Devon Energy Corp Executive Insights: NGL Pricing, Acreage Position

On Wednesday, Devon Energy Corp (NYSE:DVN) reported its first quarter earnings and discussed the following topics in its earnings conference call. Here’s what the C-suite revealed.

NGL Pricing

Jessica Chipman – Tudor, Pickering & Holt: Thank you for all the color on NGL pricing. I had one question related to that. At the Analyst Day, you showed Barnett returns at about 17%, assuming 2.50 gas, $100 oil and NGL realizations of 47% at WTI. Can you talk about how your returns are impacted by lower NGL realizations that we are seeing today, and is there any chance you would rethink your Barnett plans, until NGL realizations improve?

A Closer Look: Devon Energy Earnings Cheat Sheet>>

John Richels – President and CEO: Jessica, we have taken a look at it, and then, I guess a quick answer is, we won’t change our view, as long as the economics remain positive. We did just stress test those, actually subsequent to our Analyst Day, we stress tested both the Barnett and Cana, because they are both liquids rich gas projects, for our ongoing capital allocations, and of course, when we are doing that, probably goes without saying. What we are really looking at is, a program moving forward, and a drilling program moving forward, and that’s more dependent on 2013 prices than it is where we are today. But just to run some sensitivities, I will give you a few numbers here. At a $2 realized price, so let’s get back to what we are actually getting, rather than these benchmark prices. The $2 realized price, and about a $33 realized natural gas liquids price, and if you factor in the midstream uplift that we get, which of course, is integral to those operations, so we have to consider both of them. We see a high teens rate of return in the Barnett shale, and somewhere around the mid-20s rate of return in Cana, which in either case, is way above our cost to capital obviously. If you look at next year, and think about what the – by the way, we don’t think that $2 realized price is what we are going to see in 2013 and beyond, but we did that to get a sensitivity. If you look at 2013 and prices that are probably more realistic and take for example $3 realized price, now that would just about where the strip is today. I think the strip is about $3.50 or something, so a $3 realized price is probably pretty close; and again a $33 NGL price with the midstream uplift that gets you to about a 20% rate of return in the Barnett and close to 30% rate of return in Cana. So we’re still pretty comfortable with those kinds of rates of return, particularly with the scale that we have in those plays. But we’re constantly looking at that, because with our deep portfolio, we can move our funds around where we can make the most money for our shareholders and so we’re always watching that.

Jessica Chipman – Tudor, Pickering & Holt: Just a second question to you on capital spend, it looks like the run rate based on Q1 spend is actually lower than your total 2012 capital budget. Is there any chance you think that you may be able to keep CapEx below budgeted level?

David A. Hager – EVP, Exploration and Production: Well, as John says we are constantly looking at the results of our budget and it’s certainly possible, but I would point out that we’ve been assembling some large acreage positions that will hit principally in the second quarter. So we think, right now we’re still running about true to our forecast for capital.

Acreage Position

David Kistler – Simmons & Company: Following up real quickly on that acreage comment and tying it to your Analyst Day, where you indicated you’d like to increase your position in this line. Is it fair for us to assume that that’s where that capital is being deployed that Vince just mentioned, and any indications you can give us around price per acre in that play would very helpful?

John Richels – President and CEO: First, it’s not safe to assume while we’d like to increase our position in the mix, we have not disclosed where those incremental acreage acquisitions are and any place that we want to increase our acreage position we aren’t really willing to talk about specific transactions and the cost trends in that acreage.

David Kistler – Simmons & Company: Then just looking at Wolfcamp results on the (Abbott) 17H well, can you talk a little bit about cost and design and where that’s targeted over time?

David A. Hager – EVP, Exploration and Production: This is Dave Hager. This is – giving idea on cost and again this is the first well that we drilled over in our Wolfberry area, this is actually in the – what we call our Odessa South area of the Midland Basin, it’s really geographically if you want to know where that’s located, just in the far southeast corner of Ector County and that well looks like it’s going to cost somewhere around $5 million or so. It looks like we’re going to have probably on the order – and it’s very early – we have about 20 days or so, but we are estimating somewhere around 300 barrels net EUR on that, and we have in that particular well completed in the Wolfcamp B interval, that’s really where much of the activity has taken place with the industry that we have and back in our main core Wolfcamp shale, we have completed some in the Wolfcamp A, as well as some in the – we think the C and D zones also are prospective. But we played it conservative with this first well, that’s 80 miles away from our production state in the Wolfcamp B.

David Kistler – Simmons & Company: Any color on lateral length frac stages and where that cost could trend?

David A. Hager – EVP, Exploration and Production: I don’t have – I don’t have the number of frac stages sitting in front of me right now, but we completed that I believe very similarly to how we did our other Wolfcamp Shale well, so I’d think again, we’re still very much on a learning curve on our Wolfcamp shale wells. It was a 3800 foot horizontal on that particular well, but we’re still, I would have to lump that in with the rest of the Wolfcamp Shale. We’re still on a learning curve and we showed at the resource update how we’re continuing to improve on the cost side of it and we stated there we think the key is to get out as far laterally as we can, 7000 foot plus on the lateral length and so this is really encouraging results, I think given that this is only 3800 foot lateral and future wells with experience in this area may be haven’t be able to take out significantly further and get even better EURs.