德文能源 (DVN) 2015 Q1 法說會逐字稿

Welcome to Devon Energy's first-quarter 2015 earnings conference call.

(Operator Instructions)

This call is being recorded.

At this time, I'd like to turn the call over to Mr. Howard Thill, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you, John, and I, too, would like to welcome everyone to our first-quarter 2015 analyst-investor call.

Also on the call today with me are John Richels, President and Chief Executive Officer; Dave Hagar, Chief Operating Officer; and Tom Mitchell, Executive Vice President and Chief Financial Officer, along with a few other members of our senior management team.

If you haven't had a chance to listen to the management commentary, you can find that, along with the associated slides and our new operation report, at DevonEnergy.com. Additionally, we have included our forward-looking guidance in our earnings release. I hope you've had a chance to review all these documents, as today's call will largely consist of questions and answers.

Finally, I'll remind you that comments and answers to questions on this call will contain plans, forecasts, expectations and estimates which are forward-looking statements under US securities law. These comments and answers are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control.

These statements are not guarantees of future performance. See our 2014 Form 10-K for a review of risk statements related to our business and any potential forward-looking statements.

And with that, I'll turn the call over to our President and CEO, John Richels.

Thank you, Howard, and good morning, everyone. The first quarter was an outstanding one for Devon, and arguably one of the best, from an operations perspective, in the Company's 40-plus year history.

Before we jump into Q&A, I'd like to highlight just a few key messages that I hope you'll take away from our earnings materials. First, our premier asset portfolio is really hitting on all cylinders. We're seeing significant operational improvements across the portfolio, with improving type curves and increasing inventory. And we're achieving meaningful capital and operating cost efficiencies.

The strong operational momentum translated into topnotch first-quarter performance. We exceeded our production guidance for the third consecutive quarter. We did a great job of accelerating cost savings across our portfolio, with field level operating costs coming in well-below our guidance. We expect this level of excellence to continue in upcoming quarters. As a result, we have significantly raised our 2015 production outlook, while at the same time, reducing our full-year capital and LOE guidance by more than $400 million in aggregate.

And finally, we have a terrific balance sheet that continues to get better. When you combine the additional cash flow from our improved production outlook, our lower cost guidance and the recent EnLink-related sale proceeds, we've enhanced our cash flow outlook by over $1 billion in just a few months. So, in summary, our focused asset portfolio is generating differentiating results and returns for shareholders.

As many of you know, this will be my last quarterly call as CEO, with my planned retirement at the end of July. And I'm confident in saying that Devon has never been in better shape than it is today. We have a great set of assets. We have a very capable and experienced management team, and a rock-solid balance sheet. These winning qualities clearly offer investors a unique opportunity in the E&P space, and I firmly believe that Devon's best days are still ahead.

So thanks again for joining us today. And with that, I'll turn the call back to Howard for Q&A.

Thanks, John.

To make sure that we have enough time to take as many calls as possible, we'd ask that you limit yourself to one question, with associated follow-ups to that question. You may re-prompt to ask additional questions as time permits.

So John, with that, if you'll queue up the calls and questions, we'll go from there. Thank you.

(Operator Instructions)

Our first question comes from the line of Evan Calio from Morgan Stanley.

Good morning, guys, and great results today. A lot of new details, so let me jump into a more detailed question here. You introduced a Meramec type curve based upon the initial 12 wells you participated in. If I look at the map, it looks like your acreage includes the oiler up-dip, and the gas, you're down dip sections. Is the type curve representative of a blend, or can you discuss how we should interpret that?

Hi, Evan, it's Dave Hager. This is based more really on the results that we have to date, which is more in the oiler up-dip part of the play. We are going to be evaluating some as we move further down to the gassier part of the play. But the type curve you've seen is so far based on our results. We're seeing the 12 wells you talked about, as well as about 20 industry wells in the area.

And that's where your activity will be focused for the balance of 2015?

The bulk of the activity is going to be focused in the oiler up-dip part of the play. I think we're going to draw a handful of wells down to evaluate a little further down-dip. But the bulk of it is going to be in the oilier part. That's the best economics at this point.

That's great. If I could slip just one more in. I know your DeWitt County Eagle Ford are performing -- I think it's about 25% over the curve, that you lifted just one quarter ago. Is that a function of coring up enhanced completions? Can you help to parse through that to understand the broader application on your locations?

Well, the two big things I would say are really around the enhanced completions that we're doing, and then really the production optimization techniques that we're using. And so both of those we're very proud of. We think we are adding significant value to this asset with our contribution to the completion design, as well as the production enhancement techniques that we're using -- coiled tubing clean-outs, automation, choke management, et cetera. So the field is just performing outstanding, but those are the two big drivers.

Great. Great results, guys.

Our next question comes from the line of Arun Jayaram from Credit Suisse.

Good morning, gentlemen. I was wondering if you guys could comment a little bit more on the Bone Spring, and talk about the economic returns that you're seeing in the basin area or location versus slope? I believe the drilling costs are cheaper on the slope. But just wondering if you could comment on the relative returns, and where the program is going to be focused in 2015?

This is Dave again. The bulk of the program is going to be based in the basin part of the play. We have 10 of our 13 rigs working in the basin part right now. We get good economic returns in both parts of the play, I want to emphasize that. They're just a little bit different. The slope is more a channelized deposition environment. It is more normally pressured. The well costs tend to be lower. Whereas, you move down in the basin, it's a little bit deeper. It's more over-pressured.

And we're seeing some benefit from these enhanced higher-sand concentrations up on the slope, but we really see the greatest improvement down in the basin part of the play. That's where two-thirds of our opportunities lie.

But I don't want to discount the slope part of it either. It's a good economic play. It's just a little bit different, it's a little lower cost and a little bit lower rate than the basin part of the play. So that the bulk of it is going to be concentrated down in the basin part, not only in the Bone Spring, the lower part of Bone Spring, but I'm sure you noted, also the A sand] wells that we had. We talked about a second well in there. We're really encouraged by the results we're seeing at this A sand, or upper sand, in the second Bone Spring. Tony, do you want to add anything to that?

You covered it really well, Dave. Arun, I'd just remind you that we really started a lot of our activity on the slope initially, and then moved into the basin. When you go back and look at the results that we've had on the slope, probably about a third of those results have been for the type curve we just announced for the basin. We have a lot of upside on the slope-type activity, and we think as we de-risk with those three wells, we'll set ourselves up for continued development there. So we feel very positive about going back into the slope with more development-type work.

It sounds like from your ops report, you could see potential for the inventory to increase a lot in the Bone Spring. My follow-up is just regarding the Eagle Ford. You guys talked about maybe in Q2 being a little bit facilities-constrained. Could you just talk about steps that you have underway to relieve some of that midstream, called bottleneck, or what not? And when will you have more room to continue the strong growth you've had?

Okay. I'll have Darryl Smette talk about this.

There's a number of things that we're working on with our midstream provider and with our partner out there in order to increase the capacity. A lot of that has to do with operating efficiencies. That includes getting more up-time on the stabilizer that's out there. I know currently that stabilizer has a nameplate capacity of around 170,000 barrels a day. Historically, that has been running about 140,000, 145,000, so we're working with our midstream provider to see if we can't increase that operational time.

We're looking at additional compression in certain areas. We're also looking at, on the truck side of the equation, putting in delivery stations that are closer to the locations, so we can increase our truck activity, so they don't have to drive so far. There's just a number of things from an operational perspective that we're looking at. We also have had discussions with our midstream provider and with others about providing enhanced capacity out of the area. And those discussions continue on, but nothing has been finalized.

Thank you very much.

Our next question comes from the line of Scott Hanold from RBC Capital Markets.

Congratulations on the quarter, and good luck, John, on your retirement.

Thank you, Scott.

You bet. My question is a quick follow-up on the Permian Basin. You take a look at that -- increased to potentially 11,000 gross un-risked locations, which is obviously meaningfully higher. When you look at that, in the various formations you've identified, is that -- should I assume that it's fairly pro-rated to what you already have out there on a risk basis? Or is there more upside in specific formations like the Bone Spring?

Well, let's talk to the -- there's several areas we see upside. We see significant upside in the Bone Spring as we do these down-spacing pilots we highlighted in the operations report. We also see upside in the Bone Spring from this upper sand, this A sand that I've been talking about, where we're talking about the first two wells. You combine those two, there is significant potential inventory expansion because of those two factors.

Additionally, in the 5,000 risk that we've been talking about historically, compared to the 11,000 un-risk number, we haven't been including anything for the Wolfcamp. We see probably four members of the Wolfcamp that are potentially prospective across Lee and Eddy Counties, so that's a big driver also. Then to a lesser degree, we do see some upside on the Leonard and the Delaware sands. But the two big drivers, I would say, would be the increase of potential in the Bone Spring -- which again, we think is the most economic opportunity thus far in the play -- and then in the Wolfcamp.

Okay, appreciate that. And in the Eagle Ford, you did touch on obviously the upper Eagle Ford is looking encouraging. And, Dave, what is your view on the play right now, based on what you've recently seen? If you do get more excited, is there more acreage acquisition opportunities targeting that trend?

Well, we probably don't talk too much about acreage acquisition opportunities. There may be some out there, but I'm not going to get into detail on that too much. I would say from our mapping, we see the thickest part of this really being in DeWitt County, over our existing acreage.

We're very encouraged by what we're seeing so far. We've had encouraging results to the northeast in Lavaca County. And as we're moving into DeWitt County, we're seeing better well results; we're also learning better how to complete these wells. I think you've seen, even as you go way to the southwest beyond our DeWitt County acreage, you've seen another operator talk about encouraging results -- I think they call it the Austin Chalk. But it's really the same marel formation as what we are talking about here.

So we're very encouraged with the results thus far. And we still don't think we've necessarily drilled the best part of it. So we think it is going to be a very economic play. It's a little different. It's not necessarily a shale; it's more of a marel, which is more like a limestone, really. So your spacing may be a little bit wider. We don't know for sure. We're thinking maybe 160, but it's too early to say for sure. But we're very encouraged by what we've seen so far.

Okay. The way I'm hearing your comments, you are increasingly becoming more optimistic at this point?

Absolutely.

Thank you.

Our next question comes from the line of Doug Leggett from Bank of America Merrill Lynch.

Thanks, good morning, everybody. And let me join and echo my congratulations. And Dave, we're looking forward to seeing your impact -- more so than you've already done already.

A couple of questions, if I may. Going back to the Eagle Ford, BHP, as operator, has raised some concern that they wanted to slow things down a little bit. I'm guessing that the infrastructure is going to do that for them. But my question really is, how do you change your capital allocation in light of the [four undeveloped] un-risked locations in the upper Eagle Ford? You've obviously got much bigger opportunities there than your partner. That's my first question. I've got a second in the Permian, please.

Well, what we're trying to do right now, overall, Doug, is to match our activity with the availability of capacity, with our infrastructure. And now we're trying to expand that capacity, and Darryl highlighted that. If you look at it, at the end of Q1, we had about 130 wells that were currently uncompleted. So we have an inventory to work through.

We are staying active with drilling in the area. We have decreased the rig count a little bit, but we're getting also more wells -- we're getting increased efficiency, so we're getting more wells out of a slightly lower rig count. So we have plenty of wells to be completed. That's not the limiting factor. The limiting factor at this point is just solving some of these infrastructure issues, which we're confident we're going to be able to do.

We are, so far, concentrating the bulk of our activity in the lower Eagle Ford. But we're talking to BHP about the upper Eagle Ford, and plan to do some upper Eagle Ford tests as we move into the heart of the play. Which we think would be over the acreage we have with BHP in DeWitt County.

I appreciate that, thank you. My follow-up in the Permian -- obviously there's more than potential double on your inventory. I'm just curious if, on the down-spacing in the Bone Spring, I'm curious -- does that upside include the delineation or testing on the Wolfcamp? Or is that still ahead of us? And if so, how do you -- again, how does the relative capital allocation go in your [other] position? And I'll leave it there.

When we look at the table that we've referenced in some of our previous disclosures, Doug, we've included [no] locations for the Wolfcamp. And we've been focused on second Bone Springs -- again, because the returns are higher in that particular pay horizon than others. But we still have a lot of industry activity in and around our position in the Wolfcamp.

So we're optimistic. We're building out technical plans for a rig line right now in the Wolfcamp. And we'll probably drill out of the 150 gross wells that we'll drill on the Delaware. About half a dozen of those will be in the Wolfcamp this year, and another half a dozen will be in the Leonard. But the focus, again, continues to be the second Bone Spring, just because we're trying to maximize returns in this environment.

Just to be clear, that greater than 11,000 mentioned in the ops report -- is there any Wolfcamp in there, or no?

There is on the gross expected locations of 11,000. There's not in the net risk cap that we've disclosed.

Got it, all right, thank you.

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

Yes, good morning, gentlemen. And congratulations also from me to you, John. If I could just bang a little bit more on the Bone Springs results, because they're really so tantalizing. Dave, if I remember, about a year ago, I think, when you guys were expanding -- one of the many times you expanded your inventory in the Bone Springs. At one point, you described the logs out here as just like railroad tracks -- it's hard to see what makes one zone different from the other.

And as I'm looking at this now, can you give a bit of a narrative on why it is that you're looking at the upper now, and what's appealing to you? And that would also go for the third Bone Springs, which you're going to do in one of your pilots. What led you to that, and what could be in the future?

I remember giving that description. I think the short answer is, you have to test these wells, really, to know how successful you are going to be. And that's what -- we decided to do some tests in the upper Bone Spring, and we're continuing to appraise other areas. But it does take testing to really understand just how good they are. So Tony, you want to expand on that?

I sure will. Charles, I think the technical guys are doing a lot better job now of calibrating all the surface data that we have. And of course, we're getting a lot more control points as we continue to test. We're looking at micro seismic results, and we're trying to understand what kind of stimulator rock bottom that we contact when we do our frac work there.

I think what we're generally seeing is that, while we're landing and spending most of our concentrated energy in the lower portion of the second Bone Springs, we know we're contacting a little bit upward into the middle. But we haven't seen evidence that we're contacting into the very upper portion of the second Bone.

So it's really just -- as we do in a lot of these type of plays, where the rock is not that favorable, or certainly not that obvious from first inspection, it takes a little bit more science to uncover that. And a lot of the subsurface data points just gives us a little bit more information to lead our developments down the road.

That's helpful. And then following up on the type curve adjustment, you bumped the IPs by about 60%. But on your operations report, the graph right above there says your cume through 180 days is also up 60%. And so it looks like that's not just an IP effect, but it's a sustained effect that you're seeing -- sustained production uplift. If I put those two pieces together, it looks like the EUR is -- maybe this is what you mean by the error -- but of EUR of 600,000 Boe really looks to me like that's going to go higher.

That is an increase, Charles, from -- if you go back a couple quarters, we said 450,000 Boe-plus. I made the flippant comment it could have been plus-plus-plus, if I remember right. So now we are saying 600,000 Boe in the basin.

And I think what the comment that Tony also made earlier -- I hope you caught that -- is about a third of the wells we're growing up in the slope are following the basin curve. We haven't increased it on the slope yet, but we have some evidence so far that we may have some better results coming in the future on the slope as well. But that is an increase from -- we've never came out with that 600,000 Boe number, specifically, before, we just said 450,000-plus Boe.

Okay. Thank you, Dave.

And there may be some upside in the basin from that also, frankly. We'll see how it goes.

Right. Thank you.

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research.

Good morning. I'd like to also begin by saying happy trails to John.

Thank, Jeff.

You've certainly left a much better Company than it was when you took over. I wanted to actually talk about the Powder River Basin Parkman results. Because I thought they were really quite impressive, particularly since some peers have retreated from the area during the downturn. I just wanted to ask a couple of things. If you want to count it as two questions, that's fine with me.

What percentage of your focus area can support the 9,600-foot laterals that you highlighted? Will you drill shorter laterals where the geometry of the acreage requires it? And finally, will you take your Parkman approach to the Turner or to the Frontier, and see if they can show similar uplift?

Thanks for noticing the results, Jeff. I think what we spent is -- if you go back in 2013, early portion of 2014, we spent a lot of our capital and our efforts really delineating a very large, broad area there in the Powder, as you know. We have centered in on a couple of what we call sweet spots in the Parkman and in the Turner. The work that you're seeing now is us being able to confirm repeated high-return-type work in those sweet spots.

Most of that has been in the Parkman. We find that there's a great uplift with the extended laterals, and we will continue to do that when possible. We also find that we're starting to bring on some extended Turner wells right now. So we'll have a little bit better knowledge what that will look like. But I would expect the Turner to follow the Parkman results.

In terms of the total inventory, I think we commented that we have about 1,000 locations in the Powder. We picked up a little bit more acreage in Q1, and supported our tier one position in the Parkman and Turner. That adds to that location counts on a normal lateral basis. That location count goes up a few hundred, if not 300 more locations. But really, it goes up to 1,450, as I see in the operations report now.

We're trying to reduce that by drilling extended-reach wells. And we think if we can do that and core-up our position, we can drop that to about 800, and see the results that you just saw this last quarter. So we're very excited about the Powder position right now.

Okay, thanks very much. I appreciate it.

Your next question comes from the line of Ryan Todd with Deutsche Bank.

Great, thanks. Good morning, gentlemen. If I could follow up with a couple of questions on capital allocation. One, in the near-term, in 2015, if limitations persisted from the second quarter on, in terms of the debottlenecking in the Eagle Ford, what's your ability to deploy capital elsewhere in the portfolio? Can you make up the difference by accelerating activity in the Permian or the Anadarko Basin?

Well, we don't really see the limitations that we're seeing in the Eagle Ford, at this point, are really going to change our capital requirements there on a very significant level at all. So it's a hypothetical question, I guess you'd say, because we just don't see that to be a limiting factor.

Obviously in the future -- I'll expand your question -- longer-term, we absolutely plan to increase our rig count in the Permian, in the Delaware Basin, because we are expanding the inventory so much. We don't see that so much as a 2015 event at this point. We're balancing our cash flows with our returns and the available infrastructure, and the other limitations, permits, et cetera, that we have in the Delaware Basin.

But longer-term, we absolutely plan to expand our activity in the Delaware Basin. And most likely, in other places, such as up in the Powder River Basin, as well. We have scope eventually, as prices improve, to deploy more capital also in the Cana-Woodford area. So we have a lot of opportunities in the inventory. But we don't see a significant change to where we're spending the money in 2015.

Great. And that segues into the discussion of 2016 and the allocation of capital. Can you talk a little bit about moving pieces in the portfolio? In the case of a flat year-on-year CapEx environment, how much spend do you have rolling off year on year from 2015 to 2016, in areas like the oil sands or other places that would allow for incremental dollars to flow into places like the Eagle Ford, the Permian and the Anadarko? And then with incremental -- as you think about incremental capital growth from 2016 and beyond, can you rank where the dollars go back into, in terms of Eagle Ford versus Permian versus the Anadarko, or other?

Ryan, when you think where we're allocating our capital this year and where you might -- to answer your question, where you might drop some capital in the future, we're spending about $700 million this year in Canada. That was largely as a result of some ongoing projects that were well-underway. And also the engineering and delineation appraisal work that we're doing on Pike. And so on a going-forward basis, that could drop to somewhere around $200 million, $250 million just for the ongoing maintenance capital for the oil sands. That drives $500 million of less expenditure there.

We also had some expenditures this year as we were finishing up the program in the Miss and the southern Midland Basin, that you could see curtailing next year. And then costs, of course. We're seeing costs go down significantly, as we discussed. I still think by year-end, we'll see costs 20% or 25% below where they were in the fourth quarter of 2014. That rolls through as well.

So there's some fairly significant chunks that you could see coming off. And it's a little hard to force rank. There's no question that our Eagle Ford is giving the best returns in our portfolio. But after that, as you look at the Delaware Basin, some of the work that we're doing in the Anadarko Basin. And as Dave said earlier, and Tony -- the really positive results that we've seen in the Parkman, in the Rockies, they kind of fall into that next bucket. And you'd be making decisions there not based on a full-basin analysis, but on incremental rigs, and where you're drilling within those basins.

As Dave said, we've got lots of opportunities. And if we were in that flat pricing environment, we also have some additional cash that frees up.

Great, thank you. That's very helpful.

Our next question comes from the line of John Herrlin from Societe Generale.

Hi. Just a quick one from the ops report. In the Eagle Ford, you mentioned that you're using a diverter in 100-mesh sand. Can you address that a little bit? Are you trying to put more sand into individual intervals, Dave? What's going on there?

John, this is Tony. John, we're taking a engineered approach to our completion work in the Eagle Ford. So we're capturing a lot more science than we historically have done. We are trying to look at the rock that we drilled with our open hole logs, and design our fracs according to what we think will be successful to pump our jobs away. So we are using the 100 mesh, trying to increase the total volume of sand into the wells. But we're also trying to be thoughtful in where we place that. I think when you look at the results that we are seeing there, we've increased the results from our completions.

We're also working with BHP, and their design is also changing greatly over the last year that we've been involved with them. Their completion results are also being rated as well. I think between the two of us taking a slightly different approach, we are driving our completion results to be much more effective than we have in the past.

Great, thank you.

Our next question comes from the line of David Tameron from Wells Fargo.

Hi, good morning. John, I'm going to echo my sentiments for a happy retirement, and congrats on what you've done at Devon.

Thank you, David.

I want to go back to the Eagle Ford. If I just start thinking about big picture -- you adding 20,000 -- or you added, whatever you added, 23,000 barrels, I guess? 24,000 barrels during the quarter. When you start talking about 170 -- and I know you can go over nameplate -- how should we think about this asset in 2016? Ramp to that 180 level and sit at that level? Or how should we think about that?

Well, we aren't giving specific 2016 guidance at this point, David. I can tell you, we're really happy with how it's performed. I think one of the key things is also going to be just how successful we are at debottlenecking the infrastructure here. And that's going to determine to some degree what our 2016 production is. But you can see, we're just producing outstanding results. Until we work through the debottlenecking and we really work through our whole capital allocation, we're just trying not give too much detail at this point about 2016 production, I guess you'd say. But we're certainly very happy with the results we've had thus far.

Okay. Let me ask another question, just thinking about 2016. What's your framework, or how should we think about your framework for -- no matter what the price environment, whether it's 50, 70, 80, 60 -- whatever the number is. What's your goal from a corporate perspective as far as cash flow, CapEx? How should we think about that?

Well, David, we said before that, within some reasonable limits, going forward, we want to live somewhere around cash flow. But cash flow can be different things. There's operating cash flow. We also have other levers that we have been able to pull in the past. It's just -- we've got a lot of flexibility. It's the great thing about having a very strong balance sheet and a strong financial position in a tough market. But philosophically, over time, we want to balance our capital expenditures somewhere close to what our cash flow is.

Okay, I'll leave it at that. Congrats on a good quarter, and good operational detail. I appreciate it, thanks.

Our next question comes from the line of Brian Singer from Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

Congrats to John and Dave. On the Meramec, you've now de-risked 60,000 acres. Wanted to see both what portion of the remaining 220,000 acres has scope for the oil window, what your delineation plans are there? And then when you look at a well being drilled there -- I think you talked about 51% overall liquids -- how you see that changing, if at all, through the life of the well?

Brian, this is Tony. Brian, I think what we highlighted in our operations report is, we had about 60,000 acres exposed to the -- what we call the oil- and liquids-rich window. Industry and Devon and our partner, we're currently delineating that fluid gradients through -- across the field. But order of magnitude, I would estimate that our exposure just to the low [GOR] oily window would be order of magnitude of about less than 5,000 acres. Most of our exposure is going to be what I would call the condensate liquid-rich window, and that would be largely the 60,000 acres, Brian.

Got it. And then does the well have a disproportionately higher liquids content initially? Or is it 51% overall through the life, in your estimates?

Well, we really don't have a lot of historical performance to look at that. But we're expecting that the performance and, really, the liquid content will mimic a lot of the results that we've already seen in the Cana-Woodford portion of our play there. Not a lot of difference at this time. But I've got to tell you, Brian, it's real early -- not a lot of performance data to tell us that.

Great. And then lastly, in the Permian, a lot of time spent talking about the Delaware Basin. Obviously a lot of improvements and efficiencies going on there. I wonder if the extent of that opportunity set makes the Midland Basin assets less strategic in how you're thinking about the Midland?

Well, we always look at our portfolio, Brian. That's, I think, one thing you can say about Devon. If you look at what we've done over the last two years, we have really high-graded the portfolio. And we don't ever consider that job fully finished. We think part of our job is to bring in top-tier assets, and then when assets can be more effectively handled by somebody else or create more value through a transaction, we'll consider that.

I'm not going to get too specific on the Midland Basin, I wouldn't say. We like Martin County. We've had some historical success in the southern Midland Basin Wolfcamp -- not quite as strong of economics over there, obviously. We're constantly looking at what's the best return for our shareholders overall, as far as whether we should keep or do something with it.

And certainly, the answer to this question is oil price-dependent, also. If oil prices move up, it significantly impacts the economics of our Midland Basin opportunities. So it's not just -- you have to evaluate it pretty carefully, in different oil price scenarios.

Great, thank you so much.

Our next question comes if the line of James Sullivan from Atlantic Global.

Good morning, folks. Congrats to John and Dave both, also. Could you just remind me -- to hop back over to the Bone Spring again -- what is the average lateral length you guys are drilling out there right now? And what are you using for your type well? What is that based on, in terms of a lateral length?

They're just normal laterals, so they're about 5,000 feet at this point. We do like the opportunity to drill extended laterals or extended-reach wells when we can. As we move into some of the other horizons, maybe the Wolfcamp and Leonard, you're going to see us move up into maybe the 7,500-foot lateral length. But for now, most of our work -- and certainly the type curves -- are based on a 5,000-foot lateral.

Okay, great. Just to follow up on that point, what I'm trying to get at here is, I know folks have talked about it a little bit more with the Wolfcamp. But is it a priority for you -- as the focus continues to be the second Bone Spring -- is it a priority for you to block up your acres to give yourselves more double sections, to drill longer laterals for the second Bone Spring? I know you do have a couple of blockier areas where you can do that already, but maybe more opportunity to do that? Is it a priority for you guys? And if it is, would you consider a bigger, more comprehensive acreage swap with one of the other operators in the basin there?

Well, we would. We're always trying to block-up acreage everywhere we work. The Delaware Basin is an area that, as you know, we're committed to. We would love to have both a larger footprint and a more contiguous footprint, so our guys are always trying to work those opportunities. We'll continue to expand the position and get our footprint to the point we can have the most optimum development plan possible. So I think we would be interested in considering a trade to core-up our position there.

Okay, great, guys. I'll jump back in the queue.

Our next question comes from the line of Paul Grigel from Macquarie.

Good morning. Most have been asked. Just wanted to get the latest thoughts on looking at 2016 in regards to hedging, and if there's a plan for instituting some hedges a little bit more agnostic of prices? Or if it will be a little bit more active? Or if you prefer to enter the year, depending on prices, without hedges?

This is Darryl. As we said before, we would like, over any given point of time, to have about 50% of our oil and our natural gas financially hedged. Currently, we have no hedges for 2016, although we're very well-hedged for 2015. Our current thought is that, as we look at commodity prices, we think there is a lot more room for upside than there is downside. And so we have not executed on the 2016.

We do have a process by which we consider hedging opportunities every couple weeks within our Company. So I will not give you any specific prices under which we would hedge; that is an ongoing discussion. But again, our overall thought is that we would like to have about 50% of our oil and gas hedged at any given point in time. It's something we look at all the time, continue to look at. But in the current price environment, we look at the natural gas and the oil strip for 2016, it's not something that excites us.

Great. Thanks for the color.

Our next question comes from the line of Semeer Uplenchwar from GMP Securities.

Hi, good morning, guys. And congrats, John, and best of luck in the retirement.

Thank you.

What I'm trying to understand is, if I'm looking at 2016 -- I know this question has been asked before, I'm just trying to get a direct answer -- is, what do you need to see to put rigs back to work, from a cost perspective, from an oil price perspective, cash price perspective? Just trying to understand. Because right now, we are in a low-price environment, but what happens in second-half 2016 if prices move higher? How should we think about that?

Well, Sameer, that's obviously a hard question to answer. And we're not trying to be evasive about 2016, but we're so early in thinking about 2016, and there are so many variables -- costs and prices and all of the other variables that go into that. I think what we would say is, whatever the price is, we're going to focus our efforts next year in the areas where we're going to drive the highest returns, so you get the best rate of returns.

And there are going to be some funds that will be available to us, even in excess in those really good areas where we've been driving the higher rates of return for next year. Because we'll spend less dollars in a couple of the other places that we were committed to going into in 2015. There are just a whole lot of variables right now. We're so early in the process in determining what 2016 looks like, it's really hard for us to give you an answer there.

You ought to feel that -- take away from this that our focus on the Eagle Ford, on the Delaware Basin, this emerging opportunity we have in the Rockies -- which looks pretty good -- are all areas that are going to drive high rates of return. And we'll focus on those areas whatever our capital budget ends up being.

Perfect. And then on a broader basis, everybody's -- including Devon's -- well results continue to improve in the Eagle Ford and Bone Springs. I'm just trying to understand, what is Devon doing differently versus peers? And where is Devon leveraging on peers or partners? And just trying to get an idea about that long-laterals completion designs or what have you. Thank you.

If I understood the question, what we're doing in the Bone Springs is different. I think two things. One, we have some of the best geology for the Bone Spring. So our acreage happens to be located where some of the best Bone Spring opportunities are. And second, we think we are leading the industry in our completion technology. We have really made a conscious decision to step out and test various-size sand concentrations, and stepping up to 3,000 pounds of sand per foot in some areas. So we can really understand what's the right size of completion to put on each of our specific areas.

And it's obviously a price-dependent issue as well. I think -- what are we doing to lead the way in the Bone Springs? We're, fortunately, a good geology. I think we have a good appraisal program going on, a good development program, where we're testing the various zones. And we are really, I think, leading the way with our completions at this point in the industry, also. Tony, you want to add to that?

Yes, Sameer, I think what I'd add to you -- and we talked about this at the last call. But our technical teams are putting a lot more science and a lot more work into the subsurface characterizations of the projects we work on. So we're taking a lot more cores, pressures, temperatures. We have fiber optics in all the plays that we're working, so we're able to calibrate all that information.

On the execution side, the guys are doing really good work. I think we talked about standing up our well con centers. We're maintaining -- we have 24-hour coverage of every drill bit that we're operating right now. So we're keeping the wells -- the trajectory flat. We're keeping them end zone more than we have in the past. All that's really adding to a better completion. It's hard to measure the work that we do, and where it ends up. But I think the out-performance that you've seen the last couple quarters have been associated with just some good quality work from our technical people.

Perfect, thank you.

Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers Investments.

This is like Christmas. Back here again. Thank you. (laughter) Let me ask two real quick questions. The first one is with regard to the second Bone Spring stacking test, the stacking pilots. The first -- the pilot 3 and pilot 4, are those located in the basin area? And pilot 5, because it's got a third Bone Spring well in it, is it located someplace else?

They're mostly in the basin. We have several pilots there. But I'd also let you know that we've got a couple up on the slopes. We're testing the down-spacing concept, mostly in the second Bone Spring. But we're trying to understand the relationship from the staggered-laterals approach, and just simply the down-spacing in the same interval. We're testing these concepts in original-pressured environments. We're also testing these concepts in partially depleted areas, to know what we might be able to come back to and further develop our current position in.

Okay, that's great. The other quick question I wanted to ask, slide 16 in the Anadarko, you showed a number of zones of interest. I was just wondering if you guys have tested or have any plan to test the Springer? Some of the peers in the midcon are calling the Springer comparable or superior to the stack. Thank you.

Well, we do have exposure to other intervals inside of the Mississippi in there, and so our guys are looking at all these intervals. We don't have a lot of data to talk about at this point. But we're not oblivious to some of these other opportunities, and we will be testing some of these, with time.

Great, thank you.

Looking at the queue, it looks like we're getting fairly near the end of the calls. But I was thinking, there was one area we thought we might be asked about, but we haven't been. And since we have a couple of minutes, I might ask Tony just to make a comment about it. Our refrac program in the Barnett. This is a program that we're really proud of how it's proceeding so far, and we see some real upside associated with that. So, Tony, you want to make a comment on that?

Sure. Dave, like you mentioned, we were expecting a call on our refracs. We heard a lot of that from our shareholders in the past. I guess I want to just summarize the work that we're doing. We're excited about this opportunity across our entire position. We've seen such a dramatic improvement in our completion results with the newer technology that we're incorporating on our original completions, that we've gone back and starting to test some of these new completion techniques with our existing producers.

We've already completed about 50 refracs on vertical wells in the Barnett -- all with outstanding results, very commercial. We intend to complete a program about 200 for 2015. We also had completed about eight to 10 jobs on horizontal wells in the Barnett on -- what I would call partially depleted wells. We're encouraged by the work we're seeing there. We'll continue to test that concept.

We also are testing refracs across the remaining portion of our portfolio. We've tested some in the shallower portions of the Permian Basin oil play, and also the Haynesville. We're designing refracs for the Eagle Ford and the Cana-Woodford projects.

Overall, we understand that there's going to be technical challenges associated with a refrac program. Trying to control where you place the sand is going to be more difficult. But we're doing some real creative work, and using science in our north Texas horizontal program to test both chemical diversion and mechanical diversion techniques. And we're encouraged by the work that we're seeing there. So we're using all the technology available, employing all the science that we have from the existing properties that we've been so active in, in the past.

We're extremely positive about it. We think this could be a significant game-changer for a property like the Barnett Shale. We work pretty hard to keep our rate flat at 1.2 Bcf a day, and the guys have done a lot of good work with artificial lift and line pressure reductions. We think this refrac program could be a potential game-changer for the Barnett.

With that, and no questions remaining in the queue, we'd like to thank you for your time and interest in Devon, your thoughtful questions. If you have any follow-ups, please don't hesitate to call Scott, Shea or myself. And have a wonderful day. Thank you.

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