Vince White - VP, Communications and IR John Richels - President and CEO Dave Hager - COO Tom Mitchell - EVP and CFO Darryl Smette - EVP, Marketing, Facilities, Pipeline and Supply Chain

David Hickman - Hickman Energy Advisor Doug Leggate - Bank of America Merrill Lynch Brian Singer - Goldman Sachs Arun Jayaram - Credit Suisse Subash Chandra - Jefferies

Welcome to Devon Energy’s Second Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. After the prepared remarks we will conduct a question-and-answer session. The call is being recorded. At this time, I’d like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you and welcome everyone to Devon’s second quarter earnings call and webcast. Before we get started, I want to make sure that everyone is aware that we have prepared a handful of slides to supplement today’s script. These are integrated with today’s webcast and they’re also available for download in PDF form on Devon’s home page devonenergy.com. For those that are not participating via webcast, we’ll make sure we refer to slide numbers during our prepared remarks so that you can follow along. Today’s call will follow our usual format and I a few preliminary items to cover, then I’ll turn the call over to our president and CEO, John Richels for this comments, following John, Dave Hager, our chief operating officer will provide an operations update and we’ll wrap up the prepared commentary with a financial review by our CFO, Tom Mitchell. After our financial discussion, we’ll have a Q&A session and we’ll conclude the call after about an hour and of course a replay will be available later today on our Web site. The investor relations team will also be available this afternoon should you have any follow-up questions. On the call today, we’re going to update some of our forward looking information. In addition to the updates that we are providing in the call, we will file a Form 8-K later today that will have details of our updated 2014 estimates. A copy of this updated 8-K will be available within the Investor Relations section of the Devon Web site as well. The guidance we provide today includes plans, forecast, expectations and estimates which are forward-looking statements under U.S. Securities Law. These are of course subject to a number of assumptions, risk and uncertainties many of which are beyond the Company’s control. These statements are not guarantees of future performance and we’d invite you to see the discussion of risk factors relating to these estimates and our Form 10-K. Also in today’s call, we’ll reference certain non-GAAP performance measures. When we use these measures we are required to provide specific related disclosures, those disclosures can be found on Devon’s website. As many of you know I am retiring from Devon at the end of this week. I can honestly say that being a part of this organization for the last 21 years has been both a pleasure and a privilege. I am truly grateful to all my friends at Devon and in the investment community and the industry for making my time here so rewarding. So thank you. At this point I’ll turn the call over to John Richels. John.

Thank you Vince and on behalf of the Company and many people you have positively impacted over your career. I just want to take this opportunity to thank you. You’ve done a terrific job through the years and you have been a great friend and we wish both you and Marty a very happy and healthy retirement. Now as many of you know with Vince’s retirement, Howard Thill has joined our team as Senior Vice President of Communications Investor Relations. Howard has a long history in the business with over 30 years of experience the last 12 and much the same role at Marathon Oil and previously at Phillips Petroleum. We’re very fortunate to have an individual of Howard’s experience join our team and we welcome Howard to Devon. I am sure that many of you will have the opportunity to meet with Howard over the coming months. So let’s move to the results of the quarter. The second quarter was another outstanding one for Devon both operationally and financially as we continued to successfully execute on our strategic plan. As we point out on Slide 3, during the quarter we announced the sale of our non-core U.S. assets the final piece of our portfolio transformation. Since announcing this planned transformation just nine months ago we have taken three very significant steps to reconfigure our portfolio, the accretive Eagle Ford acquisition, the unique and innovative EnLink transaction and the sale of our non-core properties at very attractive prices. Also during this time our drilling program has delivered impressive oil production growth through our focus on our reconfigured portfolio. This oil focused effort helped to deliver a 47% increase in cash flow this quarter compared to last year’s second quarter. And during the period we also completed number of major projects…

Thank you John. As John mentioned our solid execution in the quarter resulted in strong oil production growth driving an impressive increase in our operating cash flow. We are laser focused on the key drivers of outstanding operational performance, including driving down drilling times, optimized conclusion designs and very efficient production operations. Continuous improvement in each of these areas and others will provide incremental value in each of our operating areas. Now let’s take a closer look at some of Devon’s key operating highlights in more detail. In the Permian basin we increased production 25% compared to the same quarter last year to 95,000 BOE per day. The solid execution of our development programs in the Permian place is firmly on track to grow 2014 production by 20% compared to 2013. Importantly light oil production accounts for nearly 60% of our total Permian volumes. Shown in the green outline on Slide 13, is the Bone Spring play in Delaware Basin, a key driver of our Permian oil growth. In the second quarter we brought 22 new Bone Spring wells online, with average 30 day IP rates of 660 BOE per day, once again exceeding our pre-drill expectations. At an average cost of just over 6 million per well our Bone Spring program is delivering some of the best returns in our portfolio. We also have an ongoing Delaware Sands program that is beating expectations. In the second quarter we commenced production on two high-rate oil wells targeting the Delaware Sands Lea County, New Mexico. Initial 30-day production from each of these two wells averaged about 1,000 BOE per day, 70% of which was light oil. As we discussed last quarter the tremendous results from our Delaware Basin drilling programs coupled with an ongoing reservoir characterization work allowed us to substantially…

Thank you, Dave and good morning to everyone. To reiterate John and Dave’s comments, the second quarter was one of strong execution. We delivered operationally by successfully exploiting the high margin production opportunities within our portfolio. And we also delivered solid financial results as well. Our strong growth in oil production, combined with improved oil price realizations drove our E&P upstream revenue to 2.7 billion in the second quarter. These factors increased oil sales to more than 60% of our total E&P revenue in the quarter, pushing overall upstream revenue 20% higher than the year ago quarter. Not only are our upstream revenues growing rapidly but our midstream profitability is expanding as well. In the second quarter, our midstream business delivered excellent results, generating 224 million of operating profit. This result exceeded the top end of our guidance range and represented a 90% increase compared to the second quarter of last year. The year-over-year increase in operating profit was driven by the consolidation of EnLink Midstream and improved marketing margins. Based on our outstanding results in the first half of the year, we are increasing our full year forecast for midstream operating profit to a range of 775 million to 825 million, an increase of roughly 80 million from the midpoint of our previous guidance. Moving to expenses, in the second quarter total pre-tax cash costs were well within our guidance range for the quarter coming in at 1.1 billion. Excluding the cost associated with the consolidation of EnLink, pre-tax cash costs for our upstream business were 7% higher than the second quarter of 2013. Now this amount, a third of the cost increase was attributable to higher operating cost associated with Devon’s rapidly growing high margin oil. The remaining increase was driven by higher production taxes related to our…

Thank you, operator we are ready for the first question.

Thank you, your first question comes from David Hickman with Hickman Energy Advisor. Your line is open.

I wanted to look at 5-15 days and just talk about each of the objectives you highlighted to get to the risk factor, can you just give us like what was the number one or the number two objective in the Delaware, Leonard, Bone Spring and other just to get to the 30% to 50% risk factors?

: It was the primary things you have to look at, we looked at everything but you look at the prospectivity of the area based on all the well results you have and then you also apply what we call a drillability factor, can they physically be at locations, physically be accessed with our acreage inventory, those are two primary things we look at and then we also are looking at obviously historical production data to help it out and we all put it into what we call in multi-variant analysis but we remove bias and this is a statistical analysis where we are looking at basically trends in an un-bias manner that correlate with prospectivity. That doesn’t totally substitute for good technical work but it’s an additive to that but those are the main things you are looking at traditional things you are used to David is just good geosciences work, combined with reservoir work and production history.

And I guess where I’m going is, as you get more production history in the Leonard and in the Bone Spring sands, do you expect those risk factors to move up with well performance there, how do things trend over time?

: Well, the latest table constructor we hope the risk factors move down actually because the lower is the better, the way we constructed the table. Yes absolutely, as get more data we expect these risk factors to go down. And I think the biggest thing we expect to move up perhaps is this column this risked wells per section, because that’s where we simply don’t have enough data to do this kind of multi-variant analysis, because there hasn’t been a lot of wells that have been drilled, six wells per section or eight wells per section in order to get a good history on. So in this case we didn’t really do that detailed statistical analysis, we just made -- what we think is a very conservative assumption and as we conduct these pilots which we’re doing right now. We think there is great opportunity that we may increase from the four to five wells per section to more wells per section. But we just want to get some pilot information before we do that.

And then just thinking about that and leading to the 5,000 the likely grows. What’s the optimal kind of inventory life as you think about the basin relative to the number of wells you drill per year?

: The way we think about it, is we generate as many as we can obviously, then we try to put as many rigs to work as we feel that we can and maintain the quality of our drilling results. So we identify huge new resource inventory, that’s great news. But then we got to think about what can we actually execute and deliver the results with the risk that we perceive in the basins. So I don’t know if there is an optimum. I mean I would love to have 100 years inventory, totally theoretical standpoint. But what we’re trying to do is increase the pace of our drill commence with our ability to de-risk the area. And we’re confident we’re going to be able to get somewhat around 20 rigs next year and we’re thinking higher than that internally but we got to walk before we run and so we’ll see where it goes.

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

If I could take two questions please. First of all Dave on the Eagle Ford, just to be clear I am assuming you had no inventory in the upper Eagle Ford in your initial analysis when you acquired your southern. And if that is the case, can you give us some ideas based on (obviously) [ph] a number of third party wells that hoped and drilled near for Eagle Ford. From what you know today, what would you say about how -- at what proportion your acreage is perspective? And anything you could say about how that may change the inventory count? And I have a follow up please.

: Well we had none of this and the inventory at the time we did the acquisition we gave zero value to the upper Eagle Ford. So this is all additive from a value standpoint. As you can see from the isopach map that we included in the presentation, we think the bulk of our acreage is perspective for the upper Eagle Ford. The key is that there is an ash zone that develops that we think that will contain the fracs that have been done in the lower Eagle Ford from penetrating up to the upper Eagle Ford. And when we talk upper Eagle Ford, there are a couple of different upper Eagle Ford intervals, just you guys know there is an upper Eagle Ford shale and there is upper Eagle Ford Marl, we’re really talking about the upper Eagle Ford marl which some might call the lower Austin Chalk, but it’s a Marl zone and it is very mapable. We think the bulk of the acreage is developable for that. How much that adds at this point? Or we think is potentially is developable, we need to get more well results, so before we can quantify too much. And frankly where we’re drilling right now in Lavaca County may or may not be the best part of it. The best maybe in DeWitt County.

My follow up is I guess is a Cana question but it is also kind of an activity question. 5,000 locations the 10 rigs, obviously I am missing something here. What proportion of those 5,000 locations falls into the category of the enhanced frac that you described obviously yourself. And how does this basically change capital allocation as you move forward in terms of [indiscernible] EBITDA level? I'll leave it there. Thanks.

: We may go higher than that, that’s a fair enough point Doug. Now this is a recent development with these improved completion designs that are really enhancing the Cana economics. So we are allocating rigs back out there. we obviously want to see, we’ve been drilling in what we think is some of the best part of the play not all of it is going to necessary quite as good as this but we think it’s still going to be very good. So we’re going to see where these results are, where they take us. It’s possible that we may continue to ramp the rigs up well beyond the 10 that I mentioned in my previous comments.

Thinking more about the overall portfolio Dave in terms of given the spend for the balance sheet. I mean is there -- how do you see acceleration generally across the portfolio, given where your inventory is building on it pretty much every play now.

: John may want to answer this too. But we obviously every year put together a long range plan where we try to balance our ability to execute on the portfolio and maintaining the strong balance sheet. And so this is part of the capital allocation process that we’re going through right now as we speak about where we want to end up on that. I think the good news is we’re in great financial shape after these transactions. John you want to add to that?

And then Doug one thing as Dave said, we are in great shape and we will have to see. We haven’t port our budget for next year, we are still going to be working on that. I think the really important thing is with the transformation that we have undertaken over the last while, we have put ourselves in the position to be able to live within cash flow and still grow at very, very competitive rates whether we choose to do that or not that’s another question. We may well, based on our outlook, based on industry conditions and basin conditions, choose to accelerate that in the future as well. And what’s important is we got the financial capability, in some of the areas or in all of our areas, we want to make sure that we don’t get ahead of the science, we don’t get ahead of the geology, we don’t get ahead of infrastructure, organizational capacity, availability of rigs and service and all of those kinds of things. So, other items that factor into the pace that we can accelerate at but I will say we are all really excited. We are in a position that we haven’t been in for a while of being able to significantly grow really high margin products and generate high levels of cash flow. So, we feel pretty good about where we are right now.

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

Wanted to follow-up on the CapEx points you were just discussing. Can you just talk to how you are thinking about CapEx for the remainder of the year and then since you did provide some preliminary oil growth expectations for 2015 within the context of your cash flow and your 2014 budget. How should we preliminarily think about 2015 levels of spending needed to achieve 20% plus oil growth?

: Well just for this -- this year, we haven’t changed our guidance for the year, Brian, I think we are on the street at 5 to 5.4 for our E&P capital spending and that’s assuming costs remain the same but we will see how that all sorts out. And we are halfway through the year and we so far spend about 47% of our total CapEx budget for the year, so we are on track for this year. When we talk about 20% growth in 2015, growth in our oil production 2015, we've done that based on our expectation for cash flow for next year. So, again as I said earlier whether we -- as we finish developing our budget and take all these other factors that I mentioned when I was replying to Doug, into account, where we actually ended up with a capital budget in 2015 remains to be seen but that 20% number is assuming living within cash flow.

And then shifting back to the Delaware, the acreage position that you have there in New Mexico and Texas probably puts you in a very good position to comment on the quality of the oil and the impact of condensate. As you continue to drill in various zones and various parts of the play, are you seeing any increased condensate coming out of your wells? Is that impacting your realizations and what are you expecting there going forward?

: This is Darryl. In Permian Basin, what we have seen pretty consistently is a quality of group between 38 and 42 degrees. The vast majority of that is less than five-tenths of a percent sulfur so it’s classified as sweet crude. There have been individual wells that we have drilled. We have seen the gravity go up as high as 45 to 46% which has not been consistent through all of our wells. There have been some industry players who have also seen gravity that high, depending on the volume from industry that comes out of that 45 to 46 degree gravity. It’s pretty well blended in the other crude out there that’s in the 36 to 40 degree, so we really don’t see at least in the foreseeable future that, we are going to have any condensate problems coming out of the Permian Basin.

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

Thank you. Dave, I wanted to see if you can elaborate on your plans to increase your rig count in Delaware from 12 to 20 and maybe you can maybe just opinion on where your technical understanding is of the play versus a year or two ago and just your confidence in executing a program of that size?

Yes, well, I think our technical understanding has increased pretty significantly as we have appraised across our entire acreage position that has now put us into a position now that we have a pretty good understanding of what the prospectivity is across our entire acreage position. There is always risk when you drill well, so it’s not an absolute but I would say our technical understanding because we have been appraising across the entire acreage position, certainly in the Bone Springs is there now. We still need to drill additional wells and we have a listed inventory in the Wolfcamp and there haven’t been many drill on the New Mexico side and the Wolfcamp, so that’s an area that still takes some additional maturing but there is no question that overall and in some of the other formations such as the Leonard obviously, we haven’t drilled that many wells. We are drilling our first one right now but the industry has. So we’ve got a pretty hand on what’s going on there. So, from a technical standpoint most areas are maturing, that is really a little bit less on the technical side is more just getting making sure we have several factors working together to execute and we’re confident we’re going to get there, the aim should be to make sure that we have a high quality rigs and services are available, we have the gas takeaway capacity, and we have the infrastructure in the field from just a pure manpower standpoint to manage this kind of rig capacity. And so we’re working through all those issues and we’re confident that’s going to allows to do 20 rigs sometime next year.

Okay, and just my follow up. John, what your longer term thoughts regarding the pipe development and the regulatory approval process on that project?

We filed the application for 105,000 barrels of project with BP about the end of last year. So, we’ve been going through the process and it’s moving along very well, we have some consultations that are with some groups that aren’t left but it’s moving along really well and it’s our expectations that we’ll get the regulatory approval for that project probably late this year or early in 2015. So, it’s moving along really well and of course we still have as you know we haven’t made the final things I mean decision on that yet but something it will have to do this well but it’s moving along and Pike is, that was an area that always appealing to us because it’s directly adjacent to Jackfish and Jackfish is in what looks to be the sweet spot of the oil sands for SAGD development. So this is a pretty good looking lease.

Quick follow up, given the Delaware Basin opportunity, Cana-Woodford, Rockies oil, how would Pike now compete for capital relative to your U.S. onshore growth potential?

: Yes, that’s a good question. It’s a project that has very, very different characteristics. So, if you just want to compare strictly on a rate of return basis, it doesn’t compete as well because, you are reporting some capital upfront, you get this long stream of cash flow over a longer period of time. So, they're very different projects, the good part of it is, very, very low geological risk, very low engineering risk, you got this flat production profile for 20 or 25 years and an extremely high cash flow stream that comes with that. So, it really -- the characteristics of it are quite different and we’ve always thought that having a portfolio that’s has -- that's balanced in some way not only between natural gas, natural gas liquids and oil, we kind of like that balance between light oil and heavy oil too because they trade very differently over time and because they have these different characteristics. So, those are all things that we have to take into consideration in making that decision, it’s kind of balancing the near term versus the longer term aspects of those two kinds of or two different plays.

Your next question comes from Subash Chandra with Jefferies, your line is open.

Yes, thanks for squeezing me in. Just a couple of questions I guess first on Pike again, the access pipeline, is that sized for Pike? Or does it have to go through additional expansion for Pike?

This is Darryl, and yes it is sized for Pike, actually sized for both Jackfish and Pike and it does have the ability with additional pump stations to increase capacity significantly, we currently have about 270,000 barrels a day of capacity on the blended stream and like I said with additional pump capacity we can increase that volume for that pipeline. So, all of those things have been taken into consideration. I might just add the access pipeline looping the 42 inch line was completed end of the second quarter early third quarter and we are now in the process of line filling that line so which should be operational towards the end of this year.

: So, those volumes that Darryl is saying that’s really much more than we -- I mean that expansion capability with an extra pumping is actually much more than we need for Jackfish and Pike.

Okay, so it’s in excess of those as well, okay. And then in Cana, the 10 rigs, is that -- are we still 6 to 8 operated and the balance non-op?

The 6 to 8, if we do the 6 to 8 operated we really set around 10 by the first of the year if we do the full 6 to 8 which we as I was explained to Doug Leggate, we may do that and we may do more, that would actually be -- get us above the 10 rigs if we do that given what [indiscernible] is doing. And there is -- financially will do that. We’re just staying by the first year-over-year around 10.

Okay, but combined op, non-op?

Yes, that’s right.

And any commentary just if you can refresh me on the status of the drilling carriers and where you sort of see the intercompany rig movements take place over the next six months?

Well, I will start off with the rig movements. There is not a lot of rig movement going on. We are as we described increasing our activity a little bit already in Cana and so we are dropping down activity a little bit in the mix for that. We will be adding a little bit in the powder as I described but overall not a large movement in rigs in the last half of this year. We will be ramping up as we go into 2015. Now on the carriers, on the Sinopec side, as of June 30th, there was about just over $500 million remaining of the $1.6 billion carry. On Sumitomo side, there is 345 million remaining of a 1.25 billion total drilling carry. Around the end of the year, we think we would be down to the point on the Sinopec side, where we will be about a little over 150 million left and just under 150 million left on the Sumitomo side that we will utilize in 2015.

: Well folks, I am showing the top of our here but before signing off let me leave you with a few key takeaways from today’s call. First, we have dramatically improved our portfolio in a short period of time. Devon emerges with a formidable portfolio that’s on track to deliver attractive high margin production growth for many years to come. As evidenced by our second quarter results, our pursuit of high margin production is significantly expanding our margins and profitability. And finally the commitment to our top strategic objective that you heard us talk about often, which is to optimize long-term growth and debt adjusted cash flow per share has never been stronger. As we deliver on our growth expectations we are poised to create significant value for our shareholders in the upcoming years. So, we look forward to talking with you again on our next call and thank you for joining us today.

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