Welcome to Devon Energy's Fourth Quarter and Full Year 2010 Earnings Conference Call. [Operator Instructions] At this time, I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you, operator, and good morning to everyone. Welcome to Devon's year-end 2010 earnings call and webcast. Today, we will follow our standard format. I will begin with a few preliminary items and then I'll turn the call over to our President and CEO, John Richels. John's going to provide the highlights of 2010 and his thoughts on the year ahead. Following John's remarks, Dave Hager, our Executive Vice President of Exploration and Production, will cover the operating highlights as well as our 2011 capital program. And then finally, Jeff Agosta, our CFO, will finish up with a review of the year's financial results and our guidance for 2011. At that point, we'll open the call to your questions. I'd like to point out that we have our Executive Chairman, Larry Nichols, and other members of the senior management team with us today for the Q&A session. As usual, we'll conclude the call in about an hour. And if we don't get to your question during the call, the IR staff will be around the rest of the day to take any follow-up. As always, we ask each participant to limit his or her question to one initial inquiry and one follow-up, and we'll attempt to enforce that. A replay of this call will be available later today through a link on our Home page. That's devonenergy.com. After the call today, we'll file a Form 8-K. That will provide our full year detailed forecast for operating items, as well as our capital plans for 2011. And the guidance section of the Devon website will contain a copy of the 8-K, along with any other forward-looking estimates that we mention on the call. To access that information, you just click on the Guidance link found within the Investor Relations section of…

Thank you, Vince, and good morning, everyone. Throughout 2010, we undertook the strategic repositioning of Devon by selling our international and Gulf of Mexico properties to focus solely on North America. The process has gone extremely well. And today, we are reporting some very good results, which reflect our continued commitment to capital discipline and cost management and as you know, ultimately, we are focused on maximizing our per share returns. We're emerging from the repositioning in a very enviable situation. The depth and breadth of Devon's North American property portfolio provides many years of visible economic growth and a good balance between liquids and natural gas. Our asset base underpins our confidence, that we can deliver strong growth in oil and liquids over the next several years from opportunities that we have already captured within our asset portfolio. Furthermore, we have one of the strongest balance sheets in the industry, and we're in a position to supplement our top line growth and enhance our per share returns with our stock buyback program. Looking now to some of the specific highlights of 2010. We entered into sale contracts for our Gulf of Mexico and international assets, with proceeds expected to top $10 billion, far exceeding initial expectations. Essentially, all of these transactions have closed with the exception of Brazil. In the midst of the repositioning, we generated outstanding results from our go-forward North American business. North American onshore oil and gas production grew to 619,000 barrels equivalent per day in the fourth quarter. That's up 8% from the year-ago quarter when we announced the repositioning. The repositioning also drove cost savings across several expense categories in 2010. This included general and administrative expenses, which declined 13%. Reported net earnings for 2010 were $4.6 billion or $10.31 per diluted share. That's…

Thanks, John. Good morning, everyone. Our growth in reserves and production reflect the outstanding results achieved with our 2010 capital program. We drilled 1,584 wells onshore in North America, including 1,493 development wells and 91 exploration wells. Almost all of the wells were successful. We exited the year with 71 Devon-operated rigs running. And today, at the height of our winter drilling program in Canada, we have 90 rigs running. Let's look now at some of our areas, area by area -- look at some of the area by area highlights. At our Jackfish thermal oil project in Eastern Alberta, our fourth quarter daily production averaged 22,200 barrels per day net of royalties. The Jackfish volumes that were curtailed in early December is a result of outages on the Enbridge pipeline system have been restored, and production at Jackfish is currently running about 30,000 barrels per day, net of royalties, the level we expect to average in the first quarter. More than three years into production, Jackfish continues to be one of the best-performing Side B [ph] projects in the industry as measured by both production per well and by steam oil ratio. Construction of Jackfish 2 is now complete, with total capital expenditures to start up projected to come in at just under $1 billion. Plant commissioning activities are underway, and we expect to begin injecting steam in the second quarter of this year. We expect to deliver first oil late this year, with production ramping up throughout 2012. Review of our regulatory application for Jackfish 3 is currently underway. Pending approval, we could begin site work around year-end, with plant startup targeted for 2015. Detailed engineering work continues, and we have all major equipment orders in place. Devon operates all the Jackfish projects and owned 100% working interest.…

Thanks, Dave, and good morning, everyone. Today, we will begin by looking at some of the key drivers that impacted our 2010 financial results and provide commentary on our outlook for 2011. As Vince mentioned earlier, we have reclassified the assets, liabilities and results of operations from our international assets and to discontinue the operations for all accounting periods presented. Our fourth quarter results from continuing operations represent just our North American Onshore business or in other words, the results of the repositioned Devon. However, it is important to note that our reported full year results from continuing operations do include a partial year of results from our now divested Gulf assets. Let's begin with production. For 2010, Devon's reported production totaled 228 million oil equivalent barrels. This includes approximately 5 million barrels of production from our now divested Gulf of Mexico properties. Excluding the Gulf production, you will find that our North American Onshore assets produced 223 million barrels during the year. This result represents a 3 million-barrel increase over 2009, which was driven entirely by higher oil and NGL production. Looking specifically at the fourth quarter of 2010, Devon produced 56.9 million equivalent barrels or approximately 619,000 barrels per day. This is about 6,000 barrels per day shy of our guidance range due to a number of minor operational issues, which reduced our fourth quarter production by approximately 11,000 barrels per day. These included volume curtailments attributable to the Enbridge pipeline outage, other third-party facility outages and delays in well completions. In spite of these curtailments, when compared to last year's fourth quarter production from our North American Onshore assets exhibited strong year-over-year growth of 46,000 barrels per day or 8%. Increased oil production from our Permian Basin properties and growth from our liquids-rich Barnett and Cana Shale…

Thanks, Jeff. Operator, we are ready for the first question.

[Operator Instructions] And your first question comes from the line of Doug Leggate from Bank of America.

My question is really about the rig count. Can you just elaborate a little bit more as to where exactly you're allocating rigs for the coming year? And I guess the key thing I'm interested is that I understand your focus obviously is on liquids, but where the liquids are is Canada, of course, where right now, we're looking at something like a $40 discount versus some of the international crews, and then on NGL’s where we're looking at a $60 discount. So can you just talk about how you see the actual strength of the liquids portfolio and what you might want to try or how you might want to try and address the apparent, maybe, disadvantage that you have versus some of your more international peers that are going to be seeing some of the more robust oil prices?

Dave, why don't you handle the rig count?

Why don't I handle the rig count right now. And we do have, right now, about nine rigs total working for the company. And let me just try and go through it quickly here. Too much detail, but in Canada, we have about 23 rigs working and of course, we're at the height of the drilling season in Canada. So that's high relative to what it will be for the rest of the year, but we have about 10 working in our thermal program. And those are drilling those stratigraphic wells. They're in Pike that we talked about. And then, we have another 13 deployed across the rest of Canada. The more liquids-rich ones will be about three in the Lloyd area there and then we're also testing some concepts, as I mentioned, some exploration concepts that are liquids-rich there. We have about 23 located in Cana that are primarily drilling the liquids-rich portion of the play and the extension of the play to the northwest from our core. We have 13 right now in the Barnett. They are concentrating on the liquids-rich portion. And four in the Granite Wash. We also go into our Texas Gulf Coast area. We have four rigs working in the Carthage area, around an area we have traditionally high return pud program that we're executing there, proved and undeveloped program. One in Groesbeck, one in North Louisiana and one in South Texas. And then particularly in the more liquids-rich and oil-rich area of the Permian Basin, we have 17 rigs working there. I detailed where those are located in the call pretty well. I think it's six -- and they move around a little bit. But it's roughly six in the Wolfberry, four in the Avalon Shale, three in the Bone Springs and four growing out of conventional targets. And then we have three rigs up in Wyoming, some of which we're testing our more oil-oriented concepts in Powder River Basin. We have one rig working and one should key [ph] as well. So that details it all. Vince, you want to talk about the second part of the question?

Yes. And I think your question was oil and liquids growth, how much of it was oil, how much of it was liquids and what areas it's coming from?

Vince, it's more about the realizations, because I understand the liquids focus but what I'm really looking out here is obviously, the world is going to change here, in the short term anyway. The incremental volume of those liquids is perhaps lagging some of the higher international phases. I'm just wondering if there's a change of focus that you can maybe bring to bear away from NGLs, maybe more towards the oilier plays, or just talk a little bit more about how you anticipate your relative benefit to the industry from your current liquids program.

Sure. Well, you used the word "disadvantage," Doug, and your observation is correct that currently, brand is commanding a higher price per barrel than North American crudes and obviously, NGLs' prices are depressed. I would point out that even in the current environment, our liquids-rich Cana and Barnett plays are in a better rate of return than almost anything in the Deepwater Gulf of Mexico or international arenas because of the long cycle times and the impact of production sharing contracts on returns. And that's in a depressed natural gas and liquids environment. I'd also point out that a lot of our growth is black oil. Our largest liquids growth areas in 2011 are the Permian and Jackfish. 3/4 of our Permian growth will be oil, not NGLs, or of our total liquids growth in the Permian will be oil and not NGLs. And of course, Jackfish, 100% of that growth is oil. So we are not changing our oil and NGLs mix during 2011. We anticipate growing them both and maintaining our percentage of oil, which is more oil than NGLs.

Doug, Larry Nichols. I might add one comment. When you think about disadvantage from one perspective or advantage from another, and that is we do not have the political risk in the United States and in Canada that many of the international plays have. As we see Egypt going through its turmoil and as that turmoil spreads through other parts of the world, we're really in an advantaged position because of the political stable countries that we're in.

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

Just sort of a follow-up question to that. Obviously, the [indiscernible] as well. Do you all have any kind of flexibility to move some of your volumes around to get there, for the most part?

This is Darryl Smette. And we have some flexibility, but not an awful lot of flexibility, quite frankly. As you know, most of our heavy barrels in Canada are sold in the U.S. market, mainly the refineries in the Midwest and the Chicago Minneapolis areas. And the oil that we produce in the Permian Basin, most of that oil goes to the local refineries in that area. Some of that oil is moved into cushion, but there is a lack of capacity getting oil out of cushion, which has in part contributed some of the differentials that we're seeing right now. But while we have some flexibility to move, oil around, that flexibility is fairly limited.

And the second question on the Niobrara. Can you talk about -- the Powder River Basin, I guess I'll call it, can you talk about what you drove so far and kind of some of the results you might be seeing?

It's a little early to talk about results. We just got our first wells down and are completing them. So I think, probably next quarter, we'll have a lot more to say on that.

Some of those first wells, are they going to be targeting the Niobrara or I mean, the Parkman, and is the frontier consideration as well?

Primary Niobrara and the Parkman with the early wells.

Next question comes from the line of Brian Singer from Goldman Sachs.

First, on the Permian Basin and the Bone Spring Avalon Shale, you talked about the rig counts that you have in both places. Are you or do you plan on drilling the Bone Spring on the same acreage that you're testing the Avalon? And do you have an updated view on the potential from each plate in EURs as that plays?

Where we're actually drilling the Bone Springs is a little -- not exactly the same acreage, although we think there is some overlap in the prospectivity, in general, that we're not drilling those in exactly the same locations. The Bone Springs, the first and second Bone Springs tend to be more up in New Mexico, a little bit to the north of where we're drilling our Avalon wells. And then the third Bone Springs located in Texas, a little bit to the southeast of where we're currently drilling our Avalon wells. So they are different areas. If you look at the Bone Springs, you want to talk about the EURs that we potentially have in there. We'd give those EURs on the order of 300,000 to 400,000 Boe, perhaps even a little bit better as we get down into the third Bone Springs. It looks like it's a little bit higher recovery than the first and second Bone Springs. The Avalon, we've said previously, around the order of 400,000 to 600,000 Boe per well and that's -- we're currently continuing to evaluate that and staying with that range.

And you do think there's overlap in prospectivity with that? Did I catch you? You said that.

Yes, we think there is overlap in prospectivity. We haven't actually drilled them on the same locations but we think the prospectivity overlaps, yes.

You mentioned in your opening comments that you're seeing a little bit more gas than you originally expected in some of your liquids-rich areas. Obviously, a 20% growth versus high teens growth is not that big of a difference, but can you provide a little bit more color where you're seeing that?

I think I'd say it has to do probably more with where we drilled in our initial wells in these trends versus necessary what the overall trend may be once we drill everything up. And so for instance in the Avalon, we have seen in the wells that we've drilled a little bit higher gas content and where we drilled our initial wells, although we're seeing some trends there that would indicate that overall, it's going to be probably within the range we'd thought. It's just not where we drilled our initial wells. And so that's what I think we're looking at.

Your next question comes from the line of Mark Gilman from Benchmark Company.

I wonder if you could give us some idea of what the yearend 2010 overall resource space look like versus the year ago on an apples-to-apples basis?

Mark, I think we're going to try to do a bit of a resource update later on in the year, and I'm not sure we can tell you exactly what that is. But directionally, our resource base has increased significantly. We've got more prospective resource in the Cana than we thought we have. Of course, we've added a lot in our heavy oil projects where we think we probably got another 750 million barrels net to Devon of recoverable resource with the addition of our Pike resource. And all of this work that we're doing in the Permian Basin -- I mean, these are all new areas, sometimes on lands that we had for a while because of their held by production. But we, of course, will know more about that. And then lastly, we've got a very significant focus, as Dave mentioned, on new ventures, both in Canada and here in the United States, and we're pretty excited about that. As Dave said, we'd added about 750,000 acres to, of course, 1 million acres to an already large HBP position. And that will, as we get the first results from that, that will significantly add to our resource space. So the short answer is I don't think we can tell you exactly what it is. But directionally, our resource base is getting larger over time.

John, would you say the overall resource space replaced 2010 production?

Well, yes, much more, dramatically more. And as you know, just the proved reserves that we added, we're more than twice our 2010 production. In fact, as we said, replace our 2010 production and all of the assets that we sold in 2010 as well. So the resource potential, like in addition to those proved reserves, would be many multiples.

My follow-up relates to some industry evidence of a possible Mississippian carbonate play in the Anadarko. Dave, can you talk about whether any of your land might be prospective for this, or whether this is something you might be looking at pursuing?

Well, we're looking at a number of new ventures, plays, and we're just not going to get into details of exactly which ones we're pursuing. But we're certainly aware of that play.

Your next question comes from the line of Scott Lomos [ph] from Simons & Company.

Just looking at the Permian, with the horizontal success you guys have had and other operators. Have you seen any constraining factors on the rig or completion side that might hamper future growth if the rig count continues to ramp up?

No, I wouldn't say that's a major constraint for us. We're able to access the rigs, the rig rates are going up somewhat. There's no question about that. But we have been able to access the rigs that we need in order to execute the program. Our constraint right now, I'd say, we think we're in good balance with the 17 rigs we have. We don't want to outrun the infrastructure. And frankly, we don't want to outrun the pace of our learnings from a technical perspective either, and that's probably more the governor than the actual availability of rigs.

And then just jumping over to the Barnett, I know you guys are planning on kind of holding production flat with 12 rigs at 1.2 Bcf for your day. Can we think longer term in terms of how long are you guys planning on keeping that flat and at what price would the Barnett become competitive, or you might think about increasing that rig count?

This is Vince. In the first place, the Barnett is competitive within our portfolio in the liquids-rich portions and that's why we are running 12 rigs there, to keep our production at plant capacity. The future will depend on the evolution of our view of commodity prices. We would probably be drilling more dry gas wells in the Barnett if we had a three-year view of $6 or better for average of Henry Hub prices. But it also depends on the other opportunities within our portfolio and how they compete for capital.

Let me just throw something out. I always find this to be a kind of a fascinating thing about the Barnett and just why you want to call it the asset. [ph] As Dave mentioned, we're going to spend about $900 million in capital this year in the Barnett. It's going to throw off that assuming $4.50 gas, it's going to throw off somewhere around $1.4 billion of cash flow, so $450 million or $500 million of free cash flow over our capital expenditures. And then, our Midstream business, which as you know has thrown off $400 million, $500 million a year is roughly 80% centered in that area. So there's another several hundred million dollars that's attributable to that. So it just shows you the tremendous economics that we're getting around this play, and we have many, many years of running room left in the Barnett.

Your next question comes from the line of Mark Polak with Scotia Capital.

First one, just on share buybacks. Look like the pace slowed a little bit in the fourth quarter. And just wondering if you could update us. It looks like you did about $1.2 billion so far. Obviously, lots of financial capacity, do you still see doing the remaining $2.3 billion throughout 2011?

This is Vince, again. I would point out to you that in the fourth quarter, we slowed down our share repurchases for the months of October and November as we finalized our capital budget and updated our outlook for commodity prices going forward. Then we were back in the market in a big way in December and then so far, in the first quarter of this year. When we announced the share buyback, we said we fully expected to complete it. However, we would continue to weigh our options and as the commodity price outlook changed and what was available within our portfolio changed, we would attempt to optimize growth per share by making the correct allocation between capital projects and share repurchases. While we were updating our view for 2011, we thought it was prudent to be out of the market. Now that we've set our 2011 capital budget and updated our outlook for commodity prices, we're in there pretty aggressively. I'd point out to you that at the $88 a share where our stock, I think, opened today or close to that, we're paying about $12 a barrel, which is down quite a bit because of all the reserves that we added at year end 2010. So we think on a relative basis, this is still a great buy, and we are on track to complete the repurchase program within the authorization period. And in the absence of some big change in expectations, we'd expect to complete it. John, do you have anything to add to that?

No. I think you've stated it well. Right now, it still looks like it's been sort of very good buy and I think it's a very prudent allocation of some of those divestiture funds.

Your last question comes from the line of David Tameron from Wells Fargo.

Let me ask two questions, Vince. But first, on the Granite Wash, was that Wheeler County and/or what formations are you targeting there?

Yes, that's in Wheeler County and we're targeting primarily what we call the Cherokee and the Granite Wash A there. We have also prospectivity in some of the deeper zones within the Granite Wash. To give you an idea, though, we have what we think is probably about 100 additional Cherokee locations that are operated and probably, about 60 non-operated and probably, a little over 100 locations within the Granite Wash A. And those are the two zones that we've been getting the results we talk about. We'll also have some lower Granite Wash locations, probably on the order of about 200 operated and about 250 non-op. We're starting to test some of those lower ones. They're probably not going to be quite as prolific as the upper zones, but we still think they could be very economic.

And then Vermillion basin, there's chatter that you guys are testing a liquids play out there? Can you comment at all?

We have tested a well out there. We're really not right to talk about any sort of detail, though.

Well, thanks, again, for joining us this morning. As Vince said earlier, our Investor Relations staff will be around all day, if you have additional questions. So give us a call, and we'll talk to you next quarter. Thank you very much.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.