremost, with this disciplined game plan, we expect to deliver fully burdened corporate-level returns in excess of 15%. In conjunction with these attractive corporate returns, we expect capital requirements over the next three years to be funded within operating cash flow at a $50 WTI price point. Under this scenario, our capital programs will drive oil production growth of greater than 25% annually in the Delaware and STACK, advancing our total U.S. oil production by around 15% per year over this time period.
In addition to growth in high-value production, another key component of our strategy is to enhance profitability through the aggressive improvement of our cost structure. By 2020, we expect a combination of lower operating costs, declining interest expense and an improved overhead structure to translate into per-unit cash cost savings of approximately 15%.
These cost savings, combined with strong oil production growth for the Delaware and STACK, will expand Devon's upstream business cash flow by more than 15% annually through 2020. Put another way, given our advantaged portfolio, we will be able to attractively grow our business on a sustainable basis at a flat price deck of $50 WTI pricing. We will also have tremendous torque to the upside at higher prices as well. At $60 WTI pricing, we would be able to generate $2.5 billion of cumulative free cash flow over the next three years.
As we build critical mass in the Delaware and STACK, we also are working to maximize shareholder value by simplifying our asset portfolio. Given our resource-rich asset base, we see the potential to monetize in excess of $5 billion of noncore assets in a very thoughtful and measured fashion over the next few years.
Combining these asset sale targets with our free cash flow generation capability at $60 WTI pricing, Devon's total cash inflows in excess of our planned capital requirements over the next three years could range up to 40% of our current market capitalization. As this excess cash flow manifests itself during 2018 and beyond, I emphasize again, we will reward our shareholders through higher dividends and opportunistic share buybacks.
Moving to slide 6. Another positive initiative underway at Devon is the steps we are taking to further align our management incentives with that of shareholders. In 2018, Devon will incorporate two return-oriented measures into our compensation packages. As you can see on the slide, one measure will calculate cumulative returns on capital employed, while the other will calculate returns in our current drilling programs.
Both return measures will be burdened by all corporate costs, which include G&A, corporate capital, land and all other technology initiatives. Additionally, we are going to advance other shareholder-friendly initiatives in 2018 that would improve the transparency of our business results such as improved environmental sustainability reporting. I will provide updates on these initiatives in future calls.
At this point, I will turn the call over to Tony Vaughn for additional commentary on our operations. Tony?
Thanks, Dave, and good morning everyone. On slide 7, I'd like to begin my prepared remarks today by providing some additional context around our fourth quarter production results.
Our oil production shortfall for the quarter was primarily driven by oil volumes within the U.S. due to the timing of well tie-ins associated with non-operated activity in the STACK. In aggregate, these near-term timing issues limited our U.S. production by nearly 10,000 barrels per day of oil in the quarter. Two thirds of this volume impact was attributable to the timing of non-operated pad developments from multiple partners within STACK.
Importantly, this issue in the STACK is now behind us, with the tie-in of more than 50 non-operated wells in early January. The spike in non-operated activity drove our current daily rates in STACK to approximately 130,000 BOEs per day, an increase of greater than 10% compared to the fourth quarter average.
To be abundantly clear, the production shortfall in the fourth quarter was not related to reservoir performance or the pace of our operated well activity. In fact, in the fourth quarter, our operated well results were some of the best in Devon's 46-year history. Our top 30 operated wells in the quarter averaged initial 30-day rates of greater than 2,500 BOEs per day.
Combined with the ramp-up of volumes in the Delaware Basin in early 2018, the production from our two franchise growth assets is currently approaching the 200,000 BOE per day barrier and is on track with our plan to grow oil production by greater than 35% from those two assets in 2018.
Moving to slide 8. As we have talked about length today, the 35% plus growth we expect from our world-class assets in the Delaware Basin and STACK during 2018 is driven by our transition to full-field development. Importantly, the majority of this activity in the upcoming year will leverage our multi-zone development schemes in the economic core of the Delaware and STACK.
As you can see on this slide, with this leading-edge development concept, we have more than 10 multi-zone projects scheduled in 2018, with several of these projects already underway. Early results from this leading-edge development concept further support our conviction that this is the innovative approach with the best way to efficiently convert stack pay and cash flow and production.
On slide 9, at the Anaconda project in the Delaware Basin, our initial multi-zone development, we achieved capital cost savings of approximately $1 million per well compared to traditional pad developments. These cost savings were driven by the benefits of centralized processing facilities, faster drill times, completion efficiencies that reached up to 14 stages per day at this project. In addition to the $1 million per well cost savings, well productivity at Anaconda was also very strong. Average per well 30-day production rates at the 10-well Anaconda program reached 1,600 BOEs per day.
Overall, a great result for our first attempt, but we definitely expect to improve with future projects. In fact, an early example of this continuous improvement is that our second multi-zone project in the Delaware, the 11-well Boomslang project, at Boomslang, rig productivity reached nearly 1,400 feet per day, breaking the previous record drill time achieved in Anaconda by nearly 15%. Completion operations are underway, and we expect to have more positive news to report on Boomslang and several other Delaware projects in the next quarter.
Now turning to slide 10, initial results from our multi-zone work in STACK are also very encouraging. At the Showboat project, drilling operations for the 24-well program concluded in January, ahead of schedule, with average rig productivity exceeding 1,000 feet drilled per day. This represents a 30% improvement in drilling efficiency compared to prior leasehold drilling in the area, translating into an average savings of about $500,000 per well.
To the west of Showboat, our Coyote development project is also progressing. Drilling operations at Coyote have also shown positive results, with drilling times improving by as much as 25%, over the course of this 7-well project compared to historical single well activity in the area.
Completion operations at Coyote are currently ongoing, but our initial well from the Coyote development is now flowing back, achieving 24-hour IP of 8,200 BOEs per day, 8,200 BOEs per day, of which more than 60% of that is oil. This is by far the highest well productivity we have seen to date in the play. So as you can see, our full-field development work in both the Delaware Basin and STACK is off to a great start.
On slide 11, a key component of this strong execution that should not be overlooked or underestimated is the operational planning and supply chain efforts underway at Devon that are critical to ensure the certainty of services and supplies to deliver on our capital plans. While the service market is unquestionably tight right now, especially in the Permian Basin, our supply chain team has proactively secured rigs and pressure pumping services at competitive prices to execute on our capital plans in 2018 and 2019.
The multi-year development plans we have designed for each asset, along with a disciplined hedging strategy, allowed Devon the opportunity to secure long-term relationships at below-market rates with top providers.
On the drilling side of the business, we had the rigs we need under contract to execute on our 2018 program. In fact, we entered the year at around 20 rigs, and due to efficiencies associated with our multi-zone developments, we plan to gradually reduce our rig count to exit the year at about 16 to 17 rigs. While industry will see some increases in day rates and drilling-related services, our contracting strategy and efficiencies in the Delaware Basin and STACK are expected to more than offset this inflation. In aggregate, we will generate cost savings on the drilling side of our business through our improving efficiencies.
Another key area of tightness in the marketplace is pressure pumping. Within the Delaware Basin and STACK, we have largely secured our horsepower requirements in 2018, with plans to utilize seven dedicated crews. In addition to the raw horsepower, we have also have contracts in place for the majority of our sand requirements, water, diesel, chemicals and last-mile logistics in 2018. Our strategy of debundling completion services and efficiencies from our multi-zone projects will result in significant cost savings in 2018.
So overall, across all phases of our business, we have agreements in place for more than 75% of our total capital requirements during 2018. While we do expect industry service cost inflation to be somewhere in the mid to high single digits in 2018, we believe our efficiency gains in the Delaware and STACK are projected to more than offset these higher costs.
Another area that we have done a lot of good work on is with our marketing and flow assurance. We have firm transportation covering a significant tranche of our production in both the Delaware and STACK. And in Canada, we have basis hedges covering around half of our production at $15 off WTI. These attractive hedges are currently worth approximately $300 million.
Bottom line, with this good upfront planning work from our operations, marketing and supply chain personnel, we are well positioned in a tight market.
And with that, I will turn the call over to Jeff.
Thanks, Tony. For my prepared remarks today, I'd like to discuss our financial priorities within the context of our 2020 Vision and highlight the next steps in the execution of our financial strategy.
As you can see on slide 12, we have tremendous amount of flexibility when it comes to our financial position. We exited the year with $2.7 billion of cash on hand and expect this balance to meaningfully increase in the very near future once we finalize our Johnson County divestiture in the Barnett.
With regards to Devon's capital allocation, our first priority is to fund our operational plans in the Delaware and STACK as these early-stage assets transition to full-field development. Growth in these assets will drive additional operating and capital efficiencies along with higher overall margins for the company. Importantly, we expect to fund both our maintenance and growth capital requirements for the company through 2020 within operating cash flow at a $50 WTI price deck.
Another key financial priority is to achieve and maintain peer-leading investment-grade financial strength. To this end, we have set a target leverage ratio of 1 to 1.5 times debt-to-EBITDA. With the addition of our Johnson County divestiture proceeds to our cash balances, we expect to reach the targeted ratio range early in 2018. Given our strong liquidity, we will begin utilizing a portion of cash on hand to tender for outstanding debt.
This absolute debt repurchase will reduce our go-forward annual interest expense and help us achieve the targeted 15% cash cost savings Dave mentioned in his opening comments.
We will finalize size and timing of our initial debt tender in the coming weeks, but I expect this initiative to reduce our absolute debt by as much as $1.5 billion during 2018. Beyond this initial debt repurchase, we will balance additional debt repurchases against our other financial priorities, but will remain committed to sustain our targeted net debt-to-EBITDA ratio in a $50 WTI price environment.
Another critical component of our financial strategy is the return of excess cash flow to shareholders through dividends and share repurchases. From a dividend policy perspective, our goal is to sustainably pay and steadily grow the dividend. We are targeting a manageable payout ratio of 5% to 10% of our operating upstream cash flow at our base planning scenario of $50 WTI pricing.
In addition to the quarterly dividend, with excess cash from asset sales or a windfall from higher commodity prices, we expect to reward shareholders through opportunistic share buybacks or potentially a special dividend. We will provide more updates on this topic in the future disclosures as excess cash flow manifest in 2018 and beyond.
Shifting briefly to tax reform. The recent changes in U.S. tax law were favorable to Devon and have enhanced our ability to return cash to shareholders in the future. While tax reform did not materially impact our fourth quarter or full year 2017 results, the tax reform will positively impact our ability to repatriate foreign earnings back to the U.S. In the future, the free cash flow generated from our Canadian operations can be transferred tax efficiently to the U.S. to help fund our growing, high-margin asset base.
Outside of tax reform, we completed a legal entity restructuring in Canada in 2017 that will significantly reduce our current tax expense going forward. The tax reform and legal entity restructuring resulted in material entries to our deferred taxes, driving some of the noise you see in our effective tax rate for the quarter and year end.
And finally, I do want to recognize our accounting team here at Devon and their efforts on the conversion from the full cost accounting methodology to successful efforts. A lot of long hours and hard work went into making this change in accounting policy. We believe successful efforts accounting provides several benefits, including greater transparency into the financial performance and better comparability of results to peers.
Going forward, we expect the change to help us highlight the superior capital efficiency of our core assets. We have included a supplemental disclosure packet on our website that highlights the changes on a reported quarterly and annual basis for 2017 as a result of the conversion to successful efforts methodology.
With that, I'll turn the call back over to Scott.
Thanks, Jeff. We'll open the call to Q&A now. Please limit yourself to one question and a follow-up. If you have any further questions, you can reprompt as time permits. With that, operator, we'll take our first question.
Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning everybody.
Good morning, Doug.
Dave, I understand you don't want to be specific on potential asset sales, but I wonder if I could just ask you to opine a little bit on two things, where the Powder River fits in your development outlook. Because either it looks to us like we see we're going to get a core asset or it's been primed for sale, and I'm leaning towards the former.
And my second issue I guess, related to the same thing is, what's in the development outlook that you have, particularly in the Delaware, what is the strategic role that EnLink plays going forward? And I'm just curious whether EnLink is part of the $5 billion target potential asset sales over the next several years. And I've got a quick follow-up, please.
Sure, Doug. Well first off, it's very clear that the two key core assets for Devon going forward are the Delaware and the STACK play. We have positions there that are as good as anybody's, and we are having outstanding results and they are going to drive the growth in the company for the next few years. And they're going to take the bulk of the capital for the next few years.
Outside of that, we do still have some great assets in other areas, including the Powder that you mentioned, Barnett, Eagle Ford in heavy oil as well as the EnLink. Specifically in regard to the Powder, we like the opportunities we're drilling there in the Turner. We see some potential there in the Niobrara as well, and we're going to be drilling some wells there. We think there's a good growth opportunity.
But again, it's not going to reach the scale of the STACK and the Delaware. So I'm not going to get more specific than just to describe that obviously, the two most important are the STACK and the Delaware. And we understand the pluses and minuses and the optionality we have around all of the other assets in our base, whether it be E&P or a midstream asset. But obviously we have a lot optionality.
And the reason – I'm not trying to be coy on this at all – but we're trying to maximize the value that we can get. And market conditions change through time too. And so to announce a strategic decision one way or the other when we have a lot of optionality and market conditions change is really not in the best interest of the shareholders, we don't think. So we have that optionality there. There's a lot of ways we could accomplish this. And reiterate once again that when we do this, you can look for us to be authorizing a way to return value to the shareholders.
I appreciate the detailed answer. I guess my follow-up is also on EnLink and the buyback, Dave. I mean, I guess you kind of answered the question with a 40% number, at least in terms of the scale of the cumulative cash flow you could generate. But when you look at EnLink specifically, you know I've been rabbiting on about this for a while, that the consolidation discount, the debt metrics, all the things that go along with that and the strategic role in the company, can you just lay out, is there an option where EnLink can some way be deconsolidated while still retaining the necessary strategic control you'd acquire? And is that 40% number in the three-year timeline a reasonable basis that we should be thinking about by share buybacks? And I'll leave it there. Thanks.
Hey, Doug. This is Jeff Ritenour. In regards to deconsolidation, from an accounting standpoint in our financials, as long as we maintain control, we're going to end up consolidating the financial results. So don't expect to see any near-term deconsolidation short of a relinquishment of that control, which would really be driven by not only a sell-down of units, but ultimately we'd have to be at a position where we weren't in a control position, whereas today we actually sit on the board as you guys know. So don't see a consolidation in the near term.
From an overall investment thesis as it relates to EnLink, as you've heard us say many times, we like the investment. The distributions that we receive on an annual basis amount to about $265 million, $270 million a year. That is a material portion that goes towards funding our E&P capital budget each year. So again, and on top of that, you have the operational synergies in our core areas.
So both in the STACK play and obviously in North Texas, the relationship we have with EnLink is important to us from an operational standpoint. In the Delaware, not so much today. EnLink's business is just starting to grow in the Permian, and specifically, with an overlap on our Delaware assets, there isn't significant synergies there today.
Jeff, just to be clear, the control comes from the 2% GP, right? Does that mean the equity interest down to that level could be for sale? And I'll leave it at that. Thank you.
You're exactly right. The control does come from our ownership of the GP. And really, it's a little more complicated than that, in that we own 100% of the managing member of that general partner, which deems control over the entity.
Right. Thanks, guys.
Our next question comes from the line of Paul Grigel from Macquarie. Your line is open.
Hi. Good morning, guys. Just wanted to focus in on the management incentive plan here, really a two-part question. Are there additional changes alongside the addition of return calculation that we should expect? And second, how should we expect to view the transparency element moving forward within those calculations?
Hi, yeah, be glad to answer that, Paul. First off, yeah, these are going to be incorporated in our balanced scorecard that we use for the pool for our bonuses. You will see us take out a couple of measures that we have in there currently, replace those with these. We're going to be taking out the reserve adds measure and we're going to be taking out a pre-tax cash margin per BOE measure that we had in there historically.
We view these as a couple of the most important measures that we'll have in that balanced scorecard. And although we haven't fixed the exact percentages of what these will represent of our balanced scorecard, I can tell you that typically our more important measures each represent 15% to 20% typically. So I would expect this to be 30% to 40% of the total calculation.
But I think even as important as the actual math behind this, I can just tell you from a focus standpoint within the company and the conversations that are taking place internally at the company, that this is something that we have always been focused on it, but there's no question that it has intensified dramatically in the last six months.
And I think you can see as far as the transparency, we tried to provide some transparency in our operations report as to what we are targeting. We will give you as much of the detailed formula as possible here of how we are going about calculating those measures. We can describe that now. It gets a little complicated, but we'll certainly put that in the proxy so that understand how we're calculating it. We've laid out what the targets are.
And then the one measure, the cash return on capital employed is going to be something that you could easily measure straight off the financial statements. And so you can check it yourself. The other measure, which is the all-in asset return measurement, that really goes to the productivity of the wells. And so we're not going to actually provide the details of every decline curve of all of the wells that we drill there, but it'll be tied into our reserve report, which of course is audited every year.
And so it's going to be a very comprehensive and very accurate measure that we feel will give as much transparency as anybody in the industry around these numbers. And again that includes all overhead costs associated with – all costs associated with the corporation.
So I know a lot of them like to talk about well-level returns of 50% or 100%. We understand that's a fallacy frankly to even be talking about those kinds of things. This is where we are getting and what kind of returns are we generating for the shareholders. That's what we think's the most important and that's what we're going to provide as much transparency as we can.
No. That's great. That's terrific. I guess changing one to 2018 guidance as a follow-up, could you guys go through some of the thoughts as you laid out 2018 guidance on either the risking of the non-op guidance moving forward as well as risking on the timing of some of your large pads? You mentioned that they may be actually coming forward, but curious how those were risked within the 2018 guidance as well as the non-op productivity.
Yeah, I might kick this off and then turn it over to Tony for a little bit more details. But obviously we were disappointed with our miss on Q4 production guidance. And we took the guidance that was provided by the operators on those approximate 50 wells and that's what we plugged into our guidance. If you look at the STACK overall, it's a little bit more significant proportion of the STACK production. In other places I think around 23% or so our production is outside operated.
I can tell you that we have taken a much more conservative approach to forecasting non-operated volumes in 2018 versus 2017. I guess you can say we learned our lesson there. We thought we were being appropriate, but in hindsight, some things happened that we didn't know was going to happen with those non-operated wells. Again, the key is though that all of our operated activity is just doing outstanding, but we have taken a more conservative look to the outside-operated wells. And certainly, we've taken a measured approach to our expectations of when our operated large pads are going to come on as well, to make sure that we have confidence in the guidance. So Tony, you want to take it, more detail on that?
Yeah, you bet, Dave. Just to add a little bit to what you said, I think if you look at our work on these multi-zone projects, we probably have roughly about 25 to 30 projects in some level of maturity between STACK and Delaware. We're working those plans. We have a very disciplined stage gate process that we have a lot of transparency into what we're doing. You can see in our operating report, we have about 10 or 11 of these projects that are going to be really impacting 2018 highlighted here.
And the way we kind of think about this is we're trying to keep the projects of the right size and scale to reap out the benefits of the efficiencies of doing these batch operations and (36:59) and utilizing centralized production facilities on a greater number of wells and pads. But we don't want them so large that we just get extremely lumpy like we might have seen when we were in the offshore business.
So we've done a pretty good job of scaling these appropriately. The one large one that you see in 2018 is the project that we're on right now, which is the Showboat project. And in there, we have gotten through the drilling portion of this project and saw some great cost savings there on the drilling side. It's hard for us to explain and convey the synergies and the efficiencies we have when we get when we can park rigs, three or four rigs on a location and just execute, execute and execute. And we're seeing it in spades here on the drilling side of the business.
I mentioned in my prepared remarks, we're also starting to see this on the completion side of the business, where we're zipper fracking not just two wells, but three wells together. And our efficiencies on that side of the business are peaking and really, the cost per well on the facility side is going to be competitive and even improving over time as we continue to utilize all these facilities.
So we think this is the answer to go. I think we've commented in the past that we think the present value uplift here is 40%. We still believe that. And I think we're very pleased with the early work we've done on these that we've commented on where we are in the maturity of our ability to execute on these. So we're excited about this part of our business.
Paul, I might just add, too, that when we first rolled up our 2018 oil guidance as a company, our total number was really very, very close to the Street average that we had. What happened really more recently that caused it go a little bit below the Street average is in Canada, where we're going to be experiencing higher royalties because of higher WTI prices. And so we're going to be going from a, as you probably understand, the royalties out there are not based on WCS prices. They're based on WTI prices. And so based on that, we have taken a more conservative assumption on what we think royalties are going to average throughout the year and increase those from I think around 5% to 7% or so. And that's really caused our overall oil production guidance to fall a little bit I think below where the Street expectation was.
No, that's all very helpful color, appreciate it.
Our next question comes from the line of Matt Portillo from TPH. Your line is open.
Good morning, Dave and team.
Good morning, Matt.
Just a question in your release, you highlight the potential over the next few years to reduce your costs, cash cost by about 15% on the operating level. Could you talk about some of the initiatives you're working on and where those trends might start to show up in terms of the cost savings over the next years?
Sure, Matt, and that's going to be about $2 per BOE we anticipate reducing from that. Several different things that are going to contribute to that, one of which is obviously we're going to be growing our volumes. And so we do not see our G&A or our LOE really increasing as we grow the volumes, so the per-unit costs are going to be coming down. I can tell you we're taking very hard looks also at both of those areas as to make sure that we are really maximizing the efficiency there. And we have initiatives going on where we see scope to improve in both of those areas on an absolute basis as well.
We also anticipate the interest cost coming down. Jeff has talked about the debt paydown, and so that's going to also. So you put all three of those together, we see about a $2 per BOE improvement. I might also mention that we're all anticipating, as our mix changes, and we have more oil as part of our production mix in the future, we also see about $1 per barrel improvement on the revenue side at flat prices. That's just as we move to more oily mix in it. So all told, about a $3 improvement on the per-unit basis.
Great, thank you. And my follow-up question is just in regards to the asset side of the business. Could you remind us your current acreage exposure in Ward County, south of the state line and just thoughts around capital allocation on that asset over the next years given the focus in the northern Delaware Basin at this point?
Just as a rundown of our overall Delaware position, we have about 300,000 surface acres, and about 90% of that's north of the state line area in New Mexico. So directionally, on the Texas side, we have 20,000 to 30,000 acres. Not all of those are in the counties that you referenced, but mostly concentrated in that area.
And if I can expand on your question a little bit here, we talked a little bit about the $5 billion of asset divestitures. And so the way that we look at that is we, and once we complete the Johnson County divestiture in the Barnett, which we frankly wish that had been done by the time of this call, but we think that is right around the corner from us here. And we're very confident that that's going to get completed here by the end of Q1. But once we do that, from our first phase of divestments, we'll have accomplished $1 billion or more of divestments.
We see about $1 billion more of incremental portfolio cleanup that we can do with only minor impact on production. And that could include areas, like you mentioned, Matt, as part of that overall strategy. And we are in the process of putting that plan together and finalizing that plan, and you'll see us executing on that plan in 2018. So that would get us up to about the $2 billion number. And then beyond that, that's when we really get into the more strategic decisions. And again as I've said, it's our primary growth areas are the STACK and the Delaware. And beyond that we'll look at everything else that makes sense on an opportunistic basis.
Thank you very much.
Our next question comes from the line of Bob Brackett from Bernstein Research. Your line is open.
My question about the non-op strategy. It sort of hits you a bit in the STACK, and you have some activity in the Eagle Ford that's non-op. Are you happy with your level of non-op or is that something you'd clean up over time?
Bob, I think and generally we're happy. If you just look at the component of non-op to the company, on a total capital basis, that's certainly less than 10% of the company spend, and on a production basis it's about 12% if I remember the numbers right. It happens to be concentrated, a large portion of that OBO volumes happen to be concentrated in the STACK play and that's really the cause of this one miss.
And you know our STACK team, we really operate the OBO component much like we do the operated component, so we're very in tune with what our operators are doing. We have technical meetings with those. We try to participate in a lot of activity in STACK just so we have a ample library to help us on the operated side. We probably have the deepest inventory of data of any of the operators in the STACK. So there's some true benefits to us having that component in STACK and that's helping us.
The relationship that we've had with BHP is similar to what it's been over the past few years in the Eagle Ford. And there, we're operating a couple of rigs this year. The way the Eagle Ford tends to work is when we have frac crews in the field and working new completions, we see a dramatic boost in rate, and when we don't, you see a pretty steep decline on that. And we're prepared to put a couple of rigs back on the completion side of the business in the Eagle Ford.
So we saw a little bit of a decline moving from Q4 to Q1 on the Eagle Ford, but it's going to really bounce back up. So I think we're happy. We got good operators and we learn a lot from those operators.
Yeah, Bob, I'm going to ask Wade Hutchings, who manages all of our STACK business, to comment a little bit on that. But I think the thing that you're going to hear is we participate in more wells than any other operator in the STACK play. And so when you see the fact that our operated activity, we've not had any hiccups. All of our wells have really performed at a very high level. That's one of the benefits of having some outside, some OBO activity, that we get a huge amount of data from a very large amount of wells that are drilled in the play, and it allows us on our high working interest wells that we operate to really produce outstanding results. So Wade can you expand on that a little bit more detail?
Happy to, Dave. I think the key thing I would note for us is the biggest value for our OBO investments in STACK has really been accelerated learnings. We're generally happy with the results that we see on a financial basis. We actually get to control which wells we elect into and wells that look marginal we'll stand out of. But ultimately we come back to the most critical thing we are trying to determine today in the STACK is the appropriate development scenario.
And you see that in 2018, that makes up the bulk of our own operated investments, trying to answer how many reservoir compartments are there in the Meramec and how many wells per reservoir compartment make up an ideal development scenario. We're really accelerating that learning because we're participating in multiple development pilots today with several of the key operators in the STACK. And so again, I'd just reiterate, we get a very large amount of value on accelerating our learnings for how we're going to move into full-field development in the STACK today.
Okay, great. That's clear. Thanks for the details.
Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your line is open.
Good morning.
Morning.
Dave, my first question is with regard to the master development plan approach that you're taking with the BLM. Looks like you increased your approvals from 2 to 4 MDPs in the quarter. And if I read it right, there's an aspirational goal of up to 1,600 permits, which sounds like a multiyear inventory. I was just wondering, in particular can you discuss what commitment the BLM is making to Devon when it approves these MDPs and how it's going to shape your development.
Sure, be glad. And we have also in the room here today Rick Gideon. Rick handles all of our Delaware activities as well as our Rockies activities. And so I'm going to let Rick – he's eminently familiar with all this and I think he'll give you a more thorough answer than I will. So Rick?
Thank you, Dave. When we take a look at these MDPs, the overall plan is so that we can get permits not just on subsurface, but surface right-of-way, takeaway, battery, et cetera. So what we can do is cover the NEPA, the surface area all at one time. In doing this, it helps the BLM to be able to do more permits in a timely manner. So we work very closely with them, have a very good relationship. Once you have that approved, it then works on to the APD. Upon approval, the commitment from the BLM by statute is 30 days after we get those approved.
Okay. So then really shouldn't think of this in terms of being like a multiyear thing. It's more maybe like an annual thing that's going to roll from year to year, and then when you get the approvals from BLM, you'll decide which ones you want to move on and which ones not. Is that sort of the way it works?
Well, we're always prioritizing our asset, so the MDPs you will see are in the prioritized portions of our field, the best parts of the best rock. When we plan, we do plan for these multi horizons. And as we find out more information, you could see some minimal change to the drilling plan on whether a certain horizon is included, how many wells per section. But as we go into the planning for right-of-way, for takeaway, for battery, we plan for success. And so you'll see some changes within each of those MDPs. But we're prioritizing the best parts of our field.
Okay, well yeah, that's helpful. My other question is using Anaconda as an example, but I mean you could refer to any of your major projects, Boomslang, Seawolf, whatever you like. You developed 10 wells in three landing zones. You said that centralization created all kinds of efficiencies, and it saved $1 million a well. What I'm trying to get a vision of is things like how many more wells and how many zones do you expect to drill in Anaconda in the future and in what size batches? I'm trying to get a sense of how you balance between the multi-zone development advantage that you've talked about while not overcapitalizing the project infrastructure.
Rick's going to handle that question again, so.
As we build these batteries, we're planning, and you may hear us utilize a term, drill-to-fill, and I'll utilize this both for the Delaware and the STACK. As we come back, we can reutilize that battery for the rest of the wells in that section. Depending on where it's at, when you take a look at an Anaconda, obviously we can finish the Leonard. We've already developed the Bone Springs in that area. But as we come back to these different independent zones that are not dependent or sharing the same pressure regime of some of these, we can reutilize that battery in the same section or even sections next to that section when we come back and drill. So you'll see even more use of that centralized battery as we move forward.
Okay. So the point is, the infrastructure is not necessarily just tied to the one project that we hear about, but it might be able to be parasitized in a useful way to (51:44)?
Yeah, I think that's the way to think about it. If you look at it on a map, these developments that we're doing, there are still a lot of areas immediately around these developments that are not yet developed. And so this infrastructure can be used as we develop those other areas as well.
Okay, great. That's very helpful. Thank you.
Our next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Good morning, Dave, to you and your team.
Morning, Charles.
I wanted to ask a question, and I apologize if someone else touched on this, but I may have missed it. But I believe Tony talked about this 8,200 barrel a day well at Coyote. And I wonder if you could go back over, talk about some of the specifics of that well. Presumably, it was a long lateral, but if you completed it any differently and how that result fit versus what you were expecting kind of pre-drill or pre-completion.
No, nobody else talked about it. We could have four or five more questions about it if you want, but no, it's obviously a great well but we're going to have a lot of good wells out here. But, Wade, do you want to talk about it a little bit more?
Sure, happy to. So, Charles, this well that we're referencing is the first well in our Coyote development project that has come online. It is actually very close to another well that we released results on in fourth quarter, the Faith Marie well. That well ended up with a 30-day IP of around 4,700 BOE a day. Again, the 8,200 BOE per day is just a 24-hour IP, but very encouraging results. It's in the kind of northwest part of the Meramec play. The target in that area is in the lower Meramec. And frankly, what we're seeing there is just excellent reservoir properties. And so we look forward to the rest of the Coyote wells coming online, and then you'll see other projects of similar size come online over the next one to two years in that area.
Got it. Thank you for that detail. Am I getting the right message, that if you view the big driver being excellent reservoir properties in the area, that this is more likely to be representative than an anomaly, at least for this pad?
Well let me, I'm going to change – answer that and start off an answer and Wade or Tony can chime in a little bit here, too. That this Meramec is a little bit different than some of your unconventional plays, and it has some conventional porosity and permeability. And so you have to think about when it has that, that you may actually be able to increase your EUR and drill less wells to recover a similar amount of hydrocarbons than you originally anticipated.
So we're going to find areas out there such as this, where I think our well density is actually going to be a little bit less than we maybe originally anticipated. Extremely highly productive wells, but we're going to have higher EURs also. And so from a capital efficiency standpoint, that's a really good news story. But you have to think about that a little bit differently than you may in some of the shale reservoirs where you probably may not have the opportunity to increase your EUR as much when you see the interference between the wells.
So, Wade, you want to expand on that a little bit? Because that's I think a concept that's really important. Because sometimes when we hear people say, okay, we're going to develop this on four wells per section rather than six wells per section, people may look at that as a negative. Well, in some areas it may be. But here, it may actually be a positive because you're going to recover a very similar amount of hydrocarbons, just have to drill less wells.
Yeah, I think I would expand on that by noting the team here at Devon has mapped each one of these reservoir targets across the Meramec all across the play. And they do change their reservoir quality in a geographic sense. And so as we have been appraising the field over the last couple of years, that's what we've been trying to determine, is where are the best reservoir quality in each of these potential landing zones. We still got a little bit more of that work to do. But in the core of the play, we feel like we've done a good enough job to identify which zones have the best reservoir quality.
And then the next question is how to most optimally develop each one of those zones. Some of those may take a lower well count per section than others because of the phenomenon that Dave described. We ultimately are seeking to get the most return out of every one of these sections, and ultimately determining the precise number of wells per layer that we want to invest in.
Charles, just to add a little bit of a high-level thought process to you. We've been involved in 5,000 Barnett wells. We've been involved in probably 600 or 700 Eagle Ford wells. We've talked to you about the continued optimization in the Woodford after 850 wells. So this is our business. And we try to core up and get a blocked acreage position and try to get as much data and science as we can so we can, as Wade said, optimize on value. And so this is a great storyline that you see an advantage for Devon, is just these large contiguous blocks of acreage we have that are in the heart of these plays.
Dave, Wade and Tony, that's helpful color from all of you. And I agree that a lot of people's instincts goes the wrong way. You'd rather drill one well and get the EUR from the whole section. But that seems to get lost some time.
Last thing, or the one quick follow-up. I don't mean to belabor this point, but the 50 wells outside operated that got delayed, just curious if there's maybe a little more color you can add. Is that just one operator? Because it really seems like a remarkable contrast to your operations in the STACK, and I guess what I guess I'm trying to confirm or disconfirm is the idea that this might be something that's emerging out of a traffic jam in the play or something like that.
You know Charles, I would not read this as a systemic issue for the play. This happened to be on five or six large projects in the play from some of the more competent operators in the play and it was varied. It just wasn't one operator. And what you see the different operators doing is, Wade was really describing, is collecting a lot of data so some of these projects probably got slightly deferred because of data acquisition.
Some of these projects, the operators work really well here together and do our best not to bash offsetting wells. So when we have completion operations and one of our sections offset, operators will understand that and we'll alter their operations. So there's a little bit of this that we're all working together to try to maximize value. So I wouldn't read this as a systemic issue. I think actually is a pretty positive issue. Just happened in this particular 50-well program is just right at the quarter borderline. If it happened a little bit earlier in the quarter, we wouldn't even be talking about it.
That's helpful color, Tony, thank you.
Our next question comes from the line of David Heikkinen from Heikkinen Energy Advisors. Your line is open.
Good morning guys, and thanks for taking my question. Just looking at and talking about the $3 a barrel cash margin expansion. Wanted to check something that your guidance doesn't include things like the Barnett asset sale, and that could be, asset sales could be an additional cash margin expansion beyond what you already detailed.
Absolutely.
Yeah, we have not modeled in any divestitures into the forecast that we laid out.
Perfect. And you did say you could buy back up to 40% of your market cap?
No. I think in Dave's commentary, what we were suggesting was the cumulative cash flow that we could develop over that three-year period, married with proceeds from the divestitures would equate to essentially 40% of our market cap.
Okay, cool. Thanks guys.
I'll now turn the conference back over to our presenters.
All right. We're now at the top of the hour. We appreciate everyone's interest in Devon today, and I think we've got to most people's questions, but do not hesitate to reach out to us at any time today, myself or Chris Carr. Once again, appreciate your time and we'll talk to you soon.
This concludes today's conference call. You may now disconnect.