Welcome to Devon Energy’s second 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 second quarter earnings call and webcast. Today’s call will follow our usual format. I’ll cover a couple of preliminary items, and then our president and CEO, John Richels, will comment on the quarter. Following that, Dave Hager, our chief operating officer, will provide the operations update, and then we’ll have a financial review by our CFO, Jeff Agosta. We’ll follow that up with a Q&A session. And I’ll point out that our executive chairman, Larry Nichols, as well as Darryl Smette, who is the head of marketing midstream and supply chain, are both with us today to join in the Q&A. We’ll conclude the call after one hour. During the call today, we’re going to update some of our forward-looking estimates based on the actual results that we’ve seen in the first half of the year our revised outlook for the second half of 2013, but we are not planning to issue a new 8K. We will, however, post any updated estimates that we provide during the call today on the guidance page of our website. If you go to our website, you can just click on the guidance link, look in the investor relations section, and all of our guidance is summarized there. All references today to our plans, forecasts, expectations, and estimates are forward-looking statements under US securities law and they are of course subject to a number of assumptions, risks, and uncertainties. Many of these are beyond our control. And I’d point out that these statements aren’t 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 and when we do that, we’re required to provide certain related disclosures. Those can be found on Devon’s website. Before I turn the call over to John, I’ll point out that both earnings and cash flow for the second quarter significantly beat Street estimates. Our non-GAAP earnings climbed to $1.21 per diluted share. That’s more than double the earnings we reported in the year ago period, and it exceeded the Wall Street consensus by about 30%. Cash flow climbed to $1.4 billion for the quarter, the highest level in the last six quarters, and that also comfortably beat Street expectations. Overall, from both an earnings and cash flow perspective, it was an excellent quarter for Devon. At this point, I’ll turn the call over to President and CEO John Richels.

Thank you, Vince, and good morning everyone. As Vince just mentioned, we had an outstanding second quarter. In addition to benefitting from the substantial improvement in realized prices during the quarter, we exceeded the top end of our production guidance. At the same time, our year to date cost metrics are tending towards the low end of the forecast range. This is all strong evidence of the successful execution of our business plan as we continue to grow our high margin oil production. Let me begin today by reviewing some of the highlights of the quarter. In the second quarter, we increased company-wide oil production 14% compared to the second quarter of 2012, and 4% compared to last quarter. This growth was driven entirely by high-margin light oil production from our U.S. assets, which increased a robust 36% year over year. With the success we’ve had in growing our oil production, we now expect liquids production to exceed 45% of total volumes by year end, and that’s up from just 30% just a few years ago. In the second quarter, total company-wide production from our North American asset base is at an all-time record, averaging 698,000 equivalent barrels per day. This exceeded the midpoint of our guidance by 3% and topped the upper end of our forecast range by 8,000 barrels per day. Based on the results of the first half of the year, we now expect our full year 2013 production to be near the top end of our guidance range for the year. Jeff will cover the production guidance in a little more detail later in the call. When you examine our operating results in greater detail, you’ll find that we had terrific execution across all of our core focus areas. The most notable growth in the second…

Thanks, John. Good morning everyone. Let’s begin with a quick recap of our second quarter capital expenditures. Exploration and development capital for the second quarter came in at $1.2 billion, bringing our total for the first half of 2013 to $2.7 billion. Based on our planned activity for the second half of 2013, we’re on track with our full year E&P capital guidance of $4.9 billion to $5.3 billion. As John mentioned, our teams delivered excellent execution in the second quarter, across our entire North American onshore portfolio. Let’s take a closer look at some of these high points. Starting in the Permian, our production averaged a record 76,000 barrels of oil equivalent per day in the second quarter. Looking specifically at our Permian oil production, it grew 32% year over year. Light oil now accounts for 60% of our Permian volumes. The execution of our Permian development program through the first half of the year has been outstanding, and we remain on track to drill more than 300 wells this year. Our Bone Springs horizontal program in the Delaware Basin is a key driver of our Permian oil growth. We currently have 12 operated rigs working in the play. In the second quarter, we brought 29 Bone Springs wells online, with average 30-day IP rates of 675 barrels of oil equivalent per day, of which more than 65% was light oil. These results are about 15% better than our type curve expectations. Our continued growing success in Eddy and [Lee] counties, combined with our ongoing geological evaluation, has once again allowed us to increase our inventory. As John mentioned, we are doubling our inventory for the second time this year to 1,400 Bone Springs locations. Given this success, our 2014 program has the potential to double our current year…

Thank you, Dave, and good morning everyone. Today I will take you through a brief review of the key drivers that shaped our second quarter results and where called for, provide updated guidance. Beginning with production, as John detailed earlier, our record-setting production averaged 698,000 barrels of oil equivalent per day. This was driven by growth in light oil production from the Permian Basin, coupled with the Mississippian and Woodford oil plays in north central Oklahoma. Total second quarter production exceeded the midpoint of our guidance range by nearly 3%, and topped the upper end of our forecasted range by 8,0000 barrels per day. Looking ahead to the third quarter, we expect to continue to demonstrate year over year growth in our oil volumes, with average daily oil production ranging from 165,000 to 170,000 barrels per day. This implies a year over year growth rate in the high teens. Driving this strong oil growth in the third quarter is an expected 40-plus percent increase in oil production from our U.S. operations, far surpassing the impact of higher post-payout royalty rates at Jackfish 1 and the planned turnaround at Jackfish 2 that Dave discussed earlier. Overall, on a BOE basis, after accounting for growth in NGLs and declines in natural gas, we expect production in the third quarter to range between 680,000 and 695,000 BOE per day. Due to the outperformance of our core development assets year to date, we are increasing our full year production target. This is in spite of selling noncore properties. We now expect our full year 2013 production to range from 250 million to 254 million BOE, an increase in the midpoint of our full year forecast of 4 million barrels. Breaking down our 2013 outlook by product, high margin oil production is the most significant…

Operator, we’re ready for the first question.

Our first question in queue comes from the line of Arun Jayaram with Credit Suisse. A line is open for you now.

Jeff, kudos on the repatriation. I know that’s been a lot of effort for you and your teams, so congrats on that. My first question is regarding the Woodford play, Dave. Understanding it’s early in this play, but I was wondering if you could just comment a little bit on the consistency of the well results thus far, perhaps the initial rates of return versus the Mississippian program, and bigger picture, what do you think this could do for Devon if you can prove this position out.

Well, we’re pretty excited about this opportunity overall, because I think by the nature of being a shale play, and the fact that it is a source rock for the vast majority of the Mississippian play, by the nature of it, shales tend to be more consistent in nature, and so that has led to greater consistency in well results already. And we’re just at the beginning stages of really characterizing the overall play. So we are seeing more consistent results, there’s obviously some variability. Some of the keys we’re looking for, where we can enhance the permeability through fracturing and you see some variability depending on the thickness of the reservoir, but overall, it is a consistent play that produces strong economic results. You can see where we’re using, essentially for right now, the same type curve as we’re using for the Mississippian, but it’s going to be a little bit lower well costs. So that’s, obviously, even going to enhance the economics a little bit more. And as I highlighted, we’re very confident. We derisked 100,000 acres, and we see the potential for up to 400,000 acres of Woodford potential across our 650,000 acre position in the Miss trend. So it’s an exciting play. If it works out to scale, you can do the math, but it can add a lot to our light oil story.

And do you have the same water issues that you have in the Miss Lime?

No, you don’t have near the water issues you have in the Miss Lime.

John, one for you. I wanted to ask you, just around strategic alternatives and potential strategic alternatives beyond the MLP, thoughts on other things such as Canada, thinking about strategic alternatives around Canada to unlock some of the value there of your oil sands position.

Without getting into any of the specifics, we’re always looking at ways that we can bring that value forward, and I think our history proves that we’re not afraid of doing that and making bold moves. However, a lot of things that we talk about and reflect on from the outside don’t necessarily add long term value. And so we’re very conscious about that, and we’re looking at any opportunities available to us. We’ve always said we’re always considering how to bring value forward, and we’re not leaving any stone unturned in that analysis. But we’re only going to do the things that add long term value and not take action simply for action’s sake.

Next in queue we have Doug Leggate with Bank of America. A line is open for you now.

Dave, first to you, perhaps. The Mississippi Lime and the Woodford, are we now basically seeing the Woodford as a primary target for your acreage there? And could you talk about what the implications are in terms of development plan, rig count activity, or rather, I guess, well activity, and ultimately how you might change capital allocation associated with this play.

We like both of them. I think that’s the key. We like the Woodford and we like the Miss Lime. This is not negative on the Miss Lime, it’s just we have additional potential here in the Woodford. I think that’s really the key. The Woodford is a little bit deeper, and it has some of these additional qualities that we described of being a shale with probably more consistent results, a little bit easier to drill, a little lower well costs, all of which are very positive for that. And in addition to being deeper, when you drill a Woodford well, you hold all rights above that. And so we’re going to have a tendency to drill more Woodford wells here in the short term to make sure that we get our acreage secured through the Woodford. But ultimately, it’s going to take the rest of this year, I think. That’s what I’ve been trying to say consistently, that it’s going to take the rest of this year to really get a clear understanding of what the full potential is on both the Woodford and our Miss acreage, but it’s starting to emerge pretty positive, I can tell you, and it looks like we certainly have a strong leg to our next oil growth within Devon. And so I like where we are, bottom line. It’s just nice to have an additional formation such as the Woodford to really bolster that growth.

I don’t know if you wanted to take my follow up, but it’s related to the carries, clearly the success in the Powder, the Permian, and the Miss. How are you allocating, and what’s the remaining capital carry you have in the two joint ventures that you have with Sumitomo and Sinopec?

We should benefit to the tune of over $1 billion this year and a billion next year.

And that’s the two JVs combined.

Yeah, the two combined. But as far as specific to the Rockies and the Miss, that’s got to be upwards of $700 million to $800 million per year.

Your next question in queue comes from the line of Joseph Allman with JPMorgan. Their line is open for you now.

On the Miss Lime, production increased by about 2,200 barrels per day from the first quarter to the second quarter. And you drilled 44 wells in the second quarter, 34 in the first quarter. These are gross wells. So why is the production not ramping up faster there?

It’s important to remember that so far we’ve only brought a total of 64 wells online in the Miss, total of about 90 or so for the combined Miss and Woodford. And so we have currently, as we speak, we’re building out our infrastructure and we’ll be continuing to build out that infrastructure throughout the third and fourth quarter. So as we get the infrastructure built out, as we complete these additional wells, then we’re going to see the ramp up in production even further.

And the Miss Woodford, I think your press release indicated that, so you exited the June quarter at 7,000 barrels a day, you exited the March quarter somewhere in the neighborhood of 3,500 barrels a day, you brought on 36 wells in the second quarter, and you mentioned the 10, that averaged 840 or so BOE per day. So that would imply that the other 26 wells actually had a very low rate. So I was just working the math. I’m just trying to understand what the average of those other 26 was.

They’re varied. And it’s important to remember, and I’ll go back to what I said previously, we are still in the testing phase of this. We are landing in various zones within the Miss, and we’re experimenting throughout our acreage. An additional point I need to make is the working interest in a number of these wells. We’re talking about gross wells. And so the working interest in a number of these wells is very low. So you really can’t do the math I think you’re trying to do, to figure out the rate. But we are seeing a lot of variability right now, and we’ll continue to see that as we evaluate our acreage here throughout the rest of this year. And then we will really be focusing in on what we think are the best parts of the play.

Dave, could you give us the average working interest for the Miss Lime and for the Woodford? I thought it was actually pretty high, with about a 20% royalty.

I think it’s averaging about 30% or so.

30% working interest average?

Yeah. I might also mention, just to follow up on some of these wells too, we can produce for about 30 days and then we can’t produce them any further, because there are the flaring restrictions we have. So we’ve actually had to shut in some of these wells. So there’s a lot of complicating factors that factor in to why it’s taken a while to ramp. Once we have our facilities in place, that we’re talking about building out here in the second half of the year, that won’t be an issue anymore.

And John, just on the strategic alternatives, as a follow up, from the language it sounds as if that process has slowed down somewhat internally. I think you were looking at options for the midstream business, and you already announced those, but it sounded previously, I think you said everything was on the table. Now it sounds as if that process has slowed down internally. Is that a proper interpretation?

I don’t think it’s slowed down. I said everything’s on the table, and everything’s still on the table. If we can see opportunities that create long term value and that make sense and are accretive, then we’ll look at them. But I just wanted to make the point that just undertaking activity for activity’s sake doesn’t make sense unless we think it’s really something that’s going to add some value to the stocks. I wouldn’t say that we’ve changed our view on that.

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

Shifting to the Permian, can you talk in more detail about what’s driven the increase in your Bone Springs locations? How much of that is due to incremental Bone Springs zones working, versus you’ve tested a wider acreage, versus spacing, versus EURs, or anything else?

Let me give you a little bit of an idea for what is going on here. It’s primarily, as we test additional acreage. That’s the answer. To give you a little bit of color on the details on this, when you look at the logs of this first and second Bone Springs, they are what we like to typically call railroad tracks, which really means we see very little indication of a deflection of the SP curve, or the resistivity curve, which you typically see in productive formations. And so what this really means is these are pretty fine-grained reservoirs, and so you can’t just look at a log and say for certain that these wells are going to be productive. You have to actually go in and test new areas, and then you find out, oh, it’s working. And so based on that fact, then you step out further, and you step out further, and you say that area’s working too. So that’s what we’re really doing. We’re stepping out and testing new areas, because it’s just not obvious from the well data that it’s really going to be productive. And what we’re finding is that these areas that just don’t look that impressive by traditional log analysis techniques, when we go out and test them, they’re working really well.

And my follow up goes back to some of the earlier questions. Is the emergence of this Woodford oil opportunity in the Mississippi Lime area meaningful enough where it reduces your appetite for considering or adding oil resource via acquisition from some new play elsewhere?

Well, we’re always going to be very disciplined, I think, if we’re looking at any acquisitions. And so we’re going to, I think, continue to look to see if there are any meaningful, but obviously we haven’t made any deals yet, because we’re being very disciplined from a value standpoint. I think it’s always in our best interest to look, but we’re certainly excited that this adds a lot of strength to our internal oil growth story as well. So I wouldn’t say we’re going to stop looking. We always see if there’s something meaningful out there, but it certainly gives us a lot more confidence on our internal story.

Next in queue we have [Sue Lin] from Robert W. Baird. A line is open for you now. [Sue Lin] - Robert W. Baird: A quick clarification question about Woodford oil. Is this part of your Sumitomo JV? And also, what is your planned activity for developing this play in ’13 and ’14? Could you use part of the [drill carry] from the JV?

We have 650,000 acres throughout the Mississippian trend. About 150,000 or so of that acreage is within the joint venture, not with Sumitomo, but with Sinopec. And where we’re drilling the bulk of our wells right now is on that acreage that’s within the Sinopec JV, and that has the bulk of the derisked acreage for the Woodford right now. And we see additional prospectivity outside of the joint venture acreage with Sinopec that we’re going to be derisking here throughout the remainder of ’13 and ’14. So right now, as part of the Sinopec JV, and as part of the overall plan, as part of the 350 wells we talked about that we’ll be drilling overall in the play, and it’s within the budget that we’re working with with Sinopec and the JV. [Sue Lin] - Robert W. Baird: And then the second question is regarding Powder River Basin. Given that the overall results there seem to be pretty good on Parkman and Turner, and you also have 600 risked locations, I was just wondering is this going to become a core area for you guys? Are there any permitting issues to develop this play here?

Well, we’re excited with the results we have. And we’re looking at ways to increase our well activity as we move into 2014. It is BLM land for the most part. Not entirely, but for the most part. There’s a longer permitting process involved in that, so we need to get ahead of the curve as far as permits. We do see the scope for increasing rig activity in 2014. Is it going to grow to the size of the potential that we see in the Miss or the Permian? No, I don’t think so. But is it still going to be a meaningful part of the growth story? Yeah, it can be a significant contributor, I think. Still, it’s probably not going to be of the scale of the Permian and the Miss. [Sue Lin] - Robert W. Baird: And then my last question is do you have any update for us on Cline, in the Permian?

Yeah, on the Cline, we’ve decreased our rig activity right now. We’ve seen a lot of variability on the Cline. And we certainly have our concerns about the Cline, but we’re also getting additional 3D in there. We’re looking at our completion techniques. For the short term, we’ve decreased down to two rigs in there, both of which are going to be doing what I call mini developments in Sterling County, seeing how low we can get the well costs to have economic developments there. In the meantime, we’re studying the well results we have to date. We’re getting 3D. And as I said, the results have been pretty mixed so far. So we need to do some studying here before we go back out there with a significant program.

Your next question comes from John Herrlin with Société Générale. Their line is open for you now. John Herrlin - Société Générale Americas Securities : A couple for Dave. With the Woodford Mississippian trend that you discussed, you said that you had variable thickness in the Woodford Shale. How variable is it aerially, when you look at all this acreage? Or is it relatively uniform?

It’s reasonably variable. We have some areas we’re not including in our prospective acreage at all, because it’s not present. And so we’ve seen positive well results, down to as low as 40 to 50 feet of Woodford shale. We’ve seen very good well results, and it’s up to 150 feet thick in other areas. So there is some variability across the play. There’s no question about it. But again, we’ve had positive results down to 40 to 50 feet, and so that’s why we see a lot of it as being prospective. John Herrlin - Société Générale Americas Securities : When do you think you’ll an HBP mode in terms of capturing all the acreage? This year?

We won’t have it all captured this year. It will take on into 2014, particularly to the acreage to the north. The bulk of the acreage within the joint venture area will get HBP this year, but it will be 2014 to really do the acreage to the north. John Herrlin - Société Générale Americas Securities : Next one from me is on the Permian. Have you hit a stage where you’re in a pad mode yet? You’ve talked about your drilling times improving.

Oh yeah, we’re doing pad drilling throughout the Bone Springs, throughout the Wolfcamp shale. We have been for some time. And that’s frankly why some of the ramp up of production has been pretty inconsistent, I guess you’d say. But to give you an idea, though, just to fortify our production growth in the second half of the year, to give you one example here, in our Wolfcamp shale area, we fracked about 25 wells in July. They’re coming on here in August. We’re going to frack another 25 wells in August. They’ll come on in September. And so that’s what’s really the cause of the nature of pad drilling that the growth has been a little bit lumpy. But now that we’re getting all these wells drilled, completed, and on production, that’s what gives us the confidence. We’re going to have to kind of ramp up what we’re forecasting for the remainder of 2013. We’re also pad drilling in Bone Springs. Same issue there. John Herrlin - Société Générale Americas Securities : Given the results in Bone Springs wells, are you going to increase your EURs there?

They’re running at about 15% above the type curve right now. I don’t know, I’ll have to talk to the guys and see if they feel confident in doing it all the way. You understood the issue I talked about before. They’ve got to convince themselves those railroad track looking logs are really going to deliver even more. So we’ll see if they can get that confidence. But we’re getting outstanding results.

Next in queue we have Rehan Rashid with FBR. Their line is open for you now.

Just a quick question on Jackfish 2. Once we have the turnaround and the incremental pad in, what should we think about as the run rate?

We’re probably going to get an incremental on the order of about 8,000 barrels a day or so from the next pad, so once we’re fully back ramped up, I’d say 30,000 to 31,000 barrels a day, somewhere in that order.

And this should be by what, middle of next year?

Yeah, somewhere around there.

And just broadly speaking, thoughts around further exploration efforts going on within the enterprise, some broad thoughts on that front? What should we be looking forward to?

Well, we’re always out there looking, and we have a lot of ideas internally. Frankly, this has been a year where we had captured a lot of acreage, and we felt it was the year to evaluate that acreage. And given the success that we’re having on that acreage right now, I think it’s an open question as to how much additional acreage we need to add. Because we’ve got a lot of growth that we’re identifying right now from the acreage we’ve already captured. So if we see some that we think are truly outstanding, we may go out and try to capture those, but we’ve got a lot of growth already from what we have captured.

You last question in queue comes from the line of Charles Meade with Johnson Rice. Their line is open for you now.

I was wondering if we could turn to the Midland Basin Wolfcamp, and those look like some pretty good results that you have there, but I’m curious, I know that at least one of those two Ector wells you did in 2012 was a relatively short lateral. I want to say it was around 3,000 feet. And so I wondered if you could add some detail, first on what your lateral lengths were on these wells that you reported with this quarter. And second, if you could give a breakdown of the 250,000 net acres that you have prospective for the Wolfcamp, how much of that is Delaware and how much of that is Midland.

On the lateral lengths for the wells in Ector County, we’re currently drilling those about 5,000 foot laterals. Not quite as long as the ones we were doing in the southern Midland Basin. The breakdown of the Wolfcamp shale acreage that we have, it’s about 140,000 acres or so that we think is prospective in the Delaware Basin. Then we have about 65,000 acres or so, I think, perspective down in the southern Midland Basin. And then the rest of it is up in Ector County, and then some other smaller, scattered acreage.

John, do you have any closing remarks?

Just want to summarize. Our annual production is going to be at the top end of our guidance, with our U.S. light oil production up 36% year over year. Really importantly, too, year to date cash costs are at the bottom end of the guidance, and our capital expenditures remain comfortably within our original guidance. We’re going to continue to expand our high margin light oil drilling inventory in the Permian, and we’re very excited about the new Woodford oil shale play that David’s discussed a lot today. So was we move forward, we’re going to continue to be disciplined with our capital, we’re going to continue to preserve our financial flexibility, we’re going to continue to pursue our top strategic objective of maintaining long term growth and cash flow per debt-adjusted share. So thank you very much for joining us today. And with that, I guess we’re done.