Welcome to the Devon Energy’s third quarter earnings conference call. (Operator instructions) At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you, and welcome everyone to Devon’s third quarter earnings call and webcast. Today’s call will follow our usual format. I’ll cover a few preliminary items, and then turn it over to our President and CEO, John Richels, he will provide comments on the quarter. And then following John’s remarks, Dave Hager, our Chief Operating Officer, will provide the operations update. We’ll wrap up the prepared remarks with a financial review by our CFO, Jeff Agosta. After Jeff’s discussion, we will have a Q&A session and we will conclude the call after about an hour but the investor relations team will be available for the rest of the day for any questions that we don’t get to during the call. During the call today, we’re going to update some of our forward-looking estimates based on our actual results that we’ve seen over the first nine months of the year and outlook for Q4. While we will not be filing a revised Form 8-K we will post estimates reflecting these adjustments that are provided during the call today on the guidance page of our website. To access that guidance, click on the guidance link, down within the investor relations section of the Devon website. All references today to our plans, forecasts, expectations, and estimates are forward-looking statements under US securities law. These are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are, of course, not guarantees of future performance. You can see a discussion of the risk factors relating to these estimates in our Form 10-K. Also on today’s call, we will reference certain non-GAAP performance measures. When we use these measures, we’re required to provide certain related disclosures and those can be found on Devon’s website. At this point, I’ll turn the call over to our President and CEO, John Richels.

Thank you, Vince, and good morning, everyone. The third quarter was another solid one for Devon, both, operationally and financially as we continued to deliver on our strategic plan. Higher oil production combined with better prices drove significant improvements in our margins, allowing us to comfortably exceed Wall Street expectations for both earnings and cash flow for the quarter. We achieved third quarter US oil production growth of 38% year-over-year, largely driven by success in our Permian Basin development programs. Over the past two years we have doubled our light oil production in the US to 81,000 barrels per day and by yearend we expect our US light oil production to top 90,000 barrels per day. Most importantly, our success in growing our US light oil production has resulted in higher margins and improved profitability in the current commodity price environment. Looking beyond the low-risk development projects that are driving today’s growth, we’re also investing in opportunities that will provide the next leg of high margin production growth for Devon. In the US, we’re highly encouraged by the progress we’ve made with our Mississippi and Woodford and our Rockies oil plays, our light oil production in these plays is growing rapidly and it’s currently approaching 20,000 barrels per day. Dave is going to speak to this later on in the call. We’re also laying the ground work for continued long-term growth with investments in our world-class portfolio of thermal oil projects in Canada. These projects remain on-track to produce at least 150,000 barrels of oil per day by the end of the decade. And this highly visible oil production growth out of Canada will be significant contributor to our long-term success. Our company-wide focus on oil production is not only delivering volume growth but it’s also improving our revenues and…

Thanks, John. As John mentioned, the third quarter was one of solid execution by our asset team, resulting in strong oil production growth. This growth in oil production, combined with effective cost management, allowed us to expand margins and grow cash flow. Looking specifically at costs, our results year-to-date have benefited from our supply-chain efforts and improved drilling efficiencies. As a result, our service and supply costs have declined by roughly 5% compared to 2012. In addition, we are realizing cost savings through drilling efficiencies in each of our core operating regions, allowing us to complete our full year programs with fewer rigs than originally budgeted. Due to this enhanced productivity, as of the end of September, we had reduced our rig count by 10% from last quarter to 64 operated rigs. Now let’s take a closer look at some of the key operating highlights in the third quarter. Beginning with the Permian, our production averaged a record 82,000 barrels of oil equivalent per day with light oil accounting for 60% of our total volumes. We are currently running 23 operated rigs in Permian and by year end, we expect to have drilled more than 350 wells for the full year. In the Delaware Basin, our Bone Springs horizontal program continues to be a key driver of our Permian oil growth. We currently have 12 operated rigs working in the play. In the third quarter, we brought 24 Bone Springs wells online with average 30-day IP rates of 609 barrels of oil equivalent per day, of which more than 70% was light oil. These production results are about 20% better than our tight well profile. With a large portion of our acreage de-risked and in the development stage, pad drilling is playing an increasingly important role in our development plans.…

Thanks, Dave, and good morning, everyone. I will take you through a brief review of the key drivers that shaped our third quarter results and, where called for, provide updated guidance. I will also elaborate on the good news about our cash repatriation plan that John mentioned earlier. Looking first at production, in the third quarter, we produced approximately 64 million oil equivalent barrels or about 691,000 equivalent barrels per day. This was in the top-half of our guidance range and most importantly was underpinned by strong high margin oil growth. For the quarter, Company-wide oil production averaged 165,000 barrels per day, an increase of 16% compared to the same period last year. As John detailed earlier, this growth was driven entirely by our US properties with light oil production up 38% year-over-year. Looking at the fourth quarter, we expect strong oil growth in the Permian Basin and the Mississippi and Woodford trend to continue, driving US light oil production up more than 30% compared to the fourth quarter of 2012. This impressive growth will increase our expected total Company-wide oil production next quarter to a range of 170,000 to 175,000 barrels per day. After taking into account declines in dry natural gas, we expect total Company-wide production in Q4 to range between 680,000 and 700,000 BoE per day. Overall, this keeps us on-track to deliver on our full-year production guidance of 250 million to 254 million BoE. Moving to price realizations, overall our third quarter regional price realizations by product were generally in line with our expectations. Looking specifically at Canadian oil prices, in the third quarter higher season demand and improved flow rates on export pipes for heavy oil out of Canada, improved our realizations to 75% of WTI or $80 per barrel. This represents the best oil…

Thanks Jeff. (Operator Instructions). With that operator, we’re ready for the first question.

(Operator Instructions). Your first question comes from Scott Hanold of RBC. Your line is now open. Scott Hanold – RBC: Thanks. Good morning. Looking at the Permian Basin, the Southern Delaware, you know, kind of a couple of questions. You talked about expanding your inventory there, can you give us a little bit more color on that, like, how many of the benches down there you all have tested and which ones you think are going to be prospective and which ones in your current well count? And then the other thing is, I think you all just recently acquired Forest Oil’s acreage down there, can you give us a little bit of thoughts on what you’re seeing there?

Yeah, Scott, you’re talking about the Southern Midland Basin, I think, aren’t you? Not the Delaware Basin. Scott Hanold – RBC: Oh, I’m sorry if I said Delaware, yes, you’re correct.

Yeah, right. Yeah, we have tested and there’s obviously a nomenclature issue within the industry that we prefer to call it that we have tested both the Middle and the Lower Wolfcamp, those are the primary prospective zones on our acreage. We are right now, for the most part, have very little across the acreage, but for the most part we are completing in the Lower Wolfcamp and we believe that allows us to actually frac up to the Middle Wolfcamp as well. So, by industry nomenclature, I think that would be completing more in the F and then the frac would contribute on up through the D in there. Regarding the Forest acreage, that’s the part that I didn’t mention in my comments earlier. That’s the additional acreage that we acquired. It’s a little over 50,000. I think, around 53,000 or so total. We haven’t drilled any wells on that acreage yet, we will start drilling those next year. And that’s the comment I was making that I do believe that we’ll expand our inventory. We have not expanded our inventory at all in the comment that I gave to you already on the – but we fully anticipate that it’s going to work and will be additive to the overall position. Scott Hanold – RBC: Okay. And just to again clarify on your current inventory count in the Southern Midland Basin, I think it was 800 locations. Is that assuming an Upper and a Lower Wolfcamp?

It is considered what is appropriate to complete in each of those. And we have not really plugged into there that we would have multiple completions at the same location. So, that’s a single completion at each of our locations. It is possible, through time, we may see that we may complete in more than one zone from the same location but we haven’t included it in our location count. Scott Hanold – RBC: Okay. Because I think some of your competitors or peers are talking about anywhere from two to four different formations prospective in each zone location, is that –

That’s certainly a possibility through time and we have the same opportunities our peers do, it’s just how we choose to classify our locations, perhaps a little more conservative. Scott Hanold – RBC: Okay. And based on your acreage contracts, do you have to drill lowest formation to hold everything.

Scott, I’d have to check on that. That is typical that you would, but I’d have to check – let me think about it whether it – I’m going to – yeah, I’ll give you some clarification here, they are saying we are in the same zones. So it doesn’t -- don't think we have to. Now more I think about that, I think that’s right that if drill in the operator, we still the hold the lower.

Your next question comes from Vinnie Wong of Morgan Stanley.

I know that Crosstex deal hasn't closed yet, but can you tell us how you are thinking about maybe the drop-down pace of assets into the MLP just so -- you mentioned the benefit of the combination versus doing IPO in terms of speed to market?

Vinnie [ph], there's really a couple of different drop-downs that we can do in the MLP. As you know, we put half of our assets into the GP and half into the MLP. So there will be a continuing drop-down from the GP to the MLP of interest in our midstream company. And then we do have other assets, the one that we flagged at the time – other assets that we didn't put into the MLP, one of the assets that we've flagged at the time was our interest in the Access Pipeline, which is the pipeline that services our Jackfish and Pike acreage and also has third-party volumes from other operators in the area. And that's certainly something that we can drop down. When we do that, it's a little bit up in the air right now, and of course, we are constructing that. I think it's going to be completed by the end of 2014 roughly and third quarter 2014. And so a 2015 drop-down is certainly possible. We'll have to kind of take stock of things at the time that we finish it. I think the really important part and the really exciting part for us is that not only we kind of got a market valuation of what those assets are, but in the future it gives us a lot of flexibility around building new assets, dropping down some existing assets that we haven't put in yet, and also doing acquisition and by doing that it accelerates the value over what we'd otherwise have seen.

Okay, great. And just my second question is in regards to $2 billion in cash being repatriated, can you update on what you are thinking there and particularly where you guys want to put it?

As Jeff mentioned, it's likely to be around year end before we can repatriate those funds. Vinnie, as you may know and most of the folks on the call are probably familiar with the factors that we've talked about in the past that we take into account as we allocate our capital and the objective we've always enunciated is to optimize cash flow for debt adjusted shares. So, when we bring that cash back around the end of the year, we'll allocate using the same parameters. We're right now in the middle of and – or continuing to develop our 2014 capital budgets and we'll do that over the next couple of months. And as we move into 2014, we'll finalize our capital allocation decisions. At that time, share buybacks are always included in our consideration to capital investments and we’ve got a great track record of buying stock back over the years. But to give you any more definite guidelines around that right now would be a little premature.

Your next question comes from Jeffrey Campbell, Tuohy Brothers Investment. Jeffrey Campbell – Tuohy Brothers Investment: Questions on the Woodford oil play. My first question is as I wasn't entirely sure from what I heard, is all of your current drilling on JV lands or are you also doing some drilling aside from the Grant County, kind of sounds like a wildcat, are you doing any drilling on your non-JV acreage?

This is Dave. We just have one rig that's working outside of the JV. The rest of the rigs are working within the JV. And that's the rig in Grant County. Jeffrey Campbell – Tuohy Brothers Investment: And my other question with regard to the Woodford, I'm looking at the map of your acreage in the area. Do you believe that you have prospectivity in any of the other counties besides Grant? I'm thinking non JV again, like maybe Kay or Sage County.

Well, it's possible. We need to drill some wells over there and determine it. Again, we are seeing such an advantage here of getting 3D seismic and that's what's really helped us out dramatically within the JV. We're going to drill a few wells up here in Grant and Kay County without 3D just to – 3D in and of itself costs a fair amount of money. And so we want to make sure that we have a working petroleum system up there before we actually spend the money on the 3D. We now have in Grant County enough confirmation that through the wells that I discussed that we are shooting 3D up there. We will be going through the same process in Kay County and that – the overall comment that I’ve made before is that we have 650,000 acres in total in the Mississippi and of that we believe there are sufficient thickness of the Woodford to have potential prospectivity across 400,000 of that 650,000 acres. To-date we feel we have de-risked 100,000 of that 400,000 acres. So, we have the thickness across the 400,000 but there are other elements that factor into there as far as the maturity of the oil, do you have sufficient permeability, et cetera, and that’s what we’ll have to determine across that other 300,000 acres we’re talking about, some of which is in Grant and some of which is in Kay. Jeffrey Campbell – Tuohy Brothers Investment: Okay. Great. That was great color. Thanks very much.

Your next question comes from Matt Portillo of TPH. Your line is now open. Matt Portillo – Tudor, Pickering & Co.: Good morning, guys. Just a quick question for me in regards to your oil growth guidance for Q4. Looks like kind of a step up on a quarter-over-quarter basis, is pretty flat especially with the ramp-up in the Canadian volumes. So, I was just wondering if you can comment maybe where we’re seeing a little bit of a deceleration in the growth into year-end or if that was in line with your planned expectation going to the fourth quarter here?

Yeah, Matt, it’s a little bit less than we guided to last quarter. The first thing I want to make clear to everyone, though, about this is our wells are delivering exactly as we anticipated. I went through it area-by-area. The capabilities of the wells are there. That is not the issue. The issues – there’s a couple of other issues that have factored into it though overall. First, we are seeing some down time with our ongoing production in the Permian, especially as related to electrical submersible pump that we’re running in all of these. Our run time of those has been a little bit less than we anticipated. We’re working through that issue as we speak but that has caused our base production to fall a little bit short of what we anticipated. Nothing to do with the productivity of the wells, just the efficiency of the pump. Secondarily, in the Rockies because of the success we had with the Rockies drilling program, we took a little bit of capital out of CO2 that we’re going to expand, that were going to deliver a few thousand barrels a day and kept a rig running in the Powder River Basin because of the outstanding results we’re getting there. Those volumes, associated with that rig, will show up next year but not this year. And then finally, because of the stronger prices when we put our projection out there that we were seeing in Canadian oil because of the stronger realizations we anticipated royalties would be a little bit higher. And so that would cause the net production to go down a little bit as well. But having said all that, I want to make sure that you understand the US oil growth in Q4 is going to be greater than 30% versus Q4 of 2012. So we’re still having very, very strong oil growth, it’s just some minor issues like that, these have nothing to do with the productivity of the well, that have caused it to decrease it a little bit. Matt Portillo – Tudor, Pickering & Co.: Great. Thanks for the clarification there. And just in regards to some of the initial well results you’ve seen in the Woodford. I was wondering if you could potentially compare the rates of return you’re seeing on your Woodford programs versus your Southern Midland program? And if you continue to see strong initial rates here, in line with your or above your type curve could we potentially see capital allocated away from the Permian into the Woodford or an acceleration in Woodford drilling? Thank you.

Well, we’re going through that entire evaluation process right now, of comparing the returns. And we’re obviously a little bit less in the overall maturity of the program in the Woodford then we are in the Southern Midland Basin. But having said that, we’ve had some outstanding results this quarter with well, well above the type curve and, of course, highlighted by the Jardo [ph] that had a 30-day IP of 2,200 BoE per day. So we like both these plays an awful lot. And to ask me to make a decision between one or the other is kind of tough because they are two of our top plays and we like them both but we’re certainly very pleased with the Woodford results. Matt Portillo – Tudor, Pickering & Co.: Thank you very much.

Your next question comes from Arun Jayaram of Credit Suisse. Your line is open. Arun Jayaram – Credit Suisse: Good morning. John, it’s been a busy year on the strategic front. By year end you will complete in a two major repatriations and you’ve got the midstream transaction. So just wondering if you could maybe comment on where Devon is in terms of the overall portfolio. Anything else that you are working on in terms of the portfolio changes, or is this the asset base going forward?

Well, Arun, as you know, in this business that's a constant. We are always looking to bring good opportunities into the asset base and sometimes that means that other opportunities don't look as attractive anymore and you move them out. So, that's not something that we – that's a continuum. We're not at the end of it. We always got to look at that. So, it's an ongoing process to continue to try to increase our productivity as a company and our value for our shareholders. It's something we're looking at all the time. Arun Jayaram – Credit Suisse: John, just to maybe elaborate on that. At one time you guys had – was doing some analytical work around Canada, maybe a spin-off or something like that. Have you come to a decision on that, or are you still evaluating that?

I think these things are all things that we're evaluating all the time, and I think you know that in our history, we've proven that we're not afraid of making bold moves when we have to, but a lot of things people talk about and reflect on from the outside don't always add long-term value particularly when you look at taxation and everything else that's involved. So we're always looking at how we might bring value forward, and as we've previously said, we're not leaving any stone unturned. But we're not going to do things that – we're only going to do things that add long-term value and we're not going to take action simply for action's sake. So, these are things we're always looking at, but sometimes they’re not quite so simple. Arun Jayaram – Credit Suisse: That’s helpful. Dave, I wanted to see if you could elaborate a little bit more on this ESP-related downtime. Is this something that could have a knock-on effect as we think about 2014, or is it more isolated to the fourth quarter?

Well, it's something that we're working on right now, and we think it’s very solvable. Basically, we're running these ESPs in an unconventional environment, and frankly, running a lot of sand through these ESPs, which as you can imagine, running sand through pumps is not a great thing for long-term life. But we are working with some of our vendors on ways that we can get a better design out there. We're also working on ways that we can improve the efficiency of replacing these ESPs, and so, I don't think it's going to have a long-term impact. We have a special team, I can tell you internally, that’s working at very hard along with our vendors. And I think it's something that we're going to come to a good answer on here in the next three or four months. And frankly that's just one of the things that contributed to it. The other I mentioned was a change in the Rockies program to the additional rig and also the impact of potentially higher royalties due to improved realizations in Canada. So, I wouldn't overplay that. It's just one of the several factors. Arun Jayaram – Credit Suisse: My last question would be just what your new midstream spending levels could look like post the closing of the transaction?

That of course is dependent upon where we choose to spend capital and so we're going to – we're in the processing of working our 2014 capital budget. And until we've got the upstream piece we won't know exactly what the midstream piece is, but directionally surely, I mean, we certainly expect it to be down.

Your next question comes from Charles Meade of Johnson Rice. Charles Meade – Johnson Rice: Going back to the Woodford, can you give us an idea if that 75% to 80% oil cut that you see in the Jardo [ph] well is representative of what the oil gas spilt is for the rest of your wells there?

Well, in all of our wells in the Woodford, it's going to have a higher oil cut early in the life, which certainly is beneficial from a rate of return and NPV standpoint. Although over the life of the well, we anticipate they will become more gassy and the ultimate -- and when you looked at total EUR, it will probably split about equally, one-third each for oil, natural gas liquids, and natural gas. Charles Meade – Johnson Rice: And then I know it's early in the play and clearly this Jardo [ph] well is a great well, but I was wondering if you could elaborate a bit on if this well – if you had an idea ahead of time that this well might really perform well, whether because it's a long lateral or whether there is something you saw on the seismic that gave you an indication whether this was just a surprise to everybody?

Well, it was a long lateral, so that certainly helped but there also were some other geological characteristics which, of course, I’m not going to tell you that we had observed ahead of time and we think that that benefited that. Your obvious follow-on, is it repeatable, I’m sure. And to some degree, yes, but it’s not going to be – we’re not going to be able to drill those wells everywhere across the acreage but we think we have a good idea for what allowed that and we’ll have some of those type wells across our acreage position, we think, again. Charles Meade – Johnson Rice: Dave, you understood exactly what I was after. Thank you for the added detail.

Your next question comes from David Tameron of Wells Fargo. Your line is now open. David Tameron – Wells Fargo: Good morning. Can you guys just talk about, in the Permian can you – and you addressed this a little bit but you can you give me some color on Delaware versus Midland, the differences between the two and kind of the rates of return and well cost?

Are you talking specifically, David, about the Wolfcamp or across our entire portfolio? David Tameron – Wells Fargo: No, I mean, just what you’re seeing on the Bone Springs versus you know – and I was just studying the wells you put in the press releases as far as the Permian well and the Bone Spring well look to have higher IPs by couple of hundred barrels or so, I guess, close to 300 barrels, on those 30-day rates. And I kind of looking at that versus –

Right. Yeah, in general to answer your question, the Bone Springs are our highest returns in our portfolio in the Permian Basin and amongst the highest in our entire portfolio as a company. Although all of them generate strong rates of return, the Bone Springs are a little bit better, no question. David Tameron – Wells Fargo: Okay. Alright, I’ll leave it at that. That’s all I got. Thanks.

Your next question comes from Mark Hanson of Morningstar. Your line is now open. Mark Hanson – Morningstar: Good morning, guys. Two quick questions for you. First, how would you characterize the Miss Lime’s performance relative to your expectations based on results to-date? I know you’ve given an awfully good color this morning across the trend, both, Woodford and Mississippi Lime. Just seems, from commentary you provided, you’re a bit more enthusiastic about the Woodford at this point?

Well, we still like the Miss Lime an awful lot. It is meeting out type curve expectation, certainly within the JV and is actually above our type curve expectations slightly. So we’re very happy within the JV. North of the JV and in Grant and Kay County we’ve had mixed results. I had talked about one very good well that we had out there in the past quarter. We’ve had some that are not as good. But you have to understand, this is done without the benefit of seismic. So, the primary thing we’re trying to do up there outside of JV right now is see if we have enough evidence to have a good strong working petroleum system and which we now are confident in Grant County that we do have that. And now that we have that, we’ll shoot 3D up there and we’ll really refine where we’re drilling those wells and I would anticipate the results to become much more consistent and to improve with the benefited of 3D. But overall as far as the Miss goes, it is meeting our expectations just at this Woodford particularly within the joint venture area. Now, we’ll have at least one well up in Grant County that’s somewhat encouraging as well. It’s working spectacularly. Mark Hanson – Morningstar: Great. Very helpful. And then the second question, just with your Permian rig count, I saw that it dropped by a meaningful amount, I don’t know if that’s related to the ESP issues, but any more information on where rigs were dropped and the things –

Yeah, it has nothing to do with the ESP issues at all. We dropped our rig count because we become significantly more efficient in drilling our wells. We executed our entire program for 2013 and we could execute it with less rigs. So, if we had kept the same amount of rigs we would have overspent our capital for this year. And so we were just exercising capital discipline to stay within the overall capital by reducing our rig capital. We executed the program we had intended to this year. Mark Hanson – Morningstar: Great to hear that. Thank you.

And your last question comes from Biju Perincheril of Jefferies. Your line is now open.

Biju, we apologize for butchering your name. Biju Perincheril – Jefferies & Co.: That’s quite alright; I’m used to it. The question I had was on the Wolfcamp. It looks like the 30-day rate this quarter was maybe a little bit lower than what you had in the past. And I was just wondering if that’s because you’re changing anything around on the completion front or is that just the normal variability?

Nothing significant there, Biju. The change around, it’s just what pads we happen to be bringing on this quarter but I wouldn’t read anything else into it. Next quarter, it could go back up just as easily as it went down a little bit this quarter, nothing significant there. Biju Perincheril – Jefferies & Co.: Aerially or geographically, were you drilling in the generally same areas?

Yes, generally we're drilling in the same areas still. One comment I want to make to Scott Hanold, asked a question that kind of stopped me earlier about holding all rights and the reason, I wasn't thinking about it as clearly as I should have been. The answer is it's kind of an academic question, because we're actually completing in a lowest Wolfcamp zone. So because we are completing in the lowest Wolfcamp zone, we're going to have all the rights above that, so it's really an academic issue. We'll hold all that. Biju Perincheril – Jefferies & Co.: And one question along those lines is do you have any plans in the near-term to test different horizons at the same location?

Nothing immediate. We recognize the prospectivity there, but we are right now just delineating our entire acreage position.

Well, folks I'm showing the top of the hour. So that concludes today's call. As usual, our investor relations staff will be around the rest of the day to answer any questions that didn't make it into the call or if you come up with other things during the day. So before signing off, I'd just like to go over a few key takeaways. First, our core assets are performing very well leading to higher oil weighting for our portfolio. This is driven by the 38% year-over-year growth in light oil production from our U.S. portfolio. Results from our emerging U.S. light oil plays and long-term investment in Canadian thermal oil are providing visibility on the next leg of oil growth for Devon. Our pursuit of high margin production is improving profitability and we are doing excellent job of controlling, operating and capital costs. By year end, we will have repatriated $4 billion of cash at very favorable tax rates translating into about $1.75 per share benefit to Devon shareholders, and finally, we took another significant step forward in unlocking unrecognized asset value within Devon through the formation of our new midstream business. Going forward, our approach to the business remains unchanged. We will continue to pursue our top strategic objective, and that is to maximize long-term growth and cash flow per share after adjusting for debt. So, we look forward to talking with you again on the next call, and thank you very much for joining us today.

And this concludes today's conference call. You may now disconnect.