德文能源 (DVN) 2016 Q4 法說會逐字稿

Welcome to the Devon Energy fourth-quarter and full-year 2016 earnings conference call.

(Operator Instructions)

This call is being recorded. I would now like to turn the call over to Mr. Scott Coody, Vice President, Investor Relations. Sir, you may begin.

Thank you, and good morning. I hope everyone has had the chance to review our fourth-quarter and full-year 2016 financial and operational disclosures that were released last night. This data package includes our earnings release, forward-looking guidance, and our detailed operations report. Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Tom Mitchell, Chief Financial Officer; and a few other members of our senior management team.

I would like to remind you that comments and answers to our questions on this call today will contain plans, forecasts, expectations, and estimates that are forward-looking statements under US 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'll turn the call over to Dave.

Thank you Scott, and welcome, everyone. For Devon, 2016 was a transformational year.

We successfully reshaped our portfolio around top two franchise assets, the STACK and Delaware Basin, providing us a sustainable multi-decade growth platform. With these world-class assets, we delivered outstanding operational performance throughout the year. Our drilling programs generated the best well productivity results in Devon's 45-year history, and we maximized the value of every barrel produced with cost reduction efforts that reached $1.3 billion of annual savings.

We also took important steps during the year to strengthen our investment-grade financial position, with the timely completion of our $3.2 billion asset divestiture program. Overall, while 2016 will certainly be remembered for extreme volatility in the energy markets, our unwavering focus on the controllable aspects of our business yielded extremely strong results, and we laid the groundwork for Devon to deliver differentiated growth in margins and cash flow expansion, as commodity prices recover.

As we look to 2017, the next step in our strategic plan is to accelerate investment across our US resource plays, while maintaining our low-cost structure to maximize profitability. With an improving cash flow stream, we are planning to steadily ramp up drilling activity throughout the year, to as many as 20 operated drilling rigs by the end of 2017, roughly doubling our rig count from year-end 2016.

This ramp up in activity would represent an upstream investment of $2.0 billion to $2.3 billion for the full year 2017. The majority of this capital will be concentrated on low risk drilling activity in the STACK and Delaware Basin, and is expected to jumpstart Company-wide production growth, driving light oil production in the US approximately 15% higher for the full year 2017, compared to the fourth quarter of 2016.

Additionally, we expect to deliver this attractive growth profile with substantially lower operating costs. In fact, lease operating expenses within our US resource plays in 2017 are expected to be 30% lower than peak rates a few years ago, further bolstering the profitability of our top-tier asset portfolio.

Looking beyond the attractive growth profile Devon is going to deliver in 2017, we are even more excited about our outlook for 2018. Given the nature of pad drilling, the majority of the rig activity deployed in 2017 will provide an even greater impact to production in 2018.

Due to these timing considerations, there is significant operational momentum across our US resource plays heading into 2018, which we project will advance light oil production by approximately 20% on a year-over-year basis. This rapid growth in our highest margin product coupled, or combined with our low cost structure, positions Devon to deliver peer-leading cash flow expansion at today's strip prices.

Hopefully you can sense my enthusiasm for the significant value we expect to generate with our capital programs in 2017 and 2018. Looking beyond 2018, Devon unquestionably has the quality and depth of resource within our asset portfolio to deliver high returning and sustainable growth for many years to come. Between STACK and Delaware Basin alone, which are two of the very best positioned plays on the North American cost curve, we have exposure to more than 1 million net acres of stacked pay potential.

Across these world-class acreage positions, we have identified in excess of 30,000 potential drilling locations, of which approximately one-third have already been derisked through successful appraisal work. To further advance our understanding of the ultimate inventory and resource potential within Devon, we have several catalyst risk projects underway in 2017.

In the STACK, we are participating in several Meramec infill pilots, can further expand our risk inventory beyond the 40% increase we announced today. These pilots will also help refine our initial multi-zone development in 2017. This milestone development, called a Showboat project, is evaluating around 15 wells in a single drilling unit across three landing zones. Ultimately, we believe we could have spacing as high as 20 to 30 wells in a single drilling unit, when codeveloping the Meramec and Woodford together.

Moving to the Woodford, I would encourage everyone not to lose sight of this under appreciated play within the STACK. With the massive Hobson and Jacobs Row developments, we expect a step change in efficiency through improved completion and longer laterals, that could deliver returns rivaling that of the Meramec formation.

In fact, early flowback results from our operating position of the Hobson Row look outstanding, with initial well results tracking at or above our EUR type curve of 1.6 million BOE per well. Additionally, gross peak production from the Hobson Row are well on their way to exceeding 40,000 BOE per day in the second quarter of this year.

2017 will also be an important year for our Leonard and Wolfcamp programs in the Delaware Basin, with nearly 60% of our drilling programs in the area devoted toward characterizing these emerging oil plays. We expect the activity to have a material impact to Devon's Company-wide resource potential, and we are eager to progress our understanding of the 12,000-plus potential locations we have identified between these two plays.

Looking beyond this Delaware and STACK, we are nearing an initial flowback of our diamond spacing in the Eagle Ford, which could expand our high return inventory in the play. In the Rockies, rig activity underway is derisking the Powder River basin oil fairway, and the technical teams in the Barnett are experimenting with game-changing horizontal refrac technology.

As you can see, there are many significant projects ongoing, that will help us further characterize the full resource potential we possess across our resource plays. With continued appraisal success, these catalyst-rich drilling efforts in 2017 will further supplement our great collection of assets that are well-balanced between scalable growth plays, and top-tier cash flow generating properties. This advantage asset base provides tremendous optionality going forward.

And lastly, I want to be very clear on this. While having a premier portfolio is essential to winning in the E&P space, developing these assets through superior execution is equally important. Over the past few years, we have done a tremendous amount of work here at Devon to reshape our corporate culture, and have made a commitment to invest in leading edge technology to establish a competitive edge.

Through this pursuit of excellence, we have substantially reduced drilling times, we have maximized value per well with industry-leading completion designs, and we have optimized our base production with best-in-class field operations. Notably, these efforts have not only lowered costs across the board, but they have dramatically increased Devon's well productivity by greater than 300% since 2012.

This quality work firmly places us among the very best operators in North America. However, we are not satisfied with our recent accomplishments, and the teams here at Devon are passionately pursuing to improve all aspects of our business in 2017. With the drill bit, I absolutely expect capital efficiency and well productivity will continue to ratchet higher, as we shift the majority of our drilling activity toward extended reach laterals in the STACK and Delaware Basin.

Additionally, we are aggressively taking steps to offset industry inflation by decoupling historically bundled services, and we are utilizing a much more diversified vendor universe to achieve the best value for our LOE and capital dollars. We are also adding long-term service contracts, where prudent, to better capture terms at the bottom of the cycle.

Another area of our business that has the potential to meaningfully improve our operating performance is the application of innovative technologies in the realm of big data, where we view ourselves as leaders in the E&P space. We are at the forefront of these emerging technology trends will help us continue to deliver improved results through predictive analytics, and the deployment of artificial intelligence in our field operations.

We are just scratching the surface with regards to the potential of our advanced analytics initiatives, which we believe have the potential to unlock hundreds of millions of dollars of value annually. We expect the application of these technologies to not only contribute to better well productivity, but also to help us further optimize our operating costs and keep overhead expense lower through more efficient data systems and workflow across our organization.

So in summary, the future is very bright for Devon. We have the right assets, the right technical staff, the right culture, and our business is backstopped by an investment-grade financial position. As we execute on our strategic plan, Devon shares our position to deliver peer-leading returns through our rapid shift to higher-margin production, substantial cash flow growth, and a re-rating of our trading multiples, better reflects our premium assets and operatorship. With that, I will turn the call back to Scott.

Thanks, Dave. We will now open the call to Q&A.

(Caller Instructions).

Evan Calio, Morgan Stanley.

You have significant locations in the Meramec, and you have a large location upside in the Delaware, where you are ramping up most this year. The question is, how do you think about the portfolio impact if your location count continues to grow, and do you have enough confidence in the current direction to trigger a round of asset sales in 2017?

We obviously are working our way through the appraisal of a number of different zones, as you highlight, both in the STACK play and the Delaware Basin. And the results so far have been very, very encouraging that we've seen, with not only the number of zones that are working in both of these plays, as well as the potential [for] downspacing in both of these plays.

So we think we have -- we are positioned in a couple of the best basins in onshore North America, and we have some of the best position in those best basins. So we feel really good about that. We do want to further our understanding before we make any strategic decisions, such as that. We are also working some of these other areas that may be consideration, and we are improving the results in those areas at the same time.

We're going to have, for instance in the Barnett, we're going to have a refrac program that is at substantially lower costs than we've done previously, that could really be a game-changer in terms of the returns on that program. Were also going to drill some new wells with modern drilling and completion technology, that hasn't been done for several years.

So we want to see all of this work come together, as far as finalizing or getting more data, as far as how big our inventory really is in these top-tier resource plays. And doing some work in some of these other plays to really understand the full potential of these plays, before making any sort of strategic decision.

Now I will say, if you go back over the past few years, we haven't been hit -- if you look at it as a Company, we haven't been hesitant to make the right decision at the right time, as far as optimizing our portfolio. We think it is really important that if we ever do make a decision this way, that we have the best information available when we do that.

Maybe a follow up on the delineation side. You have two rigs in Woodward and Dewey counties, outside the core of the play. Can you discuss what your testing there, what zones, and potentially what that could derisk for you?

I'm going to let Tony Vaughn, our Chief Operating Officer, answer that question for you.

Evan, I think we've commented before, but we have about 80,000 acres outside the core of our footprint in STACK. You probably have read some of the competitors are testing for the Osage and the Meramec, and we are continuing to work some prospectivity in those areas, trying to gain an understanding of really where the play moves.

Any idea on timing there, in terms of when we might have some results there?

We are engaged in some operations right now, both on the drilling and the completion side of it. So it would probably be the second half of 2017 before we have a better understanding about our thoughts there.

Great. Good results.

Doug Leggate, Bank of America Merrill Lynch

Dave, can you just remind us, what is the spacing assumption, wells per PSU, that you are assuming in the 1,600 locations in the Meramec? And what's behind my question is, 20 to 30 seems like quite a big step up, and I am wondering if you could help frame for us if that's across the entire play, or just the over-pressured area, or just how you're thinking about how that 1,600 locations has -- what the upside risk is for that?

Thank you for the question. In summary, we see tremendous potential for that continuing to increase through time. If you -- right now we average six wells per section across the entire position in that number.

As we -- it's a much higher number, probably around 13 wells per section, and obviously to average six is much lower outside the core, and we have essentially put none of the locations we have counted within the liquids rich part of the window where we are participating along with some of our peer companies in the drilling activity there, as well. So we see that there is tremendous upside to this, as we further appraise the entire area, so we are just getting started.

I appreciate that. I'm going to ask you about the portfolio, as well, if I may, because let's assume you have a tripling or quadrupling of the inventory in the STACK. I think Tony has said in the past that your Delaware slope acreage probably wouldn't compete for capital, your Barnett could auction their assets, probably struggles to compete for capital.

So what do you need to see to -- or whether or not you can actually confirm that as the actual case that those are maybe non-core assets, and what you need to see to maybe start thinking about moving those forward as another asset in this [position] program? And I will leave that there. Thanks.

Again we are looking to further quantify just how rich our inventory is. We know it is rich, but we would like to get more information on the spacing in the various intervals that we are testing, both in the STACK play and the Delaware Basin. Also, just how many of these different intervals are working.

So we would like to further detail that, to know for sure. It has certainly been true historically that the slope in the Delaware Basin does not appear to compete as well, although I will note there has been some pretty big purchases there recently, by some other companies, but I think historically it has not competed as well.

And the Barnett, although you can get returns well above the cost of capital, have not competed in our portfolio. But again, we are currently testing some innovations in the refrac technology side, to significantly lower that cost, and we are trying some new wells out there with modern drilling and completion. So we would like to understand that potential before -- both in terms of just how deep our inventory is, and also what is the real upside better from these other plays before we make a final decision.

We understand the question very well. It's not lost on us. We understand, and like I say, we have not hesitated historically when the time is right to make these strategic decisions. But that's what were working through, before we make a decision.

Very clear. Thanks very much.

Ryan Todd, Deutsche Bank.

Maybe a question on the -- first question on the type curve in the STACK. At this point, you have only provided one that has been for a 5,000 foot well. Any color on how we should think about the reserves from the 10,000 foot longer laterals that you are drilling now? Should we -- and 30-day rates, should we extrapolate from, in terms of reserves for lateral foot from the 5,000 foot wells? And what is the average well cost at this point, are you expecting from the 10,000 foot lateral?

Ron, this is Scott, and last quarter we did roll out our first extended reach type curve for what we consider the over pressure [oil] window within the STACK. And the EURs on that are approaching two million barrels per well on an equivalent basis, and depending upon the streams of casing, whether it's two or three, the cost of the -- D&C cost can range from $7.5 million to $9 million.

And from an IP-rate perspective, these are pretty prolific wells as well. It's well north of 2,000 barrels equivalent per day on a 30-day rate. So that's our initial type curve, and I think Tony can talk about maybe what we're seeing at the earlier results on that, and how it's trending.

Thanks Scott, you did a good job of characterizing the type curve there for the 10,000 foot wells, and the producing history that we have had on those is really exhibiting better performance over time than even the 5,000 foot laterals. There is additional upside in our type curve. I believe we need more information to look at that, but we're quite pleased with the 10,000 foot wells over the 5,000 foot wells, and we will certainly try to maximize every opportunity we can, to drill those 10,000 footers.

And on the longer laterals is there room, I appreciated the incremental shift toward 65% of the inventory of the 1,700 wells in STACK being the longer lateral. Is there room for that to shift higher at this point, or how should we expect your ability to drill longer laterals to trend over the next little while?

Ryan, I think that is what our technical teams do every day. I think they are looking for opportunities to core up either through small-scale land acquisitions or trades. Also looking to work with other operators there.

We have a great relationship with the other primary operators in STACK, trying to maximize the efficiency of each of our operations, and so that's working quite well. And I think the positions are largely made between the large operators. There is potential for that to continually inch its way up.

Thanks and maybe if I can ask one on your view on costs. What does your 2017 capital budget assume in terms of well costs relative to costs in 2016? And how much inflation do you assume, what are you seeing to date and any expectations on what you expect over the course of 2017 and maybe into 2018 in terms of the cost structure?

When we were out a few months ago talking about that, we said we expected high single-digit inflation across all aspects of the business. We have revised that upwards a little bit now. We're saying now in the 10% to 15% across all aspects of business.

If you look at -- and we have accounted for that in the capital guidance we have provided to you. We were originally talking about a capital program around $2 billion, a couple three months ago. Now with a $2 billion to $2.3 billion, we probably upped the midpoint about $150 million of that.

About $100 million of that is due to just moving up the timing of some rig activity, particularly in the Delaware Basin, and about the other $50 million or so is due to additional cost inflation now. At the same time, we think we can largely mitigate about 75% of this cost inflation, that we anticipate to see this year.

You're seeing examples of us across our portfolio, where we are lowering the drill times associated with these wells. We have our 24/7/365 drilling control room is really helping out a great deal with the efficiency, and nearly 100% in zone on these wells. Yes, it does appear the inflation has picked up somewhat from a few months ago, but we think we can largely offset that.

Thanks, very helpful.

Arun Jayaram, JPMorgan.

My first question involves your CapEx program from this year, of $2.5 billion at the midpoint, which is below your upstream cash flow potential that you highlight on page 6 of the Ops Report of $2.7 billion. I just wanted to get your thoughts on spending a little bit low below cash flow, and the strategy behind that?

And maybe some thoughts around 2018. You highlighted $3.5 billion of upstream cash flow potential. What does that 20%-type growth number for US light oil, what does that embed in terms of CapEx next year?

This is Dave. First off, from a corporate standpoint, given the strength of our balance sheet and our financial strength, we are comfortable right now spending approximately at cash flow, in any given year. We want to stay a strong investment-grade credit company, and we believe with our net debt position at this point, that the spending within cash flow is approximately where we should be.

Now we recognize, depending on who's price deck you use there, that there may be the potential to -- that we may have a little bit of free cash flow this year. I think frankly we would probably have to subtract off the dividend off the numbers in our book there, and you will probably see we are really at cash flow neutral. But if there is the potential where we have a little bit stronger cash flow than we anticipate, we certainly have the program, and we are very confident we can deliver on good returns on that program, for a little bit higher capital spend.

So that, we are not doing, we're not announcing we're doing that obviously right now, but that potential is there. We have some of the highest best positions in onshore North America, and we have focused on delivering outstanding returns on that, and we could ratchet up to some degree our capital spending and be confident that we could maintain those returns. As far as the 2017, or excuse me, the 2018 capital program, basically what we're -- we're not going to give you a specific numbers there, but do feel comfortable stating that we're roughly planning to once again spend within cash flow and deliver on our growth targets that we have outlined there.

That is helpful.

Another thing to keep in mind on that, the 2018 capital spend really has a bigger impact on 2019 production than it does 2018 production. Really the bulk of the 2018 production, given the time delay between when you spend the money and you have first production, is largely determined by the 2017 capital spend.

That is great. My follow-up is, I wanted to go back to a comment that you all put in the press release just talking about Canada, and the tremendous upside exists within your Canadian resource potential. You highlighted 1.4 billion of resource potential there.

I wanted to see -- obviously a lot around Canada recently, with the market concern around border taxes. How are you thinking about an investment decision at Pike, and given the resource potential that you have in the Delaware as well as the STACK, and elsewhere in the lower 48 portfolio, I was wondering how you guys are thinking about Pike. Obviously that's with BP.

That is a decision that we will visit the second half of 2017. We are very confident that Pike is going to be like Jackfish, in the sense that it's going to be a top-10%-type project in the SAGD.

Geologically, it looks just as good if not better than the Jackfish project, and obviously, we've shown the ability to execute on the construction side at Jackfish as well as anybody, and we have the graphs in our operations reports that just show the efficiency with which we're able to manage that production to, in terms of steam-oil ratios, and also goes back as well to just the quality of the reservoir. So we like the project a great deal.

Now obviously, the question is not what prices are going to be in 2017, but what we anticipate prices will be when first production happens, which would probably be around 2021 or so. So, we are hoping to get at some greater clarity on that question. There are other variables that obviously factor into it beyond price, and also just the capital costs.

We do not necessarily see the proposed border adjustment tax as a negative to Canadian prices. We do see where it could be positive overall for our portfolio, in that the bulk of our oil is in the US, and we think it would cause WTI prices to go up. It may cause the differentials to increase a little bit, but not necessarily lower the price is coming out of Canada, because that heavy oil is needed by the refineries here in the US, that's what they are tooled to handle.

And with the decrease in Mayan crude particularly too, we think the draw on Canadian crude will still be there largely. So we don't see that as a negative on our Canadian operations at all. You might even benefit from a positive FX as well, impact to it.

We will visit that question the second half of the year. We like the project a lot, but obviously does take a -- it's a little bit lower return than our well oriented programs here in the US, but the way I describe it is more the bond in our portfolio. It is a lower risk, we know how to do it, and generate good returns with it. So we will make a call with our partner, BP, later on in the year on this.

Okay, thanks a lot.

Charles Meade, Johnson Rice.

I would like to ask a question about the Delaware Basin, and we spent a lot of time talking about what you are doing up there in Lea and Eddy counties, but you got this other center of gravity down there, along the Reeves Ward line along the Pecos River. And I'm sure it hasn't escaped your attention there has been a lot of A&D activity down there, and I'm wondering if you could talk a little bit about what the nature of your position down there is, and how testing your development on that position slots into your drilling plans for this year and beyond?

Tony is dying to tell you about it Charles, that is what we call our [Maveta] area down there, so I'll let Tony talk about it a while.

Charles, you are right, there was a lot of A&D work down there, with a lot of extremely high price-per-acre transactions have occurred. We watch that. We've also spent a good bit of subsurface evaluation time on our position, looking at the results from our competitors there. So we think we are in the right country for good return work.

We've got activity planned for the latter part of 2017. And again as we manage our investment in the Delaware Basin, we tried to highlight the primary areas that we'll be working there on in our operating reports. So while we'll be drilling about 100 wells, the majority of those will be on those four areas in southeast New Mexico, but we are working on some appraisal type work in the Maveta area, and certainly watching a lot of activity around us, that are helping us derisk that. So it is a good play as you mentioned, and something that we will incorporate in our development plans.

That is great detail Tony, thank you. Dave, for my follow-up, I'd like to pick up on something you said in your prepared remarks. You talked about Devon being the leader in big data. To the extent that you're comfortable, can you tell us where in your operations you're using big data, that's yielding good results, and what makes you a leader? And what things should we look for going forward, from your efforts on this front?

Tony would like to do this one, also.

Charles, thanks for the question. It's probably about three years ago we made a large commitment internally to be more fact-based and data-driven in our day-to-day work. We have spent quite a bit of time in that, we brought in and incorporated some people from outside the industry to help us get through that work, so collectively, it's been a big effort.

So as we've taken the information or that data collection and we talked about all the different types of subsurface data that we're acquiring, also that has been included in our surface work. We stood up some decision support centers, it was the first thing that we did, just monitoring all of our producing assets from around the Company. Minimizing downtime, trying to maximize the production rate from that.

But this really has greatly expanded from that. So while we're acquiring a lot of this information, we have found ways now to get that information on the hands of our technical teams, more real-time than we have in the past. And so, the data reporting has elevated us to a new level here, internally.

We're incorporating that into all phases of our business. And some different areas that were working on it, as you mentioned, was on the artificial lift reliability. So now we're watching daily information, more than daily information on all of our submersible pumps and gas lift injection rates across the Company, and are able to better predict the reliability of those pumps.

We're able to better schedule maintenance on those pumps so we have limited downtime. We are also incorporating this data into our well flowback-type work. We are able to monitor our rates and pressures, and really get the wells off of the well flowback environment quicker. That happens to save about $50,000 per well.

We have incorporated this data into our cold tubing drill outs in the completion phase of our work, and so what were seeing this pressure and rate information on that portion of our business, it's also accelerating our cold tubing drill outs to the point of saving about $100,000 per well. And then we're also incorporating this into our drilling business now, so we're using it to help geo-steer wells and position our drill bit, and using that data really to do it in a quicker, more efficient manner than we can with just standing up additional personnel to watch that on a day-by-day basis.

Charles, we have talked to you a little bit about the well-con center in the past, and at one time we probably had 30 to 40 people working in that well-con, and now it is under 10 people still managing the same type of work, perhaps looking at more information than we have in the past and making real-time decisions, that's really just causing things like our Delaware Basin wells, we're getting from spud to TD in about 10 days now. Probably about a year ago, at the time that we were more active there, that was about 17 or 18 days. This is just a way that has tuned up our business in small increments across the Company.

Thanks for the detail, Tony.

Paul Sankey, Wolfe Research.

In terms of all your various choices, could you talk a little bit at a higher level about the marginal decision between natural gas and oil? It just seems that the prices are so far apart of the two commodities, that I would like to know more about your thinking in terms of what returns you need, what risk you put on either activity? Thank you.

Paul I'm not sure exactly where you're going with that, but what I would say is that we obviously are driven by returns in all of our capital allocation decisions. Those returns were largely driven by what our anticipating prices are for both oil and natural gas.

Given right now the reality of strength of oil compared to natural gas, that does mean that the bulk of our capital program is going to those plays that have a higher proportion of oil versus our dry-gas-type opportunities. We still have some of those in the portfolio, and the Barnett would be the big one, and some areas even in a deeper part of [Cana], for instance, that we are not having a lot of activity going. So that will drive our capital allocation decisions.

Just our belief in what the relative strength of the commodities will be. And obviously that not only does it from our capital allocation, but we take that into account when we are making strategic decisions, as to where we think the portfolio should be positioned.

It is a fairly simple question, but it was really the Barnett that I was thinking of, and how come there would be any investment there? How good do the returns have to be, given the price discrepancy between the two commodities? Is it a maintenance activity with just a bit of CapEx going there, or is there genuine -- I mean you said you [could see] returns, so I wondered quite how you could get there? It must be --

We are spending money there not to maintain production. We are 100% dedicated to putting our capital where we believe the highest returns are.

In the case of the Barnett, and Tony can detail it, we are spending a little bit of capital there this year, not a large amount, because we are investigating the how well a new refrac design, which may be around $700,000 versus previously was around $1 million to $1.2 million cost to refrac those wells, how well that is going to work. And if that is successful, it could have returns that are very competitive within our portfolio.

There's also the potential that with a modern drilling and completion design, that you could also have returns that are competitive within our portfolio. Remember, we haven't had an active drilling program there for several years, and there has been tremendous advancements on both the drilling and completion side since then. So we are not putting a lot of capital into that, but the only reason we are is because we believe that could lead to a program that could be competitive within our portfolio, or any body else's portfolio, if we choose to make a strategic decision around that.

I think that is what I was driving at, it's interesting that there is any activity there, and it is a bit bearish for natural gas that there is.

Just the second question would be on the Delaware. Can you talk more about the nature of your activity there? Is it primarily an appraisal-type activity, or is it in the exploration realm?

Paul, it is really not in the exploration nor appraisal. We are doing a little bit of appraisal work across our position, but for the most part, we are moving into developments in 2017. So you will see on the Operating Report on the Delaware Section there, the four core areas we are working.

We have already got three rigs stood up right now, working the Thistle area. That will be predominately a Leonard shale development. We have announced in December that we had a couple of good wells stacked on top of each other in the B and the C, and we have seen industry work in the A, so we think we have a very hearty development plan for the Thistle area.

Cotton Draw has been an area that we've had the majority of our historic second Bone Spring work, and again, we'll have rigs working there through the year developing additional Bone Springs, Delaware, Leonard, and some Wolfcamp-type activity. And then the Rattlesnake in the southeastern portion of our position there, we'll actually be standing up work there in the second half of the year, prosecuting Leonard shale, but primarily the Wolfcamp.

And we've seen some really outstanding results from some operators adjacent to our footprint there in Rattlesnake, that have had some stellar wells. So we're really trying to move our Delaware and STACK into development mode, as quick as we can. We continue to do some amount of appraisal work year-in, year-out, just to prepare for the next year's developments.

Paul, real quick this is Scott, just to add on a little bit to the end of that, just to provide a percentage. About three-quarters of our activity will be development drilling, and that is one of the reasons why we are so confident with our production outlook with the Delaware Basin. If you look at our Operations Report, you are going to see greater than 20% growth from Q4 to Q4 on a 2017 to 2016 basis.

Obviously, we expect to stabilize production in the first quarter, and even more important I think is just how excited we are about the momentum that carries into 2018. So this is absolutely going to be a strong growth asset with some of the best returns in North America.

Great, thank you for your help.

Matt Portillo, TPH.

Just a quick question on the Jacobs Row. Wanted to see if we could get a little bit of color around how you're thinking about the hydrocarbon mix? Obviously Hobson has gotten into an oilier section from a development perspective, and Jacobs offsets that. And I wanted to see if we can get any high-level color in regards to timing of rig allocation there, and when we may start to see first production from that very large development.

Matt, this is Tony again. Let me start a little bit with the work that we're doing on the Hobson Row, and then I will move into that Jacobs Row there. We are about halfway through that five-section position that we have in the Hobson Row. In Dave's opening comments, he commented the results we're having there are outstanding, and we are on track with the development.

What is unique about the Hobson Row, the reason why I wanted to bring this up is if you start on the west side of that five-section footprint there, you've got fairly leaner fluid type that we are producing, but as you move through -- quickly move into the heart of those five sections, we have a higher oil content there. And so we commented that we're seeing 25%-plus oil content. As you move to the far eastern side of that footprint, we expect it to be even higher there.

While we don't have everything completely delineated on the Jacobs Row, I think it will be in that higher oily mix, at least 25% going forward. When we think about the timing of bringing in rigs for the Jacobs Row, we are in the midst of our plans right now. We think that will be the second half of 2017.

You can see there that it is a larger development than the Hobson Row. We will incorporate the number of rigs and frac crews to timely get through that, so we are maximizing the present value of that operation.

Great, and then just a follow-up to Canada. We've continued to see improvements on the operating side in regards to Jackfish. I was curious if there is any other debottlenecking opportunities for expansion on the production side?

And then a follow-on to the comments on Pike. If we think about 2018 and 2019, if you were to move forward with potentially sanctioning, what call on capital could we expect ballpark around the project?

Matt, I tell you, I got to compliment our operating team in Canada right now. They are extremely efficient, they have debottlenecked J1, 2, 3, to the point where we are seeing daily production rates 10,000, 12,000 barrels per day above nameplate capacity. That is a function of debottlenecking on the surface, but it is also a function of their clear understanding of how to optimize steam injection into that high-quality rock.

We are rocking along at a pretty high rate, in our minds. We've got some fairly new pads that have been brought on in the latter part of 2016, that has really helped move that production rate up. We are starting to work on another pad that will have some rate benefit in early 2018. But they are doing an excellent job on the Jackfish, operating those plants there.

As you think about Pike going forward, it is really a fairly minor capital draw on the Company. As you think about that, we are 50/50 with BP. We staggered the capital profile out, just to give you order of magnitude, if we were to sanction later this year in 2018, that draw would be about $50 million net, and would go to about $150 million for the next couple of years.

Dave mentioned we will get to first steam about 2021. So in the grand scheme of things, it is really about 5% of the Company capital as you look out in time. It is really not that significant.

Thank you very much.

Scott Hanold, RBC Capital Markets.

Dave, I hope I won't wear you down with another portfolio question, but when you step back and look, obviously you talk about the potential of 20,000-plus wells in the Delaware, you're drilling about 100 this year. So certainly it seems like at the current pace, the value potential is not being maximized.

But as you step back, and understand how industry has been fairly aggressive about buying acreage in the Delaware Basin, at what looks like pretty good prices. And it seems like your desire to maybe want to maximize the value by finding out first what you have, and what new technology will show you on those assets, how do you balance the two?

And when you look at it, is it more about understanding the potential before you look to monetize it, or is there a consideration, we may just keep this, and decide to outspend cash flow to monetize it ourselves. Can you just give us a sense of the high-level perspective?

I am not going to announce anything today, so I'm not sure I can really answer that question fully. But I would say we're working both sides to really understand what the potential is in a more complete manner in our core plays, both in the STACK and the Delaware Basin, as well as trying to make sure we understand the true value of other assets that may be considered for monetization.

You never have complete knowledge, we understand that. There is not a set point in time where you fully understand, and you make this call. But it's our judgment right now that we would like to learn more, rather than make that decision today. But again, it is not lost on us that there is a -- at some point, that call will have to be made one way or the other.

We certainly, as I keep saying, have not shown any reluctance to do that historically, when we think the time is right to do that. We fully understand the values that are being paid in the Delaware Basin. We understand all of the variables.

I don't need to lay them all out on the table here, I don't think. But we just feel it would be helpful to have some increased knowledge at this point of the continued appraisal in both the STACK and Delaware Basin, before we make that final call.

Okay, I appreciate that, and Dave just to clarify, so is the likelihood more or less that if the timing is right and the price is right, you would monetize versus look to outspend to bring forth the value?

I would say that is probably on balance, probably the more likely scenario, that we would go that direction. Yes, I would agree with that.

Okay, fair enough, thanks. As a follow-up, could you clarify too, on your identified inventory in the Permian, how much of that is roughly in the slope versus in the basin? And down in the Nevada area, if you could just clarify what the size of that position is?

Scott, this is Scott. With regards to the inventory, probably two-thirds is going to be in the basin, which we consider is superior returns to the slope. And as far as the acreage, you are probably looking at 55% of our acreage from a surface perspective is going to be located in the basin as well, so we're certainly levered to the basin.

Thanks.

Biju Perincheril, Susquehanna.

Dave, you talked about two Bone Spring wells in the Operations Report, and I was wondering, are those wells targeting similar landing zones at what you have been targeting there, or would this be something different?

Biju, your question, you broke up a little bit, your question is what landing zones for the Bone Springs at those particular wells? And I will hand it over to Tony, but essentially those are in two very different areas, than where we have drilled historically. It was the Thistle area obviously was one of those areas where we drilled at Bone Spring, and I believe it is the Todd area is where we drilled our other Bone Spring. Tony, feel free to jump in, but obviously I believe it is a second Bone Spring is what the Todd area would be targeting, and when you think about the Thistle, it may be more shallow member of the Bone Spring.

The Thistle is going to be really dominated by the Leonard development there, but we do have about half a dozen wells in the second Bone that will be drilled. But in the Todd area, that will be largely dominated by the second Bone Springs, with have a little bit of Leonard and Wolfcamp activity there. We also know that we have the upper Bone Springs, second Bone Springs member available to us in [Cotton drawl] and the Todd area, that we will be incorporating into our developments.

But Biju, just to provide a more global thought, when you think about our overarching inventory in that play for the Bone Spring we have inventory across the first, second and third members of the Bone Spring, and it just depends on where you are at within the basin, it can be very localized. But certainly we are more heavily levered toward that second Bone Spring opportunity, which we believe delivers the best returns.

And my second question is in the Meramec, when I look at the Alma pilot versus the Pump House, the middle well in Pump House is performing right in line with the outer wells. Maybe you see a little lower performance on the (inaudible) well from the Alma, which is what you would expect normally. Just wondering, that difference in the two, the two pilots, how do you explain that? Is that geology? Is there anything that you did in terms of landing zones or completions that would explain the better performance out of the Pump House pilot?

Biju, we were actually happy with the results out of the Pump House pilot. I think that was helpful for us to understand the lateral spacing that we had there, but the Alma also was helpful in understanding what it was. We just we did not see the communication between the five-well pilot that we pumped in the Alma.

We have been pleased with the work we are seeing in both of those. I would say the repeatability across our footprint there, primarily in the core of the play, has been extremely high. We are continuing to see better performance in the optimization.

In fact, if you look at some of our year-end reserve work, we were able to add a substantial amount of general revisions, due to increased performance from a lot of these new STACK plays in comparison to the original-type curves. So we have been pleased with all of the pilots, they have been very informative to us. We have not seen a real train wreck out there, and we think the play at least in the area that the industry has been working, is very repeatable.

Biju, one thing to add with that, it is really -- we have been asked a lot about the upside with the STACK play, and one example that is lost on a lot of people but not you would be that with the offsetting well actually not showing degradation, and a lot of that comes down to landing zone. We're still optimizing landing zones in this early stage play, so as we continue to better understand landing zones and we extend these laterals out further, that's where we expect well productivity and capital efficiency to continue to ratchet up in this play.

That is helpful, thank you.

David Heikkinen, Heikkinen Energy.

As I was looking at the Hobson chart and your forecasts, and your comments about where you were as far as timing into that, I had a couple of questions. As you think about that forecast, first did that include the 40% of the wells that are above the curve, or is this year's forecast before you started bringing the wells online?

The forecast is based on our type curve, David.

So you are above the type curve. So can you -- what would be great, as you get into second quarter and third quarter, is to overlay the actuals, because it looks like that would track above that forecast, just given your bullet number two in that section.

We will be happy to, David. I tell you when you look at the results we are seeing, it is extremely early. The results have been above-type curve, and the wells are cleaning up. But if you remember, we are about, we are probably about halfway through on a real-time basis on the completion of these wells, and so the flowback is pretty early.

Yes, that is cool. And then Dave maybe, I'm a little confused around some of the questions on the call of selling parts of your core assets in the Delaware, or the monetization, as you are in the early phase of appraisal. I would assume that you are still in the mode of delineating and trying to determine what your potential is, and that a sale of any of those assets would be not even a consideration yet. And so did I miss something in where investor expectations were, because it is confusing.

I believe the questions David, were not around the sale of any of our core assets. The core of the Delaware Basin or the core of the STACK or anything, more directed around some assets that we can still have some capital programs, that are probably well above the cost of capital, but they are not going compete in our portfolio, and not going to receive capital.

And so the question is, I believe people are asking is, at what point will you make that decision that is not going to be an area that you will allocate significant capital to, and might consider for rationalization. But certainly, there is no consideration on our point of selling any of the core assets in our portfolio. We're glad we have them, and we think we are some of the best, and we will execute on them incredibly well.

I guess it was just the high-value acreage maybe on the slope, and there's been transactions around it. So it is a more fringy versus on a big block, of course, so maybe that was my confusion. Thanks for clarifying.

I think that is probably the questionable area.

Okay, thanks.

I am showing we are at the top of the hour and there are still a lot of people left in the queue, so we apologize for everyone that we are not getting to, but please don't hesitate to reach out to the Investor Relations Team at any point, which consists of myself or Chris Carr, and have a good day, and we do appreciate your interest in Devon. Thank you.

Thank you, everyone. This will conclude today's conference call. You may now disconnect.