Good morning. My name is Courtney and I will be your conference operator today. At this time, I would like to welcome everyone to the Devon Energy Q4 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Howard Thill, Senior Vice President of Communications and Investor Relations, you may begin your conference.

Thank you, Courtney and good morning everyone. Welcome to Devon’s fourth quarter conference and webcast call. I am Howard Thill, Senior Vice President, Corporate Communications and Investor Relations as Courtney told you for Devon Energy. Also on the call today are John Richels, President and Chief Executive Officer; Dave Hager, 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 operations report at devonenergy.com. Additionally, we have included our forward-looking guidance in our earnings release. I hope you've all had a chance to review those documents as today’s call will largely consist of Q&A. Finally, I’d remind you that comments and answers to questions on this call will contain plans, forecasts, expectations and estimates which are forward-looking statements under U.S. 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. For a review of risk factors relating to these estimates, see our Form 10-K and subsequent 10-Qs. With that, I’ll turn the call over to our President and CEO, John Richels.

Thank you, Howard. Good morning everyone and thank you for joining us this morning. You have a lot of detail in the operations report that was posted last night I sure hope that you’d like that new disclosure and you find the report very helpful as you work your way through the information. Just before we jump into Q&A, I just like to make a couple of points. The past year was an important really transformational year for Devon and the Company delivered what we think were some outstanding results in 2014. As we discuss our 2014 results today and our outlook for 2015, I hope you come away with three important messages. First, the dramatic portfolio transformation that we accomplished in 2014 has resulted in Devon having a top tier asset portfolio with a deep inventory of high rate of return investment opportunities and years of running room. Secondly, we’re approaching 2015 with caution and with a view to maintaining flexibility given the challenging business environment. With that in mind, we’re laser focused on execution which is allowing us to decrease E&P capital spending by roughly 20% in 2015 without any reduction in our previous total production growth guidance or our previous guidance of 20% to 25% oil production growth. And lastly, we have a terrific balance sheet that continues to be one of the strongest in the E&P sector and we have a very strong hedge position, ample liquidity and a number of other financial leverage that give us superior financial strength and flexibility in the current business environment. So in spite of the challenging macro environment, we think we are very well poised to deliver superior returns for our shareholders in the upcoming years. Again thank you for joining us and with that I’ll turn the call over to Howard to start the Q&A. Howard?

Thanks John. And before we start, I’d ask you to make certain that we can get as many people as possible on the call that you limit yourself to two questions. And you can re-prompt to ask additional questions as time may permit. So Courtney with that we’re ready to take our first question.

Certainly. Your first question comes from the line of Doug Leggate with Bank of America. Your line is open.

If I may take prospectus first of all on the increase in the type curve on the Eagle Ford I guess I was looking for some incremental disclosure on the rest of the Eagle Ford position Lavaca I guess the Upper Eagle Ford inventory potential because the reserve life there rather the drilling life is still relatively short and in the current price oil environment I am just curious as to how do you think about that inventory as we go forward? And I’ve got a quick follow-up please.

Hi Doug this is Dave. Well, we’re very encouraged with what we’re seeing obviously in the Eagle Ford we’re up the type curve due to the results that we’ve had with our optimized completions. We also -- the production optimization specifically the choke management have yielded outstanding results and you can see highlighted some increase in the type curve and then a few incredibly great wells, greater than 3,000 Boe per day on a 30 day IP. We have decreased the drilling activity somewhat in the -- or the rig activity somewhat in the Eagle Ford we’ve dropped down we were thinking we’re going to go from around 15 to 16 rigs, we’re down around 10 rigs in DeWitt County and then we’ll be drilling some wells in Lavaca County this year and we will also continue appraising the Upper Eagle Ford. We’re very encouraged with earlier results that we see in the Upper Eagle Ford at this point. Lavaca County is still a part of the overall program. I have talked about previously how it’s a little bit thinner over there you don’t get quite the rates in the EUR as you do in the other and given the current commodity price environment we think it’s prudent to focus our activity in DeWitt County but we have a strategy for holding on to the Lavaca County acreage and that will be part of our go forward program when commodity prices recover somewhat. So we still have Lavaca it is there the DeWitt County and the Lower Eagle Ford just keeps getting better and we still don’t have the results from the Devon completion that we did here and start coming online here at the first year, but these are from the revised BHP completions, we think took us about 80% away to where we want to go with the completions on and that’s getting significantly better and the earlier results on the Upper Eagle Ford are encouraging. We just need to get more appraisal activity. So I think overall it’s positive and with the lower growing activity and with the Upper Eagle Ford potential there, there is potential for lengthening the inventory that we have.

I appreciate the answer Dave, hopefully my second questions will quicker. Obviously there is a lot debate over how quickly and what scale of cost reduction the industry can expect in this lower oil price environment so I was just -- if you could give us Devon’s perspective please in terms of what have you assumed in your capital budget by way of cost reduction and then ultimately where do you think it can get to sort of by year-end as opposed to the average for the year? And I will leave it there. Thank you.

I think your question was quick on the first one my answer was long so it wasn’t your fault, but I’m going to turn it over to Darryl Smette he is going to talk a little bit about the cost reduction.

Yes Doug, just to kind of set the basis here what I’m going to do is give you some numbers and they’re going to be in relationship to the cost environment we saw in the fourth quarter of 2014. So what we’ve seen so far is a cost reduction on different phases of our CapEx from drilling rigs to drill bit to LTG those types of things of about 10% compared to the fourth quarter. We are still in meaningful discussions with all of our equipment and service providers. We have high hopes that we will continue to drive additional cost out of that system. Right now we’re hoping that we could get an additional 10% to 15% by year-end. What we have currently in our budget is a 10% reduction from fourth quarter and that does not include any efficiency as it we might gain from our operational people that is just price related to our service providers.

So 25% would be the total dollar just to be clear?

That would be a comparison of fourth quarter 2014 versus fourth quarter 2015.

Your next question comes from the line of Subash Chandra with Guggenheim. Your line is open.

First question is on the uncompleted inventory, how do you see that exiting ’15 versus ’14?

Yes this is Dave again. Talking specifically in the Eagle Ford, we had about 150 wells they were not completed at the end of 2014. We have decreased our completion crews out there. We did have nine crews working at one point. We’ve started five. We added four more, two of which were Devon operated. We’ve gone from nine down to four at this point three of which are BHP operated, one of which is Devon operated. The Devon operated crew is also in DeWitt County. We’re going to do a few more wells there and then we’re going to move it to Lavaca County and then after that we’ll be dropping that completion crew also. Having said all that we do anticipate the uncompleted inventory in Eagle Ford to basically have by the end of the year. So somewhere on the order of 70-75 uncompleted wells there. The other key area I’d say that we have an uncompleted inventory is in the Delaware Basin and the Permian Basin overall we have about 55 or so wells in the Permian Basin I think about 35 in the Delaware Basin that are uncompleted and that’s going to be part of the basis of our growth as we move into 2015 as we drive that inventory down to probably more on the order of 20 to 25 uncompleted wells by the end of ’15. So we’re taking a measured approach at this in light of the current price environment but we will be driving the inventory down.

And a follow-up I guess I will wait for some details in the K but any sort of flavor you can add for the ’14 reserves sort of where the hits and misses or the highs and lows were as far as reserve credit you might may or may not have gotten?

Take a shot John and I will add to it.

So Subash, what we look in our 2014 I mean some of the big pieces, and you’re right you’ll be able to get lot more detail but some of the highlights of that I guess was the light oil reserve additions were very-very strong we actually added about 200% of our light oil 2014 light oil production to the extent there were some downward revisions they were largely gas as a result of the five year rule if my memory serves me correct I think it’s 74 million barrels were related to that. So they’re just off because we’re not developing that gas right now and it will come back at the right time. Dave, do you have anything to add to that?

I think that’s the key we had extensions discoveries around 200 million barrels or so and we purchase of about 265 million barrels we had revisions other than price of negative 65 million and that was essentially all of that and although more it was due to the five year rule so that’s the key highlight. So we think when we put it all together from a all-in F&D standpoint or drill bit F&D we had very competitive metrics.

Yes, I guess I was sort of looking at in context of what you’d spent in ’14 versus ’13, look to be a bit more and with revisions or say even without revisions look to be about the same as the prior year if there was any read through in that?

Well, the one thing you have to keep in mind in general when you’re thinking about F&D is that as we shift to oil the F&D maybe a little bit higher but it’s still has the value equation makes it more than worthwhile as you still are on from a returns standpoint you still get much higher returns. But as you make the shift like we have to oil, oil F&D tends to be a little bit higher.

Okay, that is all. Thank you.

And as we said Subash the bulk of that or a big piece of that reserve addition was on the light oil side which is our highest margin product as well.

Your next question comes from the line of David Tameron with Wells Fargo. Your line is open.

If I think about the ability to ramp in the second half of the year and kind of how you guys are with price sensitivity and I assume like every other E&P company you’ve run 10-15 different scenarios since October-November. But how should we think about if oil comes back to 65, what’s that look like can you just give some general framework and thoughts around that?

Yes this is Dave again. Well there’re a lot of variables that go into that equation and we’re going to give you a fairly non-specific answer here because of that. But we have to look at also what is the cost environment if oil does go back we have to look at what returns we’re getting in each of those plays, what the takeaway capacity is, what the drilling results are, et cetera. So there is -- it's ought to be too specific on that I would say that the key thing is we have a lot of flexibility both to take capital down or to take capital back up. The vast majority of our rigs are on a well-to-well basis. We have very few on a long-term contract. Almost all of our acreage is held by production. So there is no concern with drilling wells just to retain acreage. So we have all the flexibility. So we’ll assess that situation if that were to occur and make the right call understanding we are looking at first the returns at a well level and then second what’s our balance sheet look like.

And one follow-up on that, if I think about 2016 let’s say I know it’s long ways out. But if I think about oil and where it’s at and let’s say you get those 25% reductions on the service side that you’re targeting by 4Q. Does that set up a scenario where 2016 and I guess would that set up a scenario where margins come in sets the 2016 looks similar to what you would have done in 2013-2014 just at a lower price band. Does that make sense?

Yes, I understand what you are trying to scribe there David. Well, it’s possible that’s true from I think in that scenario and again there is a lot of variables go in there so it’s hard to say for sure. But I think you could paint a scenario where you could be getting similar type returns to what you’re talking about in 2013-2014, you would have to also then consider though the cash flow for the company and the desire that we want to say with a strong balance sheet. So, obviously 65 to 70 you would have lower cash flow than you would have had at $90 a barrel. Having said that, we’re also looking at in addition to what we have talked about we have a lot of productivity gains that we’ve been able to get here through the improved completion design. And so I think at the well level you could just paint a scenario where you could have very-very good returns in that kind of price environment. I think you’d have to look at the overall cash flow for the company and just say how much capital do you want to spend and then maintain a strong balance sheet.

Your next question comes from the line of Bob Brackett with Bernstein Research. Your line is open.

I have a question about the JVs and how you allocate capital in the Eagle Ford that BHP JV, how do you develop that plan, do they put forward a plan for the number of rigs and you either consent or not consent or you do it interactively?

Tony Vaughn our Head of E&P is in the room and we’re going to turn the call over to Tony, he was probably the closest of any of us with BHP and we’ll have him answer that.

Hi Bob this is Tony. I appreciate your question. We do work very closely with BHP. We actually have some of our engineers accounted into the BHP office so it’s very close working relationship. As you know we were running about 15 rigs in DeWitt County three and our Lavaca County work. We jointly decided to reduce activity on the DeWitt side of the business back to 10 it affords us the opportunity to actually high grade the completions and you can see that the type curve was increased from about 1,200 up to 1600 Boe, 1,650 Boes per day but the average for the last quarter was all the way up to 2,100 Boes per day. So it’s really a joint effort. We have a concept of working in a project team environment between the two companies and a lot of synergies there bring all of our technical skills to the table and we just jointly work that process.

Okay. And then a similar JV question on this line it looks like you still have some money left on the carry, why not go ahead and use up that carry since you got at 70%?

Well, that carry is fungible. So we can move it, if you remember the original was the set up in five different plays and we can use that carry up in the Rockies as well and that’s our intention to use rest of it. The JV money the signer pack is in the Turner and below but they’re not in the Parkman but we will be drilling some Turner wells and that will use up that remaining JV carry and we think that’s the most efficient place to do it.

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

I’m wondering on the NGL front the guidance you guys gave for pricing surprised me a little bit and I’m wondering from your advantage business point at both a producer but also operating EnLink if you could talk about how you see that market evolving over the course of the year?

Yes, this is Darryl. Obviously NGL prices have really taken a hit. Starting a couple of years ago but just in the last three or four months that has deteriorated even further. There is a couple of things at work there. First of all we’ve had, because of the success the industry has had, we’ve had a tremendous amount of new NGL that has come on to market and that is including virtually all the products but primarily ethane and propane. Over the last few months what you’ve seen is the deterioration in the propane price and that has been caused by a couple of different things, number one the increase in supply but in the middle part of 2014 and early in 2014 we were able to export large portion of that propane internationally because of the downturn in the economies and the low crude oil prices now the crude oil Napa price is able to compete internationally with propane. So the propane price internationally plus the cost does not make that a good exportable product right now. So that has really backed up propane and caused a large growth in storage. As we go forward we don’t see, and let me just add to that, what we had is a very mild winter in some parts of the country especially early on in November and December and so there was on the propane side a number of demand scenarios that didn’t play out because of that warm weather. As we move through the year it’s going to take a while to work off that propane supply. So while we might see some improvement, we have seen some improvement in the last 30 days or so. We still think that propane is going to be under pressure. We do think ethane will continue to be under pressure simply because of all the ethane that is out there. We do not think ethane will start trading above the Btu equivalent of gas until we get into the late 2016 maybe early 2017 as additional pet Cam plants come on-stream. Even though there are some export facilities that will be available at least on the water coming in the next year or two in the current environment we don’t see that helping a lot. So we think ethane is going to continue be under pressure for the next year and a half or so and we think propane as we go through the summer months may improve a bit at least in the near-term that doesn’t give us much hope either.

That is a lot of great detail and I’m sure some of the people on the call up in the Northeast are wondering about that mild winter you’re talking about but on the different front your thermal oil in Canada, can you talk a bit about how that asset I know the operational performance looks great, but I’m wondering if you can talking more broad sense how that asset looks in your portfolio now and if you -- how it compares to your light tight opportunities and particularly with the performance but also I know there is a different tax regime up there and all that sort of thing?

Charles, when you look at the -- we got the production continuing to ramp-up in Canada as you know from Jackfish 3 and we actually have another pad coming on at Jackfish 2 to help ramp that production up through the end of ’15 and through all of 2016. We’re not making a lot of capital expenditures and undertaking a lot of capital expenditures in Canada in that heavy oil business today. And this is a business that we always thought you have to take a long-term view on it and you have to be in one of the best projects. And we’re in an area with Jackfish and Pike frankly our neighbors there are Cenovus’ Christina Lake and MEG and we’re in really what appears to be the sweet spot for oil sands development in Canada. So we’re not expanding a lot in terms of additional CapEx right now. The returns from that over the last year have always been cash flow positive even we’re cash flow positive even at a $40 or $45 WTI because we are in one of the very best projects and the returns over the last year have ranged from some of the lower values with the $45 WTI to very high returns when oil was trading at $100 and the differential was 14. So it’s something that you have to take a bit of a long-term view on but it’s still provides at a WTI prices where they are today a pretty good rate of return on cash going forward basis.

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

On the cost front your guidance for both lease operating expense and SG&A costs per Boe appears to be rising a bit in 2015 relative to ’14. Can you talk to what’s driving this and if you see or have baked in cost deflation opportunities?

I may start off on the LOE side here briefly and then hand it over to Tom Mitchell to talk about on the G&A side. On the LOE side, the increase is primarily driven just as we continue to shift our portfolio to an oil oriented portfolio versus a gas oriented portfolio. And so if you remember and part of 2014 we still have the conventional gas assets in the Canada as well as the non-core gas assets in the U.S. And so they contributed the overall number for 2014. So it’s just a shift of the portfolio. But in a normalized price environment you are still increasing margins significantly as you move to this oil oriented portfolio. But that’s the only thing on the LOE side. I think Tom can give you little more specifics probably on that and also on the G&A side.

Yes Brian, on G&A, first of all, you got to remember that reported volumes are down year-on-year when you take out the non-core assets that have been divested so that’s part of it. We do have some increases you’ve got a full year of EnLink in there and EnLink s is up a little bit. And then addition to that and this is really positive and you’re seeing it in our execution some investment has been made primarily on the technical side that’s going into G&A here back in Oklahoma City and a huge investment really in just execution overall within the company and you’re seeing it in our results here in the last few quarters in particular. So those are the primary drivers behind it.

Brian one thing I didn’t answer is we have not assumed any cost savings on the LOE side. Now we are going after those obviously but unlike the capital side where Darryl talked about the cost savings we have not assumed that in our budget case again we are aggressively pursuing those but we have not made that assumption.

And then my follow-up actually goes a bit back to the prior question with regards to oil sands. When you think about Pike this is a year I think you said you’re going to be doing the final review as you think about potentially looking at it again for sanction next year. But do you see cost deflation opportunities and have you locked any in, in terms of Pike or future in situ oil sands and what pace is that moving at relative to what you’re seeing in onshore U.S.?

Brian you are absolutely right we are seeing some cost in. So what we’re doing at Pike now as we’ve previously discussed and Dave can maybe give you if you like some more detail around the engineering. But we’re doing some additional engineering work throughout this year to scope out the project properly and also at the same time scoping out costs because that we’re seeing exactly what you have alluded to we don’t quite know where those costs are all going to work out throughout the year but we think we’re going to have significant cost savings going into a decision as to whether we move ahead and when we move ahead with Pike. And that makes a significant difference if we can keep those costs down. We’re going to revisit the decision on Pike after we’ve done this additional appraisal work and the additional engineering work and scoped up the cost more towards year-end. And in addition to the cost side that will also give us more clarity and some visibility hopefully on FX which is an important factor as well to give us more clarity and visibility on commodity prices and also on differentials because we’ll maybe have a little bit more definition around projects like Keystone XL or TransCanada’s Energy East and Alberta Clipper and Kinder Morgan and the rail process all of those things that go into determining differential. So we’re going to get lot more of that information but we are definitely seeing the cost structure come down, having said that because we’re still working on the final engineering documentation. We haven’t been locking in costs at this point in time but we’ll get a lot more clarity on that as we work our way through the year.

Your next question comes from the line of Michael Rowe, TPH. Your line is open.

I actually wanted to go back to comment made earlier just about 2016 and kind your willingness to out spin cash flow. I’m just wondering if hedges kind of roll out in 2016 and current strip price proves to be accurate, could you maybe talk about the ability of your high rate of return Eagle Ford and Delaware Basin assets to sustainably grow within cash flow and if they can’t I mean do you have some level of comfort to out spin cash flow and given your ability to monetize midstream assets to EnLink?

Michael, certainly I mean yes the assets you’re talking about our returns in the Eagle Ford and Permian are very high and certainly maintain that, but as I said in the comments at the beginning, we are in a terrific position obviously to depending on our outlook for the future at the time. We’re in perfect position to take advantage of that because of our strong financial position and because of all of the financial levers that you’ve talked about. So our plan is as we kind of look in the future our plan is to live pretty close to cash flow, but we’ve got a whole lot of other financial levers that we can take advantage of if we felt the time was right and the circumstance at the time were right.

And I guess just the last question I guess would be sort of around your hedging strategy, just given the highlights of return that you can get in the Eagle Ford as an example even today do you have any desire to hedge 2016 at this point and I guess what are your parameters that you’re thinking about internally before you’d make a decision to actually roll on hedges in 2016? Thank you.

Well so far we have -- our philosophy generally has been that we try to lock in about 50% or hedge about 50% of our production and we do that just as a matter of prudence even having a strong balance sheet and having the financial levers it is just to ensure some level of cash flow every year. So that’s our general philosophy. Now we haven’t been layering in a lot of hedges for 2016 at these prices because we believe that the price is going to be higher in 2016. And what we have typically tried to do although we have swapped some volumes, we typically try to do it on collars where we can lock in or protect the floor price and keep some of the upside as well. But given that we haven’t been layering in the hedges at this price we’re going to have to see a little stronger price or we have a change of view in the future. And the other thing that you always have to remember is, we always try to keep in mind is that when we do lock in the price side that doesn’t lock in the cost side. And so you’re only locking in half the equation and so we’re watching where costs are going now and we’re watching where commodity prices are going as we continue to prepare for 2016 and the position we might take in our hedging decisions.

Your next question comes from the line of James Sullivan with Alembic Global. Your line is open.

Just wanted to go back to a topic actually from a little minute ago about the NGL pricing you guys gave some nice color there, thanks for that. But I wanted to talk about how that affected your thinking on capital allocation to the Anadarko Basin and CANA specially, obviously the NGL wide rate parallels are kind of a bigger part of the economic proposition for those wells how do you think about that and how is that affecting well economics your generally kind of poor view of the NGL market. I know that you have a bigger asset there now so I’m not sure if we should think of the 400 million is an increase in spending, but just any color on that?

We have a very deep inventory of development opportunities that we’re pursing in the CANA field particularly not to mention now the Meramec that has, we’ve had a couple of good wells in the oil section of the Meramec that we’ve operated and then you can see we are in a number of non-operated Meramec wells that were oil oriented in the past year so that’s kind of a separate story but that’s a very positive story as well. Regarding CANA and the funding of the activity that we’re doing there is the completion designs that have really carried the day to improve the economics and the rates of return that we have out there where we upped the sand count tamp around 3.5 million pounds of sand around 6 million pounds of sand or around from 700 to 1,200 pounds per lateral foot. And we’re frankly testing that over 2,000 pounds per lateral foot now. We may see even further improvements by the size, the type curve, improvement we’ve already described to you. And so that carries the day we have baked these lower NGL prices that Darryl described into our rates of return and bottom-line with the improved completion techniques that we’re seeing these wells compete well with the other opportunities that we’re funding this year because of those improved completion designs.

The other thing I had is you guys have talked and this actually goes to some of the work you guys have done in that same filed but about optimizing performance on base production I think you have had some asset jobs that you were doing out there and showing some really nice upticks there. Could you give a rough and I know would have to be rough companywide base decline estimate and that can be either net or not net or whatever maintenance efforts you guys are undertaking eventually in the Barnett too?

James this is Tony Vaughn again. Our base decline just overall for the company without CapEx is roughly about 20% maybe not quite that high some of the good work that the teams have done across the company have really focused on up time they focused on line pressure reductions in areas like the Barnett and at CANA. As you mentioned we’ve worked on some chemical jobs in CANA that really had a strong boost in our rate and have major rate impact in ’14. The guys are looking at artificial lift with a strong focus on that more than we had in the past so all that collectively in my mind in ’14 was probably one of the primary reasons for outperformance over expectations. And so I think there is a renewed vigor we’ve really segregated our workforce into a couple of different areas. So we have the team in every business unit that’s focused on nothing but the base. We also have a team focused on the execution part of the business as well as the asset management side. So I think we’re just bringing a lot of clarity and a lot of focus to the wellbores that we operate.

And let me just add a little bit to that too I often get asked when I am out meeting with investors why are we doing is this is the new Devon why are we doing so much better operationally and Tony is actually probably even if anything he is underselling the transformation that’s taken place internally to Devon and around the execution around the assets. Bottom-line we are very focused on being one of if not the best operator in each of our core areas and it’s not just words that we’re saying here but about 18 months ago we took some of our top-technical professionals away for a few months along with a couple of consultants and said what new we need to do to transform our operational performance. And what you are seeing today is the results of that effort and there are a number of very specific initiatives that came out of that where we added technical staff that Tom mentioned earlier where we’ve added separated the execution for the long-term asset management. We’ve added project management skills. We have a 24x7 well control center where we manage all the operations of all our wells. We have state of operations we have computerized operations in all of peered office where we remotely monitor production of all the wells. I could go on with several other things but I think that’s what gives us confidence that the tight performance that you’re seeing out of Devon is going to continue on into the future. We’ve got the top assets, we’ve got strong balance sheet you’re seeing the execution now. We’re humble about it but we intend to continue doing what we’re doing and we’re going to keep getting even better.

Your next question comes from the line of David Heikkinen with Heikkinen Energy. Your line is open.

Just thinking about improving service equipment reliability and just the efficiency and pace of wells per rig per year, can you give us some thoughts about fourth quarter ’15 versus fourth quarter ’14 of, is that a 10% improvement or are there any particular areas where mud motors or frac equipment was less reliable and now that the industry has slowed down you’d see a bigger improvement in just that efficiency side as we head into ’16?

David, this is Tony Vaughn again. I think what you’re describing is well within our expectations for as we go through ’15 as Dave mentioned we’re putting a lot of thoughts into and a lot more granularity into all of our wellbore designs we’re really trying to drive out efficiency using project managements skill to manage cost to stay on schedule. We are starting to see the benefits of that right now. We have incorporated some stretch in inside of each of our business units for the execution part of our work so I think the 2% improvements that you described is relevant I’d also mention that we through our capital allocation process we have really cored up into the sweet spots of these areas that we work in, we’re really doing more development type work and less appraisal work. We have spent a fair amount of money on science and some of these appraisal areas such as the Lavaca County and also in the Delaware all that will come to will pay-off dividend here probably in the second half of this year. So I think the 10% that you described is probably well within reach then.

And so as we think going in the ’16 just kind of modeling in the increase in wells at this rig count before you even think about ramping rig count is reasonable that is cool. The other question I just want to make sure I was understanding what you said on the LOE front that you haven’t factored any cost savings and not putting words in your mouth but again kind of the same 10% CapEx reduction that you built in I don’t see a reason why some of your maintenance and kind of base LOE couldn’t come down at fair amount as we go into ’16 is that a reasonable framework?

You know what David we have put some challenge to our business units cost contentment is going to be a real driving force inside each of our business unit teams. I think the ability to reduce LOE is there I think a larger percent of that cost component is associated with labor which is a little bit stickier than some of the other things that we’ve talked about today. I do think we still have the ability to shave off some LOE and it will be a little bit better than what we have forecast but you have to remember we’re seeing projects like the Barnett which is accreted to the company LOE is starting to decline replacing that with some higher cost barrels in places like the Delaware. So we’re working that, got a lot of focus on that as we just described.

And just one last one, and I’m assuming you don’t want to give an expectation for an exit rate for production at this point, for ’15?

David I don’t think we’re not focused really on the, or giving an exit rate. But suffice to say our production stays pretty strong through the year. We have a pretty good bump in the first quarter and then it holds pretty steady after that throughout the year. And we put ourselves into really a great position with the ton of flexibility as we move into ’16 which I think is really the important part as well.

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

I wanted to first ask few questions on the Eagle Ford and perhaps maybe try to understand to what level kind of the new completion design is driving the improve results. I was wondering if you had any data on perhaps wells that are located in the same area, and what you’re seeing in terms of the new completion design versus the old one?

Well Tony, can give a little more specific here but in general the wells that you saw are in the fourth quarter were the results of a revised design that we worked with BHP on I generally characterize as probably somewhere around 80% of where we’d have liked to go with the completion design. Now we added for a period of time during the fourth quarter two completion crews that Devon operated by themselves and pumped a number of jobs those wells are just now starting to come online. So we’re not sure if you are going to see the other incremental improvement or not but we’ll see and we’ll probably have the results for that in the first quarter. But the type curve improvement that you’re seeing I think is in that wells that are in like type areas and that’s the result of that, I don’t know if Tony wants to add any more detail around that.

Yes, I think that’s right Dave, BHP has got a good design I think they’ve actually been changing that over the course of the last 9-10 months which is approaching a summer design to Devon and we pump a little bit more sand we pump more fluid they have a little bit different philosophy there but I think their completions are moving up. It will be interesting to see if the design that we pumped on the 28 wells that we worked on in DeWitt County have any incremental benefit in that. But I think overall we’re starting to see good collaboration between the two companies trying to take the best from both. I also mentioned to you that some of the science that we’re doing especially in Lavaca County is very unique. We have run fiber optics we drilled vertical well there taking 240 feet of core, doing a lot of micro seismic work, trying to have a really good understanding of what delivers value on the completions in the Eagle Ford. So I think that will continue to improve. We’re also seeing a lot of benefits from our production optimization work that I think we’ve talked about in the past and there are guys they have taken a really I think a really aliquant approach to managing their bottom out pressures and rate. We’re seeing the type curves move up and exceeding performance on that. We’re waiting to see if there will be a corresponding improvement in the expected ultimate recovery per well. I think that could come but we need little bit more data to understand that better.

And my follow up question is just regarding future potential dropdowns to EnLink I guess you guys highlighted in the ops report about expecting to do the Victoria Express Pipeline some time in 2015. I was wondering if you can maybe give some more details around that. And secondly regarding Access how big of a factor would be in terms of that ultimate valuation would the FID be on Pike in terms of future volumes?

Yes Arun, what we talked about with the Victoria Express is potentially dropping that down some time in the first half of the year guys on both our folks here and on the EnLink team are working on that and what that would look like and what the valuation would be and we can’t give you a whole lot more color around that right now. As we move into Access we’re working a lot on that. There are some complexities with it because it’s in Canada and it’s a large asset it will certainly our pace of development of Pike later on in the year will certainly have some bearing on that valuation. So as we get to the time of the year when we’re revisiting that making that decision that will come into play. But we always talked about the dropdown on Access probably being late in 2015 or maybe even moving over to the beginning of ’16.

Okay, so it sounds like in the next year or so?

Yes sir and I think that’s what we’re looking at right now but there is a lot of moving parts right now so we will have to see whether it works out that way that’s the current or that’s currently what we’re moving towards now whether we get all of that work done and whether it all pans out exactly the way we think will remain to be seen. But what we’ve always talked about is potentially doing it in the latter half of this year or early in ’16.

Your next question comes from the line of John Herrlin with Société Générale. Your line is open.

Two quick ones in the U.S. you had a negative 38 million barrel revision for oil that wasn’t related to price, John earlier you talked about the revisions being related to the five year rule is that the case for the oil in the U.S.?

Tony can answer that on -- sorry John that was largely, the five year rule was largely related to gas.

Okay, I figured that.

On the oil side we saw a little bit underperformance in our expectations in the Mississippian so we wrote down some per well performance there and also in the Southern Midland Basin we had to write down a little bit of reserves associated with that. And mostly as John had mentioned these were mostly gas write offs and associated with the five year rule.

EnLink bought the Coronado system in the Midland Basin Darryl how are you configured for the Delaware side in terms of GTP do you have adequate infrastructure at this stage?

John look just to kind of paint the background here and I think we’ve mentioned this before but a lot of acreage Devon has in the Permian Basin is acreage that we have acquired overtime. The vast majority of that acreage is currently dedicated to other parties. And so we have very little acreage that’s available to go into any of the EnLink facilities out there although the acreage that is available in the facilities are closed that is certainly a party that we talk to all the time. In terms of the facilities that are third-party facilities we have issues every now and then closer to well head we have to put in the different types of facilities that kinds of ebbs and flows and it depends on the performance of the wells generally. So when we are seeing some really-really good results from some of the wells and they come on stream which has happened more recently. There is a period of time when we have to have the facilities that catch up our third-party providers have done a very good job of doing that for us. We have a team of Devon what we call facility and pipeline people who are busy installing the facilities that we need to get to the third-party people. So right now we feel pretty good about where we’re at. We have a few bottlenecks we have some wells that are offline waiting for some pipeline and some other facilities to be installed. Most of that will be up and operational by the end of the second quarter, but we have made pretty good progress and for the most part are staying ahead of the curve. But there are some isolated incidents where we have a two or three month wait to make sure all of our production moves.

Your next question comes from the line of Kapil Singh with DoubleLine Capital. Your line is open.

Just a quick question on leverage, where do you see that going what are your sort of targets over the next kind of 12 months? And then related to that your ratings as well. And what is sort of the plan to achieve whatever those targets are?

Yes this is Tom. We’re pretty solid in our ratings we just have visited with the rating agencies in the last few week. So they’re comfortable with where we are, they’re comfortable with the capital plan. As far as movement in leverage it should be pretty much where you’re seeing it. We are relatively neutral on a cash flow spend in the plan and what we have presented before them. So it’s really one of the sweet spots for the company right now. We are very strong in this area and with the agencies.

But is leverage going to stay consistent as earnings for our EBITDA drops but that I think is same right you’re not planning to pay down debt or is that wrong?

There is no particular debt pay down, and as you get into ’16 and ’17 I’m not really projecting out into that timeframe right now but for the near-term year and a half it is stable.

You have a follow-up question from the line of James Sullivan with Alembic Global. Your line is open.

Just a quick clarification, you guys have 13 Second Bone Spring wells that you talked about both in the ops reports of Q3 and Q4 that had a very good third year rates about 900 Boes, all 26 of those were done with a heavier sand loadings, is that right?

That’s correct.

Just want to check that out, so that’s a pretty significant corpus of data there.

And we are testing bigger sand rates beyond that James just to give you an idea we will have results for that in the future.

The other thing I had was you guys had a little bit of commentary in the ops report about the possibility of the EUR estimates going up if you guys could provide the type curves but generally done with increasing the IP rates, 30 day rates and I guess that could be interpreted as hedging your bets on whether you’re accelerating resource or adding it per well. Is it fair to say that you guys are seeing something with the longer data series that you’re seeing data that would suggest you that you are capturing new resource with the new completions?

We’re very confident in the Bone Spring that we’re going to increase the EURs. We’re just trying to figure out what the number is and get a little more production history before we do that. And Eagle Ford Tony talked about it’s always less certain it’s earlier on we think there is a possibility when we may bring up the EUR there as well but there is less certainty there than the Bone Spring.

There are no further questions at this time. I’ll turn the call back over to Mr. Thill for closing remarks.

Thank you, Courtney and we appreciate all of the questions. We appreciate all the interest in Devon and look forward seeing you on the road in the near future. If you have anything else that comes to mind don’t hesitate to contact us in the interim. Thanks much. Have a great day.

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