Welcome to Devon Energy's Fourth Quarter and Year End 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded. At this time, I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you, and welcome everyone to Devon's fourth quarter and year-end 2013 earnings call and webcast. Today's call will follow our usual format. I'll cover a few housekeeping items and then turn the call over to our President and CEO, John Richels. John will provide an overview of our 2013 results and his thoughts on the year ahead. And then Dave Hager, our Chief Operating Officer will provide an update on Devon’s operations. Following the operations update, we will turn the call back over to John to finish off our prepared remarks with a review of our financial results and to provide some specific guidance for the upcoming quarter and for the full year 2014. After our financial discussion, as usual we’ll have a Q&A session. We’ll conclude the call after one hour and a replay of the call will be available later today on our website. The Investor Relations team will also be available after the call should we have any additional questions. On the call today, we’re going to provide forward looking estimates for capital, production, price realizations and other important items for 2014. Later today, we will file a Form 8-K that contains our detailed estimates for the upcoming year. The guidance page of our website will contain a copy of the 8-K along with other significant forward looking estimates that we mention during the call today. To access this guidance, just click on the guidance link found in the Investor Relations section of the Devon website. The guidance we provide today includes plans, forecasts, expectations and estimates and they are all forward-looking statements under U.S. securities law. These are of course, subject to a number of assumptions, risk and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance. You can see a comprehensive discussion of the risk factors relating to these estimates in our Form 10-K. Also in today's call, we'll reference certain non-GAAP performance measures. When we use these measures, we're required to provide certain related disclosures. Those can also be found on Devon's website. At this point, I'll turn the call over to our President and CEO, John Richels.

Thank you, Vince, and good morning, everyone. 2013 was another year of strong execution and exciting change for Devon. Our oil focused drilling programs not only accomplished impressive oil production growth, but also successfully expanded margins and improved our operating cash flow. Additionally, we’ve taken some bold steps in a relatively short period of time to high grade our portfolio and improve Devon’s growth trajectory. We did this through an accretive Eagle Ford at our shale acquisition, an innovative midstream combination and the initiation of an asset divestiture program. Now let’s briefly recap some of the past year’s highlights in a little more detail. In 2013, we had outstanding success growing U.S. oil production, our highest margin product driven by our development programs in the Permian Basin; we increased our light sweet crude production in the U.S. to 78,000 barrels per day, up 32% compared to 2012. This highly profitable U.S. oil production growth is particularly impressive considering the large base of oil production that we are [drilling] [ph] off, a base that ranks Devon as one of the largest independent oil producers in the U.S. Our pursuit of oil production resulted in higher revenues and improved profitability as well. In 2013, company-wide oil revenue increased by 23% compared to the previous year and accounted for more than half of our total upstream revenue. This revenue growth combined with the strong focus on cost containment improved our operating cash flow in 2013 by 10% year-over-year, significantly exceeding Wall Street estimates. Looking beyond our reported results we also made some exciting portfolio changes at Devon during 2013. In October, we announced the strategic combination of our U.S. midstream assets with Crosstex to form EnLink Midstream. The creation of EnLink greatly improves the diversification, capital efficiency and growth trajectory of our midstream…

Thanks John, good morning, everyone. I’ll start my comments this morning with a brief review of reserves. Crude reserves for oil, gas and NGLs totalled three billion barrels of oil equivalent at year end. On the Euro side of the portfolio, reserves increased to a record 837 million barrels. During the year, our oil-focused drilling programs added 112 million barrels of drill-bit oil reserve additions and by drill-bit, I’m referring to extensions, discoveries and performance revisions. These drill-bit oil additions replaced approximately 180% of the oil we produced in 2013. This was largely driven by our continued success in the Permian and is particularly impressive given that 2013 was not a year of significant heavy oil bookings in Canada. On the gas and natural gas liquid side of the portfolio, not surprisingly 2013 was not a big year for reserve additions given our level of drilling activity. While we did see positive reserve revisions for higher natural gas prices, this was largely offset by negative revisions mostly attributable to the SEC five-year rule. Given our outlook for gas and NGL pricing relative to oil in the near-to-medium term, these negative revision represent a reduction in the lowest margin barrels within our portfolio and are of little consequence from a value perspective. In contrast, extensions, discoveries related to our oil-focused development activity generated $4 billion in future net cash flows year-over-year, more than offsetting the negative gas revisions and driving our overall PV-10 up year-over-year. All-in our F&D for the year came in at $22 per Boe. Excluding the negative revisions related to the five-year rule, our all-in F&D would've been approximately $18 per Boe. Another metric commonly tracked by analyst is proved developed F&D. This metric measures an E&P company’s ability to convert undrilled locations to proved developed reserves in…

Thanks, David. Our new Chief Financial Officer, Tom Mitchell joined us on Monday of this week and of course, a lot of you know Tom and I’d just like to take this opportunity to welcome Tom to the Devon senior leadership team. For those of you who don’t know Tom, I’m sure you’ll have the opportunity or many opportunities to get to know him over the next while. Since Tom has only been here for a couple of days, I’m going to cover the financial review today. But you can expect to hear from Tom in future quarters. So let me start with a brief review of the financial and operating results for 2013 as well as a bit of a commentary on our outlook for 2014. For those of you modeling Devon, we will file a Form 8-K after the call today that contains detailed first quarter and full year estimates for both our go forward assets and the divestiture assets. Estimates for our divestiture assets assume a full year of results. As we close on these divestiture packages throughout the year, we’ll provide updated guidance. So let’s start with production. Our top line production in the fourth quarter averaged 696,000 barrels of oil equivalent per day which was well above the midpoint of our previous forecast. Looking specifically at the oil side of our business, we again delivered excellent volume growth. Fourth quarter oil production averaged 177,000 barrels per day setting a new quarterly record and exceeding the top end of our guidance range by about 2000 barrels per day. Our most significant growth came from the U.S. where high margin, light oil production increased 32% year-over-year. Looking forward to the first quarter and assuming one month of contribution from the Eagle Ford properties, we expect our average…

Operator, we’re ready for the first question.

(Operator Instructions). Your first question comes from the line of Evan Calio from Morgan Stanley, your line is now open.

Your next question comes from the line of Brian Singer from Goldman Sachs, your line is now open.

Can you put your E&P budget in context versus 2013, $250 million moves out for the Canadian sale then we had $1.1 billion for the Eagle Ford, can you talk more specifically about where are you’re seeing the high grading what the total change in carry is and whether capitalized interest is included in your $4.8 billion to $5.2 billion?

Hi Brian, this is David Hager, I’ll take a stab at that. First off, capitalized interest and G&A is not included in the $4.8 billion to $5.2 billion. When you look at where we’ve high graded the program I’ll say roughly the Permian activity is about the same; we’ve obviously added $1.1 billion in Eagle Ford, the overall capital is slightly lower than we had last year, probably a couple of hundred million or so, so there is a little bit of reduction. The biggest reduction will be in our Barnett and Cana areas where we are drilling less of the liquids rich opportunities and we’re also spending less money in the Canadian Conventional as well, and then finally we have a little bit smaller land budget this year as compared to last year. So if you look in our key development area of the Permian it’s essentially flat, key oil development area essentially flat, the heavy oil essentially flat, the addition of a oil or condensate area in the Eagle Ford and cutting back in liquids rich drilling land and the Canadian Conventional.

Brian, just to close the loop on that let you know that capitalized G&A and interest are about $400 million and that those are included in the total capital when we say we intend to live within cash flow in 2014.

Great, thanks, is there a major change in the carry, you didn’t mention what your after carry numbers would be in a couple of the areas but do you expect a major cause in the carried interest?

No, it's essentially flat.

Okay, thanks. And then in the Permian, can you talk more specifically regarding the Bone Spring wells that are trending well above your type curve whether this is something that’s regionally concentrated or specifically area concentrated or whether that broader takeaway is across your Delaware position?

Well, I would say, we're hopeful and optimistic that it is broader takeaways across the entire Bone Spring’s position. What we've done, Brian is we have moved our activity from the North Western portion of our acreage position in Lea and Eddy counties expanding that to the South and Southeast in the same counties so to where we have additional acreage. We are starting to appraise those areas and what we're finding is that we're getting as good a well result if not better in the South and Southeast area as we had in the Northwest portion of our acreage position. Now we don't have as many wells there yet but so far the results are very encouraging. So that's why we're optimistic this inventory is going to continue to grow and frankly, we haven't booked hardly any PUDs, just being a little bit conservative there, we haven't booked hardly any PUDs on the basis of all the results that we've had there as well. So we're very optimistic that the results are going to continue and that we are actually going to be able to continue to grow the inventory as well.

Great. Thank you.

Operator, we're ready for the next question.

Your next question comes from Evan Calio from Morgan Stanley. Your line is now open.

Hey. Good morning guys. Can you hear me now?

Yes. Thank you.

Oh! Good. So first question maybe a follow-up on the Permian, that largely flat CapEx guide there but could you provide a rig and well count assumptions there? And then also a very strong horizontal Delaware Wolfcamp well in Ward county, just any other additional color around the well and costs, lateral length, and whether you’re targeting any other shallower zones here in 2014 or just going after the deeper formation? Thanks.

Yeah. And we're going to, again, as I said, our activity level is essentially flat this year at around $1.5 billion, total; we're going to be drilling somewhere around the order of 350 wells across the entire Permian position all while utilizing 22 to 23 rigs, they will vary a little bit during the year, somewhere on that order. As I said during the call about $900 million of that is going to be spent in the Delaware Basin, primarily drilling Bone Spring wells, about 130 Bone Spring wells, about 160 overall wells, we’ll have 11 to 12 rigs working on that play this year. I also mentioned the Midland-Wolfcamp where we are going to spent about $200 million, in that area we plan to drill about 150 wells -- 140 wells or so in the Midland-Wolfcamp Shale and maybe about 10 or so in the Cline. We'll also spend about $200 million in the Wolfberry drilling about 40 wells using a couple of rigs there; in the Central Basin platform we’ll have about 10 wells using a couple of rigs and then we'll spend about $150 million additionally for leasing facilities, OBO, and other type projects. So there is a, I think a pretty comprehensive breakdown of our $1.5 billion.

That's great. And any other in terms of the…

I'm sorry, on the Delaware…

Yeah.

On the Delaware Wolfcamp, we're very excited about it and so we think there is potential, we have a significant acreage position not only on the Texas side, but as you move up into New Mexico, we have some geological modeling and thoughts, I would say, about where we think the most prospective area is. I obviously don't want to get into lot of details around that, but we're encouraged by what we see, we're going to continue to drill a handful of wells this year to evaluate portions of our acreage position and see if we can get some additional opportunity to capture.

Great. Just secondly if I could on the CapEx. I don't know if you gave a midstream component, if that was within the guidance that was flat year-on-year, and I mean, how do you think about midstream capital spend when living within the cash flow, meaning should that be included now that there is a strong inventory of assets that can be tax efficiently monetized into EnLink post deal close?

Yeah. When you look pre-consolidation numbers for Devon, so excluding EnLink any capital expenditures that we will undertake are included in our segment that we intend to live within cash flow. And obviously a lot of the capital expenditures on a consolidated basis will really be EnLink’s capital.

Right. But that ultimately could be monetized through the MLP as you think about it going forward. Is that fair?

That is fair. And we’re spending about $400 million on completion of the expansion on the Access Pipeline and that’s clearly a potential dropdown item.

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

Good morning

Good morning, Arun.

I have a quick question, just kind of clarifying the oil guidance for 2014. Is it 198 to 216 MBOE per day – BOEs per day, pardon me, just on oil excluding Canada?

No, that’s oil including Canada, Arun.

Including or excluding Canada, just wanted to clarify that.

That’s including Canada, but not – exclusive of the barrels we’re selling.

That’s what I wanted to clarify.

Yeah, there’s some oil in that – there some minor oil properties in the Canadian asset package and that number that we gave you excludes those barrels, excludes that 15,000 – excludes about 15,000 barrels that we’re selling.

So that is the go forward company.

Thanks for clarifying that. And then John, you mentioned 20% growth on top of that for 15 would be your expectation as we stand here today?

Yes.

Okay, just wanted to clarify that.

Yeah, thank you.

The second point I just wanted to comment John, you talked about obviously a lower CapEx number for ’14 and you expect to see kind of 20% oil growth going forward. Do you expect to be able to do that within cash flows on a go forward basis?

Yeah, absolutely. The position we’ve put ourselves into Arun, is with these steps that we’ve taken over the past while, is we’ve got a company now that we can grow or we can grow oil on a multiyear basis at about 20% even after we’ve let gas decline because we’re not investing in gas properties or dry gas properties at this time. We’ll still see top line growth in the mid single digits on a six to one basis probably around close to 10% on the 20 to one basis if you want to look at it more in an economic equivalency basis. And we can do all of that while living within cash flows. So it really reflects the big step up in margin that we’ve been able to accomplish and the much more prospective and efficient asset base that we have today going forward.

That’s helpful. And my last question is I don’t know if Darryl Smette is on the line. I know [inaudible] is expected to come on line about the middle part of the year, just wanted to – Darryl could maybe comment on expectations on heavy oil differentials going forward after find [indiscernible] online.

Certainly, I’ll be happy to. You know, Dave mentioned in his comments and John also mentioned in his comments, over the last two and a half or three years we’ve had supply in demand get fairly low balanced for oil coming out of Canada. When I use the term demand, I’m talking about refining capacity, the oil capacity, pipeline capacity. We are starting to see now a speculation between that supply in demand as new refineries come online or have [indiscernible] and that is more heavy oil to that. And we’re also seeing increase in pipeline exploits coming out of Canada to the United States. One of those as you mentioned is planned in south. We’re planning it just outside of Chicago, for those of you who don’t know, it’s a pipeline that will move about 600,000 barrels a day from Chicago down to Kuching where it will interconnect with a couple of other pipelines and take oil to the Gulf Coast. The reason that is very important for us is about 9 million barrels of refining capacity exists in the Gulf Coast, about 35% of that is for heavy oil. So it provides excellent opportunity to move more heavy oil to the Gulf Coast market and that’s why we think as we go through the last part of this year, we actually could find South is going to be on the end of the third quarter, later fourth quarter. But we will start to see differentials become less volatile that they have been and that those differentials will continue to get narrow.

This is Vince. I want to correct something I said earlier. I said that we were going to spend about $400 million in 2014 on the expansion of the Access Pipeline. That’s actually our total Devon portion of midstream expenditures. And about three fourths of that is the Access Pipeline.

Thanks a lot, gentlemen.

Your next question comes from the line of Hsulin Peng from Robert Baird. Your line is now open.

Good morning, everyone. So the first question is also a clarification question. I’m sorry if I missed it, but could you give out the production associated with the U.S. non core asset sale that you are expecting this year in your guidance number?

It will be in our detail guidance and we did provide the production associated with the Canadian reserves and it previously provided -- okay.

I’ve got it here, so the production, maybe fourth quarter 2013 production. First on the Canadian conventional, that we just divested, it was a total of 88,000 Boe per day consisting of 412 million cubic feet of gas a day, 9000 barrels of NGL a day and 10,000 barrels of oil a day. The remaining assets that we’re looking at divesting in the U.S. and again this could vary a little bit depending on what we actually sell. But our anticipated assets sales would have production of around 57,000 Boe per day of which a little over 250 million or so will be gas, about 9000 barrels of NGL a day and 4000 barrels of oil a day.

Okay. Got it.

Did I gave what you wanted?

Yeah, that number is excluded from your going forward, that’s a going forward number.

That’s not in the new Devon or in the retained assets. And when we talk about new Devon or retained assets, that does not include that number.

Okay. Got it. And if you [inaudible] basis and also potential basis, maybe the tax basis or the assets in the U.S., this will trend out in this tax implication there potentially?

In the U.S., our tax basis is fairly low. As you can see that was in the case in Canada. We had a very high basis and we’re able to take advantage of several other opportunities to keep our taxes down. They’re very low number coming on Canada. Now, even though we have a low basis in the United States, these properties would be available for 1031 like kind exchange, that’s something that made a sense of the time.

Okay, yeah, now that will be good. And then my further questions, the first one is regarding the Jackfish 3. So I think you mentioned that the first oil is expected in late ‘14. So is it fair to assume, I guess, I’m just trying to understand the ramp to the 35,000 in 2015. How is that ramp shape, is it graduals that function, how should we think about it?

The way that these heavy oil projects work, we are going to start steaming later on this year within the third quarter. And it takes about a period of something like 16 months, 14 to 16 month to ramp up, to get enough heat in the ground, enough steam in the ground to really get that working. So that’s a typical ramp up and so when we talk about that ramp up in oil production, anticipate starting to steam this fall, you start to see an increase, the slight increase in oil production, then it continues to ramp up all the way through ‘15 and then from ‘15 onward, its pretty much running flat at 35,000 barrels a day.

Okay, so it is…

Think of it as a steady ramp-up, not a step function.

Okay. But the full -- the peak production is not expected until ‘16.

Probably late ‘15 or early ‘16 somewhere near.

Okay, got it. And then in this Woodford area, I thought the production growth was pretty good quarter-over-quarter, this quarter. And you also mentioned that you exceeded your exit rate. I was wondering if you have a new exit rate for 2014…

We didn’t catch that area of that. It’s at the Miss-Woodford, you’re talking actually.

Right. Miss-Woodford area.

Yeah, we had an exit rate around 16,000 in December, average about 14,000 for the quarter and exceeded our expectations of 15,000. We don't have an absolute exit rate for 2014, we are optimistic as some more 20,000 to 25,000 barrels a day. We’re still doing a lot of appraisal work out there and so there’s going to be variability. So the results probably somewhere on that order of magnitude.

Okay.

Okay. We got a lot of questions. So we’re going to move on to the last caller.

Sorry.

No problem, thank you.

Okay, thanks.

Operator, we're ready for the final, final question.

Your final question comes from the line of Charles Meade from Johnson Rice. Your line is now open.

Yes. Thanks for getting me in here guys. One quick question, I'm sorry to believe it this point, but John you said that the topline was going to be -- I believe you said top line is going to be 10% for a week in 2014 and let you know update, that is over the year as you saw some of those US assets, is that right?

Well, I think what we said is on a going forward basis, multi-year basis, we drill the oil at somewhere around 20% and topline on a 21 basis somewhere around 10%.

Got it. Okay. And then switching to your Eagle Ford. Can you talk a bit about, I know you haven't closed on the acquisition yet, but have you been able to engage with your partner there at all and do you have any thoughts about how you might try to perhaps change, how operations have been running there last year?

Yeah, this is Dave. Yeah, we've been able to engage with BHP quite a bit and of course we haven't closed on the transaction yet, but we have had numerous meetings with them, talking about how everything is going and how we might be able to help out with the partnership. I think the one thing in particular that we're going to really bring to the table, it is our ability to execute what you might want to call the machine. The ability to manage the large number of rigs and then actually bring those wells on production with -- in a very timely manner, that's something we're very good at. We have 35 plus rigs running in Barnett at one point and we've been very active with this unconventional plays for a long time. It's of course skillset and I think that's something that we're really going to bring to the table. We're very impressed with the technical work they are doing, I'll tell you that. So, we think we are going to have a good exchange of technical information, they are very open to listening to us, so we think it's going to be great partnership.

Thanks for that detail John.

Thanks, Charles. Well for [inaudible] I'm showing we're a little past at the top of the hour, but just before signing off let me leave you with a few key take away. First, we've taken some bold steps in a relatively short period of time to high grade our portfolio and improve the growth trajectory of our go forward business with our acquisition of the Eagle Ford, the creation of End link and the divesture of a Canadian conventional business as we talked a lot about today. We have an emergence with a formidable and balanced portfolio positions to deliver oil production growth around 35% in 2014 led by a 75% increase in U.S oil production. We are going to achieve this attractive growth without spending within operating cash flow and lastly, while the remaining exciting changes occurring at Devon, our approach to business remains the same. We will continue to pursue our top strategic objective and that is to maximize long-term growth in cash flow per share after adjusting for debt. So, we look forward to talking with you again on the next call. And thank you very much for joining us today.