Howard Thill - Senior Vice President, Communications and Investor Relations John Richels - President and CEO David Hager - Chief Operating Officer Darryl Smette - Executive Vice President, Marketing, Facilities, Pipeline and Supply Chain Tony Vaughn - Executive Vice President, Exploration and Production.

Doug Leggate - Bank of America Merrill Lynch Scott Hanold - RBC Capital Markets Charles Meade - Johnson Rice & Company Arun Jayaram - Credit Suisse David Heikkinen - Heikkinen Energy Advisors Paul Sankey - Wolfe Research Brian Singer - Goldman Sachs John Herrlin - Société Générale Jeffrey Campbell - Tuohy Brother Investment Research Biju Perincheril - Susquehanna International Group Phillips Johnston - Capital One Securities.

Welcome to Devon Energy’s Third Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. This call is being recorded. At this time, I’d like to turn the call over to Mr. Howard Thill, Senior Vice President of Communications and Investor Relations. Sir, you may begin..

Thank you, Connor, and good morning. I too would like to welcome everyone to Devon’s third quarter analyst and investor call. I am Howard Thill, Senior Vice President of Corporate Communications and Investor Relations for Devon Energy.

Also on the call today are John Richels, President and Chief Executive Officer; Dave Hager, Chief Operating Officer; and Tom Mitchell, Executive Vice President and Chief Financial Officer. Additionally we have a number of other Devon executives in the room with us.

If you haven’t had a chance to listen to the management commentary, you can find that along with the associated slides and our new operations report at devonenergy.com. Additionally, starting with this quarter’s results, we have included our forward-looking guidance in the earnings release.

I hope you've had a chance to review those documents as today’s call will largely consist of questions and answers. Finally, I’d remind you that comments and answers to questions on this call may contain plans, forecasts, expectations and estimates which are forward-looking statements under U.S. securities law.

Our comments and answers are subject to a number of assumptions, risks and uncertainty that could cause our results to materially differ from these forward-looking statements. These statements are not guarantees of future performance.

Additionally, information on risk factors that could cause results to materially differ from the forward-looking statements made today is available in our 2013 Form 10-K and subsequent 10-Qs included under the caption Risk Factors. With that, I’ll turn the call over to our President and CEO, John Richels..

Well, thank you, Howard and good morning, everyone. As you all have seen, Devon delivered exceptional performance during the third quarter. We achieved record oil production which exceeded the high end of our guidance by 6,000 barrels a day.

With that strong execution, we increased our 2014 production outlook -- our growth outlook by about 300 basis points from 11% previously to 14%. And very importantly, that increase came with no change in our 2014 capital spending profile.

We also increased our profitability with pretax cash margins expanding by 20% year-over-year and exceeded Wall Street’s earnings expectations by $0.10. And lastly, we completed the final leg of our strategic repositioning with the closing of our U.S. non-core asset sales.

So overall, it was an excellent performance for Devon and we expect a strong operational momentum that we delivered to continue into 2015. While we’re closely watching developments in the commodity markets, we’re extremely well positioned to fund our 2015 capital program.

We’ve got one of the strongest balance sheets in the sector, we’re very well hedged and we have visible opportunities for continued drop downs to our midstream business. This places us in a position to continue to invest in our portfolio of high rate of return projects in many of the best U.S. resource plays.

So with that, as Howard said, today’s call was going to be a Q&A call basically. And I'd just like to actually congratulate Howard and his team for the change and I hope that you all found it helpful. But we've tried to put out the very best information that we could. So with that, I’ll turn it over to Howard for Q&A..

Thanks, John. And before we get started, I’d just like to remind everyone to please limit yourself to one question with an associated follow up so that we can get as many people on the call as possible. And you can re-queue for additional questions as time permits. And so, Connor, with that, we’re ready for the first question..

(Operator Instructions) Your first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Your line is open..

So, I wonder if I could take a couple. First of all, you’ve still not taken any steps to increase your inventory in the Delaware Basin. I realize you’ve taken type curves up so on, but just kind of curious as to what is it going to take for us to see the greater confidence level as you de-risk that play? And I’ve got a follow-up..

This is Dave Hager. We are doing downspacing pilots in the first half of 2015. When we see the results of those downspacing pilots in the second Bone Spring, we anticipate that our inventory will increase. If you obviously look at our presentation and our investor book, it shows that we’re currently just using four or five wells per section.

And so we think there is upside particularly in the second Bone Spring to this and we’ll test it with these downspacing pilots. I'll remind you also that in our 5,000 locations, we haven’t counted anything for the Wolfcamp.

We think that’s going to work and we think it's going to work well, but we think the economics are stronger in the second Bone Spring. So, we’re going to concentrate our evaluation there initially and then let the industry do some of the de-risking in the Wolfcamp and the Leonard Shale..

I guess, Dave, I should have been more specific. I think I really was just talking more to the Wolfcamp than the Bone Spring, because that's the area that's still TBA.

And after the numbers that we saw from you this morning, it would seem that they were starting to kind of suggest in a very similar area to yourselves that they have got a lot -- a much greater confidence.

I am just wondering what is it going to take for you guys to get to the same point?.

Well, we are drilling -- actually we drilled our first Wolfcamp Shale well in Loving County just on the Texas side. We’re currently flowing back that well as we speak, so we'll have results for that. And in next quarter's call we’ll be analyzing all of the industry data and be providing numbers. Again, we have the acreage.

It's not a question where do we have the acreage, it's just the matter of us analyzing the industry results and then providing you guidance around that based on the industry results. So, we’re very confident it's going to work and so our overall inventory is going to go up. It's just that we want to see a little more results.

And again, we think the economics are a little bit stronger in the second Bone Spring. We have more of the second Bone Spring than some of our industry peers just given where our acreage is actually located. But the second Bone Spring is a little bit shallower, it's a little less expensive to drill and it's a little more oily.

And so all of that cause the economics in the second Bone Spring to be a little better, but that’s not to say it's not a good strong opportunity in the Wolfcamp and we’re glad EOG is having success. It just makes our acreage look that much better..

My follow-up, if I may, Dave, is kind of related. And I guess before I get into this, I should say that the new disclosure and the conference call before and everything else is really terrific. So thank you for making our lives easier. But my question really is more about the increase in the type curve in the Bone Spring.

So, the IP rates obviously have been up significantly, but the type, the actual EUR did not appear to move. I think you put a plus on it as opposed to changing the numbers.

So I am just wondering if you could, if I am missing something there or if you could help us understand what your realized aspirations are as you look at that?.

We probably could have put a plus, plus, plus on that, to be honest with you, Doug, because we feel very good about that as we get additional data and we get more production data on these wells that the EURs will increase. We just want to see more production history before we say exactly what the new EURs will be.

But I can tell you so far what we’re seeing is these wells are coming on at significantly higher rates and they are essentially paralleling the old type curve. They are not falling off more rapidly. So there is -- we feel very confident that the EURs are going to increase.

We just want to get more data on these wells before we actually come out with what the increase will be..

Your next question comes from the line of Scott Hanold with RBC. Your line is open..

Maybe to stick with the Northern Delaware Basin for now, just a little bit more color on some of those downspacing pilots. Obviously four to five wells, you seem pretty confident and you're going to eight.

Can you just give us a little bit of color what you're looking for there? Is it just maximizing recovery and should we expect because those reservoirs drain pretty well, is it going to communicate a little bit or do you think that those eight wells could be fairly independent?.

Well, obviously that’s what we need to find out with these downspacing pilots. But what we’re looking for is do we have good economic opportunities with these downspacing pilots and so do they generate returns that are competitive within our portfolio that we would want to drill these downspace wells.

We think that particularly the most opportunity does set in the second Bone Spring for this downspacing opportunity and that’s what again, as I have highlighted already that those are the best economics in the Northern Delaware Basin anyway. So if we have down spacing opportunities, our belief is that they will compete very well within our portfolio.

But that’s what we’re really looking to see is just what kind of -- obviously there may be a little bit of degradation of performance, we don’t know.

But with these larger fracs that we have – again, the whole idea is to create more complex fracture networks immediately around the wellbore, but not to have them reach out as far so you that can create these downspacing opportunities where you can do the same thing on a downspacing basis and have very strong returns.

That’s the theory of where we’re going. We think it’s going to work. We just want to see the proof with the actual pilots..

Okay.

And is your acreage such that you could do a lot of this in pad development? Are you blocking up where this could be a pretty good thing where -- I don’t know what the right number is, but what do you envision wellbore...?.

Well, we’re doing a lot of the pad development already and we can continue to do a lot of this with pad development. Now, the specifics of how we would develop the downspace pads, I mean I have to defer. We may have to just build additional pads and take them into incremental facilities on the same acreage there. I think that’s our plan right now.

But frankly, we need to get a handle early on how much -- there is not only downspacing opportunities in the second Bone Spring, but if you go back to our investor presentation, we have slides there that we have showed that also on some of these areas we have Delaware sand potential, we have Leonard sand potential and we have Wolfcamp, not all of them on all of the same acreage.

But we have some areas where multiple formations are prospected. We actually have even additional zones within the second Bone Spring that we’re not sure that we’re fully exploiting at this point either, an upper sand in the second Bone Spring, we’re testing that as well.

So, there is not only downspacing opportunities, but there are stacked lateral opportunities in the Delaware Basin that again could significantly increase our inventory. And we need to get a handle for how many wells per section that might be ultimately and so we’re doing some pilot testing around that.

But the four or five wells per section, when you look at our stack basis, may be significantly higher than that..

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

A lot of good stuff you guys have this quarter. But if I could just go back to the earlier question on the Bone Spring.

I wonder if you can add a little bit to the narrative of you’ve changed your completion design and how much maybe that -- whether those, I believe it was about 13 new wells in the quarter that led to this updated type curve, whether those were using that 1,500, 2,500 pounds per lateral foot that you reference in your new completion design or whether those were before this recent [Multiple Speakers]?.

Our old completion design was really around 600 pounds per linear foot. We are now testing, as we said, up to 2,500 pounds of sand per linear foot. So far we have pumped between 25 and 30 jobs in the 1,500 to 2,500 pounds per linear foot range. Of those, we have actual well results on about half of those.

Now, some of those have just not been on very long at all. And so we’re still monitoring others we have 30 days plus. But the bulk of the well results you’re seeing in Q3 do not have the larger, thus far from a production standpoint, actual production, do not have the larger jobs in there.

And that’s why one reason we have confidence our volumes can continue to grow in the future. Now, what is the actual sand size is in our type curve. I can tell you it’s not -- it’s less than 1,500 pounds of sand per linear foot.

And so we think that if these jobs work on a consistent basis, there is additional upside to our type curve in future quarters. But we need to see those results first and see that on more wells to really be able to say exactly how much that would be..

Dave, that was an excellent answer. You actually saved me from having to ask a follow up because I was going to ask you about what the future holds up. Let me, if I could, go in a slightly different direction for my follow up, a lot of which you talks about in the Eagle Ford.

Or one of the things you talk about in Eagle Ford was the optimization of choke management once you put those wells on production. That makes sense with you guys being -- you’re taking new operatorship at that point.

But is there a chance for a similar sort of completion optimization in putting up higher sand loading on those Eagle Ford completions as well?.

We’re working with our partner BHP on that right now. Absolutely, we think there is -- we’re working with a revision of a completion design on that. We're not prepared to go into a lot of detail as we speak right now.

But we can tell you that there is -- we think there is upside associated with that when we get more results with our revised completion site. We’ve already made modifications to it, but we’d like to see more results before we actually go out with anything. I'll also mention here, Tommy here mentioned another good thing to mention.

We have done the larger revised completion design in Lavaca County where we actually operate and you’re seeing the IPs on those.

The other thing I might mention on this choke management is that we have so far most of the choke management work we’ve done, we’re doing on a very engineered basis, that has been done primarily on older existing wells that have already had significant decline.

The real upside here which we’re not seeing yet in the production numbers and which are upside to the type curve also is when we start applying this very engineered approach to new wells, to new completions and so that’s upside that we have not yet quantified for you but we think exists with the inventory.

And we’re starting to roll that in to -- again on a managed basis, managing well pressures to make sure we’re maximizing rates of return and we’re not degrading performance. But we’re starting to do this on an engineered approach with new wells. And so there's still big upside potential if it works as well as we think it will on new wells..

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

I wanted to see if you could maybe elaborate a little bit on some of the commentary around 2015, E&P capital being at similar levels to '14.

And just wanted to see if you could give us a little bit of color, because you are accelerating in Cana, you a full year of Eagle Ford spend in '15 versus '14 and you are accelerating come completion activity and you’re ramping in the Delaware as well. So just wanted to see if you can give us some comfort level with next year’s CapEx..

Arun, as you know, we’re still pouring next year’s budget. I mean we’re just working on it now and we’ll be coming out with it over the next little while. You’re right, we’re changing the number of rigs that we have working in some of the areas and all the things you point out are correct.

But part of what we’re doing is just shifting our focus to the highest rate of return areas. So for example, we expect next year that the number of rigs that we have working in the Miss will probably go down and some areas in the southern Midland basin may go down and we’ll shift those rigs over to some of these other areas.

So we feel pretty confident at this time that the kind of growth that we’ve talked about, the 20% to 25% oil growth in 2015 is achievable in a budget that is similar to what we had in 2014, which I think is a really positive development for us..

And perhaps another factor, just perhaps reduced spending at Jackfish on a year-over-year basis?.

Well, that as well. Certainly we have less spending at Jackfish. As we mentioned, we’re going to do some appraisal work and some additional engineering work on Pike, be probably $250 million. But with the completion of Jackfish 3 and relatively low maintenance capital on that whole Jackfish complex, we’ll see our expenditures come down there as well..

Arun, this is Dave. A reminder too, what I have been talking about with these previous answers I have been giving, we’re getting a lot more efficient and so we don’t have to add as much capital, because we’re getting much higher IPs and we think we’re getting higher EURs in a number of these plays. And so it’s not all about adding rigs.

We add rigs when we need to. But if we can get it rather out of better completions and much more efficient way with higher rates of return, that’s a better way to go and we think we’re accomplishing that in a number of our plays..

So just in summary, so the efficiency gains that you’re seeing are going to offset maybe higher activity levels, plus the impact of some of the carriers wearing off, is that fair?.

Right. That’s certainly part of it..

We have not seen it going up. Again, we stand by what we said on the capital though, it's going to be very similar to -- we can have these kind of growth rates with very similar capital as we had in 2014 and those were the reasons why..

And my follow-up question is just regarding EnLink. Just wanted to see, John, if you could articulate maybe your thoughts and ways to maximize value from this strategic partnership with EnLink.

And perhaps you could just remind us how this now improves Devon’s overall capital efficiency and some of the cash flows you get on a recurring basis from dividends..

Well, you hit on a couple of important points. Over the past several years we’ve had a fair amount of capital that we've put into our midstream operations. And with the transfer of assets to EnLink, that obligation or that responsibility for that expenditure goes to EnLink.

So that just leaves more of our cash flow available for our development projects, which is a good thing. We also had -- given that EnLink has very stable fixed contracts for the most part, we have a fairly reliable cash flow stream that comes to us from EnLink. And as we look at the future, we’ve got a great asset there.

The day we transfer our assets into the new entity that formed EnLink, it had a market value of about $4.8 billion today. It's somewhere up around $9 billion. And as I said earlier, we have a very visible growth profile as we continue to develop the assets that our management team at EnLink have brought to the table.

They're got a lot of organic growth opportunities. But we have continuing drop downs both from the general partner to the limited partner and from possibility of facilities drop downs from Devon to EnLink.

So all of those things point towards more efficiency on our part, more capital efficiency on Devon’s part because of the increased cash flow that's going into our development projects and an increasing valuation for EnLink over the next while. So, all-in-all a real positive development for us..

Your next question comes from the line of David Heikkinen with Heikkinen Research. Your line is open..

One question as I think about Pike and the $250 million of the spend next year, how does that fit into any partnership sell down or joint venture thoughts between now and kind of fourth quarter '15 when you remake your Board consideration?.

Well, as you know, David, on Pike, we’ve got, we’re a 50% owner of Pike and are non-operative partners with BP with a 50% interest as well.

So, this work that we’re doing is very necessary work in order for us to really understand the project and know what the capital costs are going to be and to fully delineate the area with the additional stratigraphic test flow.

So, this is work that’s absolutely necessary for us to do and it doesn’t really change anything that we might do going forward. I think we’ll get this work done over the year and then take it back to our Board for consideration in late in 2015.

And then we have the full impact on -- it really has no impact on exactly how Pike rolls out overtime, because this is work that -- this is a great looking project in what looks to be the sweet spot of the oil sands for SAGD developments.

So it's something that we absolutely need to get our arms around and then we’ll take that to our Board for consideration probably late in '15..

And then in the Eagle Ford, I thought your comments and you highlighted in, again reiterating Doug’s comments, the operation report is really helpful and kind of bold and italicized, kind of stands out.

So the potential for new type curve improvements in new wells around optimized production practices relative to your quarter-over-quarter growth rates and your 100,000 barrel a day at least target in '15.

How should we think about a sustained growth rate in the Eagle Ford with kind of new type curves, improvements and it just seems like your quarter-over-quarter growth rates accelerate given the pull down of backlog for the next couple of quarters? Is that a fair assumption to think you're accelerating growth in the fourth quarter and first quarter?.

Yes, I think just probably a pretty fair assumption, Dave. We’re really pleased with the way the things are working out and we do see with these new completions that we’re working on right now as well as our production optimization activities that we’re doing, we see that things are continuing to improve, I would say.

So, we haven’t come out with an affinity guidance regarding 2015, so I am being careful not to say too much. But I can tell you things are on the positive rather than on the neutral or negative and so we feel really good about it..

Your next question comes from the line of Paul Sankey with Wolfe Research. Your line is open..

Again, thanks very much for the additional disclosure, we always greatly appreciate that. A very high level strategy question. Hearing you talk and describe the way things are going, it sounds like the move in oil prices really hasn’t changed anything.

Is there anything that has changed in your view of future strategy as a result of the $25 drop in the barrel oil prices?.

First of all, when we’re implementing our strategy, as you know, we’re looking at longer-term prices, not with the spot prices today. And frankly, the longer-term prices haven’t changed that much from where they were when we developed the strategy and when we made the moves to so significantly transform our portfolio.

So, we put ourselves in the position today of having an asset base that has very good rates of return that can generate high margins where we can have robust growth and that has a lot of flexibility for the future in terms of oil or liquids rich gas.

So, it really -- the spot price, the change in the spot price hasn’t really affected our view of what we might do. And as we get into 2015, I think the very strong position that we are in is – we've got one of the strongest balance sheets in the sector, we’re very well hedged already for 2015.

We've got over 50% of our productions hedged at a oil price of $91 a barrel. So, we’ve got a lot of price protection from that point of view.

And with the additional financial levers that we have with the drop downs that we’re talking about and other, we've put ourselves into a very, very good position even if prices stay a little bit soft in the near term.

But as you can appreciate, as we get into 2015 and we start executing that '15 program, we’re really more interested in what oil prices are towards the end of '15 and '16 and '17, because that’s when that production comes on and when you really drive the returns on the additional work that we’ve done. So, we feel very good about the strategy.

We feel very good about the portfolio and the opportunity set that we've created for the next several years..

On gas markets, could you just update us on what you see out there on natural gas as we head into winter?.

This is Darryl. And obviously, we had -- we started out 2014 with a very severe winter weather, drove gas prices up.

As we went through December, we’ve seen additional production come on stream which was anticipated probably a little bit more than we originally thought especially out of the Utica and the Marcellus and then a very mild summer compared to the last couple that we’ve had.

But as we go into 2015, while we do see a continued increase in supply, we also are starting to see some increase in demand, we think. Most of that will come in the second half of the year and into 2016 with some additional capacity coming on with petrochemical plants, electric generation, more exports to Mexico.

So we’re still fairly comfortable that over the longer term we’re going to see prices that range between $3.50 and $5. And as we look right now, there is probably going to be a $3.75 to $4.25 price for 2015. So we’re pretty comfortable with those numbers.

Those are numbers that we’ve used in all of our economic evaluations for the last two or three years. So, just as John said on the oil side, there has really been no surprise to us in terms of what gas prices have been and how we’ve modeled the projects we’ve had before us..

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

We definitely appreciate the ops reports, thanks so much for that.

Can you talk to your needs for infrastructure investment, particularly in the Eagle Ford and the Permian over the next couple of years? And how that level of investments defers, if at all, from what is being made in 2014?.

Let’s let Darryl answer that question. He is the expert on it..

Brian, and when you’re talking about infrastructure, I assume you’re talking about what I’ll call marketing or midstream infrastructure.

Is that correct?.

Actually, let me be clear, because that’s a good point. I was thinking more to support your E&P growth. So processing to support directly support your production growth plans, any sand expansions or logistics expansion, water, et cetera, as opposed to what would be done by the midstream subsidiary for third parties..

Well, I’ll let Dave talk about water. But just in terms of, let’s take the Eagle Ford first. Our acreage, except for the Lavaca County, both on the gas side and the oil gathering side, is dedicated under a long-term contracts with third party midstream companies.

Under those contracts, they have obligations to increase capacity as we increase production in both cases. We so far have been them perform, although we did have some gathering issues on the liquids side. Once we acquired from GeoSouthern, they worked very diligently to correct those issues and each day that gets better.

So we expect in terms of takeaway both on the oil and the gas and the liquids side in the Eagle Ford that that won’t really be an issue for us. Turning to the Permian, we’re in a lot of different areas.

But what we have here is a little bit of a similar story and that a lot of our acreage that we have here has previously been committed to third parties. Now there are some opportunities in some areas for us to do independent work. But for the most part our acreage is dedicated to third parties.

And we’ve worked with them consistently over the last two or three years to make sure that we have facilities in place when we develop our wells. Now, we do not anticipate through at least 2015 and into 2016, we do not think there is going to be any takeaway capacity problems either on the gas side or the oil side or any processing issues.

Now that could change if we get much better results than we anticipate. But right now, we feel pretty comfortable where we are there. We do have some issues on some Devon facilities, gathering facilities, where we undersized those facilities based on the success we’ve had.

And so we’re now in the process of going back to those facilities and increasing capacity on those and that process is ongoing. We think most of that’s going to be completed by the end of the first quarter, maybe into the second quarter of 2015. But we feel pretty comfortable where we are from a midstream type perspective in both of those areas..

Brian, I might just -- this is Dave -- I might just talk briefly about from the sand and the water standpoint.

Before I do, I might just make a more global comment here that we have put a real emphasis internally in the company on what we call project management, which really is to make sure that we’re doing good long-term planning addressing all the issues that you’re describing. And so that’s a real focus within the company.

We’re not just out there drilling wells, we’re looking down the road two, three, four, five years and making sure we’re addressing all those issues that you’re bringing up. Regarding the sands side of the business, we think that we’re -- I am not going to say it’s not tight, it has been tight.

But at the same time we think that we have the ability through our relationships with the service companies to get the sands there for the wells. The tightest have been in the Permian Basin obviously and historically the most difficult part is what we call the last mile, which is really the trucking to the location.

Now that has been somewhat improved here in the past couple of months or so. But overall, we think it’s going to be tight. But we think that given the strength of the company and the strength of our relationship with our service providers and the bigger service providers particularly that we use the most, we can handle that.

On the water side, we do not see any significant issue there at all. We’re bringing in water actually from outside from the north into the -- near our activities located in the Delaware Basin. We don’t see any significant issue and we’ve been planning for that. So we’re in good shape..

And my follow-up is actually a follow-up to David Heikkinen's question earlier with regard to the Eagle Ford and the potential for type curve improvements next year.

Can you just add some color on what you’re thinking about spacing in DeWitt County? And whether there is the simultaneous potential for downspacing and a type curve improvement whether the spacing is set and so it would just be a type curve improvement or one of the other?.

Well we’re drilling on average at about 50 to 60 acre spacing. Now that is composed of 40 acre spacing in the more oily parts of the play and then 80 acre spacing where it gets a little bit more gassy towards the southern end of our acreage position. On an average, it’s around the 50 to 60 acre spacing currently.

Now, do I, in theory, see some potential upside for the same type thing we’re talking about in the Delaware basin where we could with these more advanced and more complex fracs that we’re not reaching out as far? Do I see some downspacing potential in theory? I think it may exist. But frankly, we’re less -- let me put it this way.

We’re less mature in our discussion process with our partner regarding that potential right now than we are in other initiatives. And so, first thing we do is get these better completion designs working real efficiently. I think we do, then we may be able to make some progress on downspacing also..

Your next question comes from the line of John Herrlin with Société Générale. Your line is open..

Dave, with respect to the shale wells with greater frac completion intensity, are you just waiting for time to recognize the improvements, are you doing any science, any monitoring, micro-seismic or traces or anything?.

We’re doing quite a bit. I’ll tell you what, I am going to turn the call over to our Head of E&P, Tony Vaughn, who can give you an even more detailed response to this, John. He’s really close to this, so I'll let him talk you about it a little bit..

John, I think you lead into a good conversation. In general, we’re being much more bullish in acquiring a lot more data than we had in the past. And I think some of the things that have differentiated Devon from some of our other companies that we compete against are just that.

And so we’re taking cores, pressures, temperatures, we’re using fiber optics in a lot of our wells around the company. We also have a well [conn] 24 hours, seven day a week, 365 center that really monitors all of our execution activities very closely. So the attention to detail is much higher.

We’ve stood up a lot of our integrated reservoir optimization teams to take this data, incorporate more technical work into it. It's really providing a lot more abilities for us to model both the reservoir, model the frac design work that we do.

So yes, the long answer is yes, we’re taking a lot more information, we’re monitoring the data, we’re micro-seismic and in some cases through fiber optics. It’s really causing us to see the real specifics about where our injected volumes are going, what’s really providing benefit and what is not.

So actually I think some of the questions that have started to call out was more -- and I think Dave hit on it very well -- was more about optimization and that’s exactly where we’re at.

So we’re seeing prove rates, recoveries and returns on almost all of our area and I think Cana was a great standalone example of taking a project that really wasn't competing in our portfolio from a commercial standpoint and through much more improved debt acquisition and technical work has turned it into a project that we are anticipating funding in a much more aggressive fashion in '15..

My next one is for John. With the free cash flow from Jackfish, obviously you could fund Pike.

But in the event that that’s not going to be a project that’s ramping up immediately, would you repatriate $1 billion a year to the U.S.?.

Well, we sure want to try to do it, John, in the most capital or a tax-efficient manner that we could.

And frankly, I will point out to you, even if we go ahead and fund Pike, we’re still going to have a bunch of free cash flow in Canada, because it's not taking out the Pike project, if they were to go ahead, it wouldn’t take up $1 billion of your EBIT. So, we’re going to have some free cash flow and my guess is that we will bring that back.

We’ll try to do it as tax efficiently as we can and deploy that here in the U.S. We haven’t -- in the past, we've sometimes left those funds offshore or in Canada because we have not had to change or alter our capital spending plans as a result of where cash is.

I mean, we've got enough balance sheet flexibility, as you know, and enough liquidity that we're not constraining our capital decisions in the U.S. by where the cash is.

So, that all points to trying to bring that cash back in the most tax-efficient way and not hurting it back because it's really not going to change our behavior in any event as long as we have the financial strength and liquidity that we have..

Your next question comes from the line of Jeffrey Campbell with Tuohy Brother Investment Research. Your line is open..

I’d like to add to the commentary on the ops report, which I’ve already told Howard, which I think is very good. But I also want to thank you for this expanded Q&A. My first question is on the Delaware Bone Spring.

Can you talk a little bit about how much the enhanced completion method is increasing the per well completion costs on average versus the previous completion methods? And can you provide any color on the return uplift that you alluded to in the ops report from these larger completions?.

The incremental cost is around $1 million, give or take, for the larger fracs. Obviously it depends on whether it's 1,500 pounds of sand or 2,500 pounds of sand, but it's per linear foot. But that’s a good estimate for what it is.

So far, and again we haven’t come out with the potential higher EURs, I can tell you that based on the very preliminary data that we’ve seen that the enhancements in the rate of return are somewhere between significant and staggering. And they are outstanding and certainly justify the incremental $1 million cost.

And so we just want to get a little bit more confidence in that before we roll out all those numbers..

The other question I want to ask was with regard to the Eagle Ford.

Could you provide some color on how you built such a large inventory through the third quarter '14 that you alluded to in the report? And going forward, what is the sort of inventory number you prefer to see?.

Well, it just has to do -- the inventory that has built up, it just has to do with the fact that we obviously -- and this part of the business again managed through BHP historically, but they just have been drilling wells and they haven’t had enough completion crews to quite keep up with the number of wells that they've drilled.

Now that is why we have agreed to increase the number of frac crews and actually they have agreed to have Devon operate two of those frac crews.

So, we were increasing from five to nine, so two of those nine will actually be operated by Devon and we anticipate they will take the number of uncompleted wells down by approximately 50%, from around 120 to somewhere around 60 wells somewhere at the end of Q4.

And that’s one of the things that does also give us the confidence not only we’re going to see good production increases in Q4, but that’s going to sustain itself through the first part of '15 as well..

Your next question comes from the line of Biju Perincheril with Susquehanna. Your line is open..

A quick question. Obviously, your domestic portfolio has improved tremendously over the past year or so.

And just wondering was that -- has there been any change in how you are thinking about the oil sands business, where does that stack up relative to your domestic business now?.

Biju, the oil sands business has some very positive characteristics that are different from some of the rest of our business. And we’ve always said that we thought that overtime we were going to provide the best returns and the most solid returns to our shareholders by having a diversified portfolio.

And we never wanted to be just the gas company or just an oil company. And so to have – we like that mix between natural gas, natural gas liquids and oil and the mix between light oil and heavy oil as a positive one because they trade very differently and have very different characteristics.

What we’ve been seeing with our heavy oil business is that the margins have increased significantly over time. And part of that is the reduction in the differentials as more certainty has risen around the Canadian oil sands business with regard to takeaway capacity and that’s likely to continue.

So our view of the future from a differential perspective is that it’s going to continue.

It’s going to become more stable, less volatile over time and that it’s going to be lower than it has been historically and that’s as a result of Energy East and Keystone XL which will come on at some point in time and Flanagan and all of the pipelines that are being built, rail now being a significant part and probably a permanent part of the takeaway capacity.

So, it’s a very good business. As a matter of fact, in this quarter, our operating margin from Jackfish was somewhere just shy at $40 a barrel. So it’s a pretty good business.

And so as we look forward, to have a piece of our portfolio and this type of asset that has basically no decline for 25 years, relatively low maintenance capital is a nice piece to have. So, it's still firmly part of our business.

And I will say that, and you’ve heard me say this, Biju, that when we got into this business, we recognized that if we were going to be in this heavy oil business, we had to be in the top quartile or a top decile project or we can’t make money otherwise.

And we are fortunate our guys did a great job and we picked a project area that is really in the top part of this industry. And so it’s a real strong part of our business going forward..

Your next question comes from the line of Phillips Johnston with Capital One. Your line is open..

Two quick question on the Medina well and other four upper Eagle Ford wells that will be spud by year end.

First, are you using enhanced completion designs on those wells? And do you plan to apply the same choke management system that you’ve tried in the lower Eagle Ford?.

Yes and yes..

And just as a follow up, you’ve talked about how these wells are located in the thickest part of the upper Eagle Ford and certainly thicker than the area to the Northeast where there have been some very good well results by other operators.

My question is, what sort of IP rates or 30-day rates would you expect from these wells? And if the wells are successful, how many upper Eagle Ford locations could you potentially add to your overall inventory in the Eagle Ford?.

Well, I don’t want to -- it’s not even about initial IP or 30 day rates. It’s about the sustainability of those rates and what kind of EURs we need ultimately from those wells. So I don’t have a specific number that I am going to lay out there for that to judge success or lack of success on those.

But we’ll be obviously watching the first few months of performance. How much there is? We’re not quite ready or I don’t think we have enough information really to say how much additional resource or how many locations we have. We need to see some success here. This is a different type of formation geologically also.

This isn’t a shale this is a marl, which is a type of carbonate reservoir and actually has a little bit of primary porosity to it. So it’s going to behave significantly different than a shale reservoir well. And we need to see more results to really say what kind of spacing we could have if we works to see how many locations.

I will point out, I think you’re probably well aware that obviously there have been some wells drilled to the Northeast by other operators, Penn Virginia and others, but I think also if you move to the Southwest, there have been other companies, I think specifically Marathon has been drilling wells for the same interval.

This is not the upper Eagle Ford shale. Some might call this the lowest-most Austin Chalk. But we’ve chosen for historical marketing reasons I say to call it the Eagle Ford rather than the Austin Chalk. But it’s actually a marl section that’s above the upper Eagle Ford shale..

There are no further questions at this time. I will turn the call back over to John Richels, CEO, for closing comments..

Thank you. And let me just make a couple of comments and I’ll turn it over to Howard just for a couple of comments as well. But I just want to say a couple of things. Thank you for hanging in with us for this long call and we got some great questions. But just want to pass on our thoughts here.

We’ve seen a significant transformation in our asset portfolio over the past year. So we have a great portfolio today with high margin assets and a portfolio that has years of visible growth.

So today we are laser focused on execution and that’s what’s helped us deliver a great quarter for the third quarter of 2014, allowed us to raise our full year production targets and we’re not taking our foot off the gas. This strong operational momentum is going to continue into 2015 as we continue to grow our oil production and our cash flow.

And again, notably, I think we’re doing that in a very capital efficient manner. We’re well positioned to fund our 2015 capital program with our strong financial position.

And lastly, while we clearly possess a great deal of financial strength, we are fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our growth in cash flow per share adjusted for debt. So with that, again, thank you for hanging in. And I’ll just turn it back to Howard..

Thanks, John. And I’d like to echo John’s thoughts. We appreciate all your support. I also appreciate the kind words on ops report and the other changes. I want to throw out some thank yous to Scott, Shea, Chris and the rest of the team that have done an outstanding effort to bring this forward.

And if you have any additional questions, please don’t hesitate to give any one of us a call. We look forward to seeing you out on the road. Have a great day. Good bye..

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