德文能源 (DVN) 2014 Q4 法說會逐字稿

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.

(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'm Howard Thill, Senior Vice President of 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 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. 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. We sure hope that you 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'd 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 levers 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. Before we start, I'd ask you that -- to that 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.

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

Thanks. Good morning, everybody. John and Dave, congratulations on your respective changes in roles as you move through this year. If I may take [two questions] first of all, on the increase in the type curve on the Eagle Fords, I guess I was looking for some incremental disclosure on the rest of the Eagle Ford position, Lavaca, the Upper Eagle Ford inventory potential. Because the reserve life there, rather the drilling life, is still relatively short and in the current oil price environment, I'm just curious as to how do you think about that inventory as we go forward? 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 upped 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. You can see highlighted some increase in the type curve and in a few incredibly out -- 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 activities somewhat in the Eagle Ford. We've dropped down. We were thinking we were going around -- 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. We'll also continue appraising the Upper Eagle Ford. We're very encouraged with the early results that we see in the upper Eagle Ford thus far, 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 and the EURs 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 Lavaca County acreage. And that will be part of our go-forward program when commodity prices recover somewhat.

We still have Lavaca. It is there. Upper DeWitt County in the Lower Eagle Ford just keeps getting better. We still have the -- don't have the results from the Devon completions that we did here, it started coming online here at the first of the year. But these are from the revised BHP completions we think took us about 80% of the way to where we'd want to go with the completions on and that's getting significantly better.

The earlier results on the Upper Eagle Ford are encouraging. We just need to get more appraisal activity. I think overall it's positive. There are -- and there -- with the lower drilling 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 answer is a little quicker. Obviously, there's a lot of debate over how quickly and what scale of cost reduction the industry can expect in this lowered oil price environment. 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 ultimately what do you think it can get to by year end as opposed to the average for the year? I'll leave it there. Thank you.

Doug, your question was quick on the first one. My answer was long. It wasn't your fault. I'm going to turn it over to Darryl Smette. He's 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 some numbers. They're going to be in relationship to the cost environment we saw in the fourth quarter of 2014. What we have seen so far is a cost reduction on different phases of our CapEx, from drilling rigs to drill bits to OTG, 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 costs out of that system. Right now we are hoping that we can 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 efficiencies that we might gain from our operational people. That is just price related to our service providers.

So 25% would be the total down, just to be clear.

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

Good. That's really helpful. Thanks, everybody.

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 2015 versus 2014?

This is Dave again. Talking specifically in the Eagle Ford, we had about 150 wells that 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 had 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. 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 halve 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. 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 2015. So we're taking a measured approach at this in light of the current price environment, but we will be driving the inventory down.

Okay. That was good. Thanks. And a follow-up, I guess I'll wait for some details in the K, but any sort of flavor you can add to the -- for the 2014 reserves, sort of where the hits and misses or the highs and lows were as far as reserve credit you may or may not have gotten?

If you look at our 2014, some of the big pieces -- and you're right, you'll be able to get a lot more detail, but some of the highlights of that, I guess, were -- 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. 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, we -- a purchase of about 265 million barrels. We had revisions other than price of negative 65 million and that was essentially -- all of that and more was due to the five-year rule. So that's the key highlight. We think when we put it all together from an all-in F&D standpoint or drill bit F&D we had competitive metrics.

I guess I was sort of looking at in context of what you spent in 2014 vs 2013. Looked to be a bit more and with revisions -- you say even without revisions, looked to be about the same as the prior year, if there was any read through in that?

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 may be a little bit higher but it's still a -- the value equation make it is more than worthwhile. You still, from a returns standpoint, you still get much higher returns, but as you make the shift that we have to oil, oil F&D tends to be a little bit higher.

Okay. That helps, thank you.

The bulk -- as we've said, Subash, the bulk of that, or a big piece of that reserve additional is on the light oil side, which is our highest margin product as well.

Right. Okay. That would explain it. Okay, thanks much.

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

Good morning. And echo my congrats on the Management changes. If I think about the ability to ramp in the second half of the year and how you guys look at the 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 get some general framework and thoughts around that?

Yes. This is Dave again. There are a lot of variables that go into that equation and we're going to give you a fairly nonspecific 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 take-away capacity is, what the drilling results are, et cetera. It's hard to be too specific on that.

I'd say 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's no concern with drilling wells just to retain acreage, so we have all the flexibility. 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.

Okay. One follow-up on that. If I think about 2016, let's say. I know it's a 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 -- I guess does that set up a scenario where margins come in such that 2016 looks similar to what you would have done in 2013, 2014, just at a lower price band? Does that make sense?

I understand what you're trying to describe there, David. It's possible that's true. I think in that scenario, and again, there's a lot of variables go in, 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. Would you have to also, then, consider though, the cash flow for the Company and do you -- and the desire do we want to stay with a strong balance sheet. Obviously the $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've talked about, we have a lot of productivity gains that we have been able to get here through the improved completion design, so I think at the well level, you could 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.

Okay. That's helpful. Thanks.

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. The 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 do you do it interactively?

Tony Vaughan, our Head of E&P, is in the room. We're going to turn the call over to Tony. He works probably the closest of any of us with BHP and we'll have him answer that.

Hi, Bob. This is Tony. Appreciate your question. We do work very closely with BHP. We actually have some of our engineers seconded into the BHP office so it's a very close working relationship. As you know, we were running about 15 rigs in DeWitt County, three in 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 1,600 BOE, 1,650 BOEs per day but the average for the last quarter was all the way up to about 2,100 BOEs per day. 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, bringing all our technical skills to the table and we just jointly worked that process.

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

That carry is fungible, so we can move it. If you remember, the original was the setup in five different plays and we can use that carry up in the Rockies as well. That's our intention, is to use the rest of it. The JV money -- the sign-up pack is in the Turner and below but are not in the Parkment. We'll be drawing some Turner wells and that will use up that remaining JV carry. We think that's the most efficient place to do it.

Got you. Thanks.

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

Good morning, everyone. I'm wondering if -- on the NGL front, the guidance you guys gave for pricing surprised me a little bit. I'm wondering, from your vantage point, as both a producer, but also operating EnLink, if you can talk about how you see that market evolving over the course of the year?

Yes, this is Darryl. Obviously, NGL prices really have taken a hit, starting a couple of years ago, but just in the last three or four months, that has deteriorated even further. There's 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's come on the market. That is included virtually all the products, but primarily ethane and propane.

Over the last few months, what you've seen is a deterioration in the propane price and that has been caused by a couple of different things. Number one, the increase in supply but the middle part of 2014 and earlier in 2014, we were able to export a 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 -- let me just add to that, what we had was a very mild winter in some parts of the country, especially early on in November and December, 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 is going 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 obtain 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-chem plants come on stream. Even though there are some export facilities that will be available, at least under water coming in the next year or two, in the current environment we don't see that helping a whole lot. We think ethane is going to continue to be under pressure for the next year and a half or so. We think propane, as we go through the summer months, may improve but at least in the near term that doesn't give us as much hope either.

Got it. That's a lot of great detail. I'm sure some of the people on the call up in the Northeast are wondering about that mild winter you're talking about.

(Laughter) Yes.

On a different front, your thermal oil in Canada, can you talk a bit about how that asset -- I know the operational performance looks great. I wonder if you could talk in a more broad sense how that asset looks in your portfolio now and if you -- how it compares to your light-tight opportunities, particularly with the outperformance but also I know there's 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 which will help to ramp that production up through the end of 2015 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. 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. We're in an area with Jackfish, and Pike, frankly. Our neighbors there are Synova's Christina Lake and Meg, and we are in, really, what appears to the sweet spot for oil sands development in Canada.

We're not expending 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 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. It's something you have to take a bit after long-term view on but it still provides at a, even at WTI prices where they are today, a pretty good rate of return on a cash going forward basis.

Got it. Thank you for those thoughts, John.

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 cost per BOE appears to be rising a bit in 2015 relative to 2014. Can you talk to what is driving this and if you see, or have baked in, cost deflation opportunities?

I may start off on the LOE side here briefly and hand it over to Tom Mitchell to talk about on the G&A. 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. If you remember in part of 2014, we still had the conventional gas assets in the Canada, as well as the non-core gas assets in the US. They contributed to the overall number for 2014. So it's just a shift of the portfolio. In a normalize price environment, you're 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 more specifics probably on that and also on the G&A side.

Brian, on G&A, first of all, you got to remember that the reported volumes are down year on year when you take out the non-core assets that had been divested, so that's part of it. We do have some increases. You have got a full year of EnLink in there and EnLink is up a little bit. And in addition to that, and this is really positive and you're seeing 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 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're 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.

Okay, great. That said, that's helpful. 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've 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? What pace is that moving at relative to what you're seeing in on-shore US?

Brian, you're absolutely right. We are see some costs. What we're doing at Pike now, as we 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 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.

That makes -- as you know, 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 have scoped out the costs more towards year end. 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. 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 energies, and Alberta Clipper and Kinder Morgan and the rail capacity. All of those things that go into determining a differential.

We're going to get a 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.

Great. Thank you.

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

Hi. I actually wanted to go back to a comment made earlier about 2016 and your willingness to outspend cash flow. I was wondering if your hedges roll off in 2016 and the current strip price proves 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, do you have some level of comfort to outspend cash flow given your ability to monetize midstream assets to EnLink?

Michael, the -- certainly. The assets that you're talking about -- our returns in the Eagle Ford and in the Permian are very high and could certainly maintain that. 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 terrific position to take advantage of that, because of our strong financial position and because of all of the financial levers that you have talked about. Our plan is, as we look into the future, our plan is to live pretty close to cash flow but we've got a whole lot of other financial levers we can take advantage of if we felt the time was right and the circumstances at the time were right.

Okay. That's helpful. The last question I guess would be sort of around your hedging strategy. Given the high rates 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? 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. It's -- we do that just as a matter of prudence. Even having a strong balance sheet and having the financial leverage, it's just to ensure some level of cash flow every year. That's our general philosophy.

Now, we haven't been layering in a lot of hedges for 2016 at these prices because we believe the price is going to be higher in 2016. What we typically try to do, although we have swapped some volumes, we typically try to do it on callers where we can lock in a -- 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 have a change of view in the future.

The other thing that you always have to remember is, and we always try for keep in mind is, that when we do lock in the price side, that doesn't lock in the cost side. You're only locking in half of the equation. 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 that -- in our hedging decisions.

Great. Thanks for the color.

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

Good morning, guys. Just wanted to go back to a topic, actually, from a minute ago about 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, Cana especially. Obviously, the NGL Y-grade parallels kind of a bigger part of the economic proposition for those wells. How do you think about that? And then how is that affecting well economics, your generally kind of poor view of the NGL market? I know you have a bigger asset there now. So I'm not sure we should think of the $400 million as an increase in spending, but just any color you have on that.

Well, we have a very deep inventory of development opportunities that we're pursuing in the Cana field particularly. Not to mention now, the Meramec that is -- 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're in a number of non-operated Meramec wells that were oil oriented in the past year. 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 improved 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 content from around 3.5 million pounds of sand, around 6 million pounds of sand, or around from 700 to 1,200 pounds per lateral foot. We're, frankly, testing up over 2,000 pounds per lateral foot now. We may see even further improvements by the size of the type curve improvement we already described to you. So, that carries the day. We have baked these lower NGL prices that Darryl described into our rates of return. Bottom line, with the improved completion techniques that we're seeing, these wells compete well with the other opportunities we're funding this year because of those improved completion designs.

Okay. That's great. Thanks for the detail there. 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 field, but about optimizing performance on base production. I think you had, had some acid jobs you were doing out there and have shown some really nice upticks there. Can you give a rough -- and I know it would have to be rough -- Company-wide base decline estimate? That can either be net or not net of whatever maintenance efforts you guys are undertaking. I know you're doing something in the Barnett, too.

James, this is Tony Vaughn again. Our base decline, just overall for the Company, without CapEx is roughly 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've focused on line pressure reductions in areas like the Barnett and Cana. As you mentioned, we've worked on some chemical jobs in Cana that really had a strong boost in our rate and had a major rate impact in 2014. 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 2014, was probably one of the primary reasons for our outperformance over expectations.

I think there's a renewed vigor. We've really segregated our work force into a couple of different areas so we have a 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 well bores that we operate.

Let me add just a little bit to that, too. I often get asked when I'm out meeting with investors, why are we doing -- is this the new Devon? Why are we doing so much better operationally? And Tony is actually, probably even if anything, he's underselling the transformation that's taking place internally to Devon 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 we, 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 do we need to do to transform our operational performance? What you're seeing today is the results of that effort. 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 from the long-term asset management.

We've added project management skills. We have a 24/7 well control center where we manage all the operations of all our wells. We have SCADA operations. We have computerized operations in all our field offices where we remotely monitor the production of all the wells. I can go on with several other things, but I think that's what gives us confidence, is the tight performance 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. We're going to continue getting even better.

Thank you. That's a lot of great color on the base maintenance. I appreciate it.

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

Good morning, guys. Thanks for taking my question. 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 2015 versus fourth quarter 2014 of, is it a 10% improvement? Are there any particular areas where mud motors or frac equipment was less reliable and now that the industry is slowed down, you'd see a bigger improvement in just that efficiency side as we head into 2016?

David, this is Tony Vaughn again. I think what you're describing is well within our expectations for as we go through 2015. As Dave mentioned, we're putting a lot of thoughts into, and a lot more granularity into, all of our well bore designs. We're really trying to drive out efficiencies, using project management skills to manage costs, to stay on schedule. We're starting to see the benefits of that right now. We've incorporated some stretch inside of each of our business units for the execution part of our work. So, I think the 10% 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 in some of these appraisal areas, such as the Lavaca County and also in the Delaware. All that will come to -- will pay off dividends here, probably in the second half of this year. So I think the 10% that you described is probably well within reason.

Okay. And so as we think going into 2016, just kind of modeling, the increase in wells at this rig count before you even think about ramping rig count is reasonable. That's cool. The other question, and just wanted to make sure I was understanding what you said on the LOE front, that you haven't factored in any cost savings. Not putting words in your mouth, but again, kind of the same 10% CapEx reduction that you've built in. I don't see any reason why some of your maintenance and kind of base LOE couldn't come down that same amount as we go into 2016. Is that a reasonable framework?

You know what, David, we've put some challenge to our business units. Cost containment is going to be a really driving force inside of 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 talked about today.

I do think west 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 costs, barrels in places like the Delaware. So we're working that. Got a lot of focus on that as we just described.

Just one last one. I'm assuming you don't want to give an expectation for an exit rate for production at this point for 2015?

David, I don't think -- we're not focused really on the -- giving an exit rate, but suffice to say, our production stayed pretty strong through the year. We have a pretty good bump in the first quarter and then we're -- it holds pretty steady after that throughout the year. We put ourselves into really a great position with a ton of flexibility as we move into 2016 which I think is really the important part as well.

Thanks, guys.

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

Good morning, gentleman. I wanted to first ask you a question on the Eagle Ford and perhaps maybe understand to what level kind of the new completion design is driving the improved 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 materials of the new completion design versus the old one.

Tony can get a little more specific here but in general, the wells that you saw, Arun, in the fourth quarter were the results of a revised design that we worked with BHP on that I generally characterize as probably somewhere around 80% of where we would like 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're 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. The type curve improvement that you're seeing I think is in 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 nine, ten months, which is approaching a similar design to Devon. 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 we pumped on the 28 wells that we worked on in DeWitt County have any incremental benefit in that. I think overall we're starting to see good collaboration between the two companies trying to take the best from both.

I'd also mention to you that some of the science that we're doing, especially in Lavaca County, is very unique. We've run fiber optics. We've drilled vertical well there taking 240 feet of core, doing a lot of seismic work, microseismic work, trying to have a really good understanding of what delivers value on the completions in the Eagle Ford. 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 that have taken a really, I think, a really eloquent approach to managing bottom oil pressures and rate. We're seeing the type curves move up and exceeding performance in that. We're waiting to see if there will a corresponding improvement in the expected ultimate recovery per well. I think that could come, but we need a little bit more data to understand that better.

Thank you for that. And my follow-up question is just regarding future potential drop-downs to EnLink. I guess you guys highlighted in the ops report about expecting to do the Victoria Express pipeline sometime in 2015. I was wondering if you could maybe give some more details around that. 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?

Arun, what we talked about with Victoria Express is potentially dropping that down sometime 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 and making that decision, that will come into play. But we always talked about the drop-down on access probably being late in 2015 or maybe even moving over to the beginning of 2016.

Okay. Sounds like in the next year or so?

Yes, sir. I think we're -- that's what we're looking at right now but there are a lot of moving parts right now so we'll have to see if it works out that way. That's currently what we're moving towards. Now, whether we get all that work done and whether it all pans out exactly the way we think will remain to be seen. But what we always talked about is potentially doing it in the latter half of this year, early in 2016.

Thanks, guys.

Your next question comes from the line of John Herrlin with Societe Generale. Your line is open.

Hi. Two quick ones. In the US 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 rules. Is that the case for the oil in the US?

John, just -- Tony can answer that. Sorry, John. That was largely -- the five-year rule was largely related to gas.

I figured.

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. But mostly as John had mentioned, these were mostly gas write-offs associated with the five-year rule.

Okay. That's fine. EnLink bought the Coronado system in the Midland basin. Darryl, how are you configured for the Delaware side in terms of GTP? You have adequate infrastructure at this stage?

Yes, John. Just to kind of paint the background here, I think we've mentioned this before but a lot of the acreage Devon has in the Permian Basin is acreage that we've acquired over time. 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, it is available and their facilities closed. They are certainly a party we talk to all the time.

In terms of the facilities that are third-party facilities, we have issues every now and then close to the wellhead. Have to put in different types of facilities. That kind of ebbs and flows and depends on the performance of the wells generally. So when we are seeing some really, really good results from some of the wells when 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 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.

Great. Thank you.

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

Hi, guys. Just a quick question on leverage. Where do you see that going? What are your sort of targets over the next, call it, 12 months? And then related to that, your ratings as well? Then what's sort of the plan to achieve whatever those targets are?

Yes, this is Tom. We're pretty solid in our ratings. We had just have visited with the rating agencies in the last few weeks. 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 are seeing. We're relatively neutral on a cash flow spend in the plan and what we presented before them. So it's really one of the sweet spots for the Company right now. We're very strong in this area and with the agencies.

But is leverage going to stay consistent as earnings -- EBITDA drops but that is I think saying the same, right? You're not planning to pay down debt. Or is that wrong?

There's no particular debt pay-down plan. As you get into 2016 and 2017, I'm not really projecting out into that time frame right now, but for the near term, 1.5 years, it's stable.

Okay. Thanks.

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

Hey, guys. Just a quick clarification. You guys had 13 Second Bone Spring wells that you talked about both in the ops reports of Q3 and Q4 that had the very good 30-day rates above 900 BOEs. All 26 of those were done with the heavier sand loadings. Is that right?

That's correct.

Okay. Great. Just wanted to check that out. That's a pretty significant corpus of data there.

We are testing bigger sand rates beyond that, James, just to give you an idea. We'll have results on that in the future.

Great. Great. The other thing I had was, you guys had a little bit of commentary in the ops report about the possibility EUR estimates going up. You guys have revised the type curves but generally done it with increase in the IP rates, the 30-day rates. 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 a longer data series, that you're seeing data that would suggest to you that you are capturing new resource with the new completions?

We are very confident in the Bone Spring that we are 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. In the Eagle Ford, Tony talked about, is less certain. It's earlier on. We think there's a possibility we may bring up the EURs there as well, but there's less certainty there than the Bone Spring.

Great. Thanks, guys.

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

Thank you, Courtney. We appreciate all the questions. We appreciate all the interest in Devon and look forward to 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.