Welcome to Devon Energy's Fourth Quarter and Full Year 2011 Earnings Conference Call. [Operator Instructions] This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you, operator, and welcome, everyone, to today's Year-End 2011 Earnings Call and Webcast. I'll begin today's call with a few preliminary housekeeping items and then turn the call over to our President and CEO, John Richels. John will provide an overview of our 2011 results and his thoughts on the year ahead; then Dave Hager, Head of Exploration and Production, will cover the operating highlights and the details of our 2012 capital program. And following that, Jeff Agosta, our Chief Financial Officer, will finish up with a review of our financial results. We'll conclude with a Q&A period, and as usual, we will tend to hold the call to 1 hour. Also with us today is Larry Nichols, our Executive Chairman, and other members of the Devon senior management team to help with the Q&A session. A replay of this call will be available later today through a link on our homepage. In today's call, we'll be providing high-level guidance for 2012 capital, production and certain operating items. And as is our practice, after the call today, we will file an 8-K with all the detailed estimates for production by product category and geographic region, operating expense items and so forth as well as expected realized prices relative to benchmark oil, gas and NGL prices. The 8-K will also provide additional details of our 2012 capital plan. Please note that all references in today's call to our plans, forecast, expectations and estimates are considered forward-looking statements under U.S. securities law. And while we always strive to give you the very best estimates possible, there are a lot of factors that could cause our actual results to differ from these estimates we're providing. A discussion of risk factors related to those estimates can be found in our SEC filing, that is, our 8-K that we'll file later today. Also in today's call, we will reference certain non-GAAP performance measures. When we use these measures, we're required to provide certain related disclosures and those are available on the Devon website. Before I hand off the call, I want to officially announce that Devon will be hosting an analyst event in Houston. This is going to be half-day format on the morning of April 4. We'll provide an overview of Devon's corporate strategy, an update of the company's resource potential and inventory and provide an in-depth operational review of our key exploration and development projects. Invitations will be sent out in the next week or 2, I just wanted to let you know to save the date. Again, that will start the morning of Wednesday, April 4, at about 8 a.m. in Houston. With those items out of the way, I'll turn the call over to John.

Thanks, Vince, and good morning, everyone. 2011 was another outstanding year for Devon. We delivered strong financial results driven by the solid execution of our operational plans and the very successful completion of our strategic repositioning. Net earnings climbed to an all-time record $4.7 billion for the year. Fourth quarter adjusted net earnings totaled $1.55 per diluted share, exceeding the First Call estimate by $0.07. Cash flow totaled $6.5 billion for the year, and coupled with the final proceeds from our strategic repositioning, cash inflows reached nearly $10 billion. In November, we concluded our $3.5 billion share buyback program, completing the repurchase of 11% of our outstanding shares. And I'll remind you, in total, over the past 8 years we've reduced our share count by over 20%. Production from our onshore North American asset base grew to an all-time record of 240 million equivalent barrels in 2011. Fourth quarter production increased 10% over the year-ago quarter, driven by an impressive 21% increase in oil and liquids production. Record production from each of our 4 core development areas, that's the Permian Basin, Jackfish, the Barnett and Cana, contributed to this strong liquids growth. In 2011, we continued to assemble high-impact positions across 5 oil and liquids-rich new venture plays. Subsequently, we entered into a joint venture with Sinopec, whereby they will invest $2.5 billion in exchange for 1/3 of our 1.4 million net acres in these plays. And finally, excellent operating performance translated into another strong year of company-wide reserve growth, boosting year-end proved reserves to an all-time record 3 billion barrels equivalent. Looking more closely at our 2011 reserve activities, our drill-bit reserve additions, that's extensions, discoveries and performance revisions, totaled 386 million barrels and replaced 160% of our production for the year. With our 2011 program focused on oil…

Thanks, John, and good morning, everyone. I'll begin with a quick recap of 2011 capital expenditures for our exploration and development activities. E&P spending was $1.9 billion for the fourth quarter, exceeding the high end of our guidance range by approximately $400 million. This resulted from 2 opportunistic acreage acquisitions identified by our new ventures group that we closed in the fourth quarter. First, we purchased an additional 125,000 net acres in the Ohio Utica. A portion of those expenditures will be reimbursed through our Sinopec joint venture agreement. Second, we acquired undeveloped acreage in a promising new oil opportunity that we're not yet ready to disclose. As John mentioned, in 2012, we will continue to pursue acreage acquisitions in an opportunistic manner to build significant positions at reasonable costs. Shifting now to our fourth quarter operating highlights and 2012 plans, starting with our thermal oil projects in Eastern Alberta. Our fourth quarter daily production at Jackfish 1 averaged 31,400 barrels per day, net of royalties and continuing its excellent trend, the continuous trend of excellent plant reliability and efficiency. At Jackfish 2, we exited the year producing approximately 14,000 barrels per day, net of royalties. Production at Jackfish 2 will continue its ramp-up throughout the remainder of this year. In early December, we received regulatory approval for our third Jackfish project and began site clearing in January. Although field construction will not begin in earnest until spring once the land dries out, we are roughly 20% complete with the project as a result of our decision some 18 months ago to place orders for various long-lead-time components for the project. Plant start-up for Jackfish 3 is targeted for late 2014. At Pike, our SAGD oil sands joint venture, this winter's appraisal program is underway and should confirm the resource…

Thank you, Dave, and good morning, everyone. Today, I will take you through a brief review of our financial and operating results for 2011 and provide commentary on our outlook for 2012. Starting first with production. For the full year of 2011, production came in at the top end of our guidance range at 240 million equivalent barrels or approximately 658,000 barrels per day. Our 2010 results included production from the Gulf of Mexico up to the point of sale, which we completed in the second quarter of 2010. Excluding the Gulf, our production increased 8% in 2011 driven by an oil and natural gas liquids growth rate of nearly 16%. Fourth quarter 2011 production was very strong, averaging 680,000 BOE per day, exceeding the upper end of our guidance provided in the previous earnings call by 5,000 barrels per day. This impressive result represents a top line production growth rate of 10% over the fourth quarter of 2010 or an 18% growth rate on a per share basis. Once again, excellent execution in our liquids-prone development regions drove our strong quarterly performance. In total, our company-wide liquids production was 238,000 barrels per day, up 21% from the year-ago quarter. In 2012, we expect an increase in oil production of more than 20% to drive overall production growth of about 6% to between 253 million and 257 million barrels for the year. This year-over-year oil growth will be driven mostly by the ramp-up of production from the Permian Basin and our Jackfish 2 project. We will also continue to exploit liquids-rich gas opportunities within our portfolio, increasing our 2012 NGLs at double-digit rates. As we focus our activity on oil and liquids-rich gas opportunities, we expect that our dry gas production will decline slightly. Looking specifically at the first quarter…

Thank you, Jeff. As you can see, our 2011 results reflect our disciplined approach to our business. In 2012, we will continue to execute our strategy by delivering oil and liquids production growth of roughly 20%, driving our production mix to 40% oil and liquids by year end, by continuing to bolster our future growth through accelerating our exploration activity and opportunistically adding acreage in new oil plays and by maintaining our position as a low-cost producer, allowing us to deliver some of the best full-cycle returns in the peer group. As we've said many times in the past, we're fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our growth per debt-adjusted share. This approach places Devon in an advantageous position to deliver competitive per share growth in any environment. And at this point, we'll open the call up to your questions.

[Operator Instructions] And with that, we're ready for the first question.

[Operator Instructions] Your first question comes from the line of Scott Hanold from RBC.

Could you talk a little bit about what's happening in the Barnett Shale? It sounds like overall production was up, but more of it's liquid. Are you starting to see some of the dry gas production turn, or is that going to happen later in the year? And remind me again, you've got 12 rigs running, you're going to drop 2? And how many of those will be actually in the dry gas area?

Let me make a general comment about the number of dry gas rigs we have working in the company: 0. We have no rigs at all drilling dry gas opportunities in the company. Everything we're drilling is liquids-rich or oil. And specifically in the Barnett, even with this, we do anticipate, because there is associated gas with the liquids-rich plays, that we are going to continue to grow the gas portion of the Barnett as well as the liquids-rich. We anticipate the total equivalents to go up, including the liquids-rich, by about 10% this year.

I might add to that. Since we did have, from years ago, many dry gas wells drilled there, and now we're focused entirely on the liquids-rich, the rich is shifting to become -- the mix of overall production is becoming more liquids-rich with this year's program.

And we still have 2,500 to 3,000 locations in the liquids-rich. And at the current rate we are drilling, the 350 to 400 wells a year, you can see we have a very deep inventory in the liquids-rich portion of the play.

Okay, maybe I misunderstood. I thought I heard a comment that the dry gas is going to decline by the end of the year for Devon. Did I mishear that?

That is company-wide because we're allowing some dry gas areas to decline. Company-wide, our gas production will be flat to down a little. It's just that in the Barnett, we will continue to grow gas production by drilling in the liquids-rich portions.

Okay. And for my follow-up. In the Permian Basin, obviously, things look like they're going pretty good there. Is there going to be any kind of constraints in the system over the next couple of years that you guys kind of envision for industry or Devon as a whole because of the activity increases there?

Yes, this is Darryl Smette. As you know, right now, there is constraints as it relates to NGL takeaway capacity in the Permian Basin. However, industry is eliminating those restrictions with 2 pipelines that are being currently built that should be on stream, the first one in the first quarter of 2013 and the second probably the second quarter of 2013, that will add about 500,000 barrels of NGL capacity and move the NGLs down to the Gulf Coast. So we are seeing some restrictions as an industry in the Permian right now and that should probably continue as we go through 2012 but should be eliminated early in 2013.

Your next question comes from the line of Dave Kistler from Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Following up a little bit on the last question with respect to potential infrastructure constraints. With the growth you guys outlined in the Permian on the liquids side, in the Cana-Woodford, Barnett, looking at your success in the Miss and current IPs in the Niobrara, can you match up for us just where processing capacity is for you guys in each area to basically help us understand if it'll be sufficient to the growth drivers you've outlined?

On the Permian -- this is Darryl again. In the Permian, virtually all -- not all but a large portion of our acreage is already committed to third-party midstream companies who have existing process facilities in the Permian and they are either in the process of expanding those or building new processing facilities. So that process is ongoing and that should right itself at the same time we have the NGL takeaway capacity. As we look at Cana, as you know, we have, the Cana plant is operational currently and extracting natural gas liquids. And we have firm transportation to move all of those natural gas liquids down to Mont Belvieu for processing and not up to Conway, where you're seeing a significant discount to Mont Belvieu pricing. In addition to that, we are currently expanding our Cana plant, and that will become operational, right now, we think, second quarter of 2013, it will add about 150,000 Mcf of capacity to Cana. As we look at the Barnett, we currently have 650 million a day of processing capacity in our Bridgeport facility. We are also in the process of expanding that plant by about 150 million a day, and that'll become operational, we think, the fourth quarter of 2012 or the first quarter of 2013. David W. Kistler - Simmons & Company International, Research Division: Great. That's very helpful, I appreciate it...

Dave, just a general comment there. We obviously work very closely between the drilling side of the business and the ability to transport it and so we tailor all of our activity and make sure that we are not conducting drilling activity, that we can't move the product at a good price. So that's, we've addressed that in all of our capital program. David W. Kistler - Simmons & Company International, Research Division: Great, appreciate that clarification. And then as a follow-up, with the stock buyback at least temporarily off the table and a number of assets coming up for sale in the Permian, how do you guys think about maybe potential acquisitions, going forward and kind of put that into comparison to, obviously, a proved reserve level that would be incredibly competitive on a dollar-per-barrel reserve metric versus an acquisition?

Well, Dave, it's John. As you know, when we look at these opportunities, we're adding a lot of opportunities and through some ground floor, grassroots leasing. That's obviously the most attractive to us if we're adding it in the right places because we bring it in at a very low-entry cost. We can control the amount of a royalty that we're going to pay and it's really important for us when we -- because we've got a deep opportunity set. It's really important that anything we bring in will compete well against the opportunities that we already have in our opportunity set. Otherwise, we're not adding value for our shareholders. So when we look at these other opportunities for acreage acquisitions, we have to compare them to the opportunities that we're adding through our grassroots leasing efforts, which we're pretty excited about. In the future, as we look at purchasing stock, I think we've had a pretty good track record over the years of buying stock when times are right and following through once we make the commitment. And what we try to do there is to stay very disciplined, to understand our asset base and to compare the repurchase of stock against the injection of more capital into our existing asset portfolio. And we try to do it on the basis over a 3- to 5-year period of what will add the most cash flow per share, adjusted for debt. It's really important that we keep focusing on that. And so those are the kind of considerations. I think the fact that we're taking a breather right now from our share repurchases should give you a pretty good idea of how excited we are with the opportunities that are in our portfolio for the next few years.

Your next question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

I've -- my first question is really going back to the production growth numbers, John, if you could help us understand a little bit about what's going on with the gas side. In order to allow the gas to decline a little more, I was under the impression you really weren't drilling any dry gas in 2011, at least the majority of the CapEx was going on liquids, so are you actually choking back wells, or are you doing anything a little bit more proactive on some of your dry gas production? So if you could help us a bit there. And I have a follow-up, please.

No, we're not at all. The only reason that our gas production has been staying up at all is because we're drilling in liquids-rich gas areas. So in the Cana, the core areas of the Cana, for example, where we have terrific liquids component. In the core areas of the Barnett, we have high liquids contents, but it's producing some gas. In the other areas, the dry gas areas like the Rockies and our conventional business in Canada, East Texas and a bunch of other areas that are dry gas, we haven't been directing any capital to that, and that's just declining.

Got it. Okay, John, that's very clear. A very quick follow-up on the share buybacks. John, if the tax implications of bringing your overseas cash back to the States changed, would your share buyback philosophy change? And I'll leave it at that.

Well, I guess I want to reiterate the point that when we make that decision, it's not solely because -- it's not because we're constrained for the cash. We do have $6.9 billion sitting offshore and we're going to leave that offshore for the time being until we get some better visibility on a repatriation holiday. But really, it's driven more by the fact that, our analysis of our future capital requirements and, importantly, the accretion that, that brings to our cash flow per share as opposed to buying shares back. And that's why I said earlier, it should give you a pretty good idea that we're pretty excited about our opportunity set right now. Now factored into that, too, we got a very low-gas-price environment, we've got a lot of uncertainty in the world economy and it's a good time, we believe, for us to maintain some financial flexibility by keeping the strong balance sheet. But we're going to be driven by the returns, not by where the money is.

Your next question comes from the line of David Heikkinen from Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: As you think about T&D capital beyond 2012, how do you think about kind of level of spending and liquids growth rates on a multiyear basis?

Well, David, this is Dave Hager. Again, we have a deep inventory of liquids-rich opportunities within the portfolio and so we think that we can continue this focus of liquids-rich and oil drilling opportunities for a number of years. And I would suspect that, again, we haven't put our total plans together for the years beyond 2012, but I would suspect that we would continue to have a growth rate on the total liquids somewhere in the teens in the out years. And we'll provide some more details on this when we have our Analyst Day meeting here in early April. But I suspect it's going to be somewhere in that order of magnitude because we have the opportunities to execute.

And of course, should the external environment change, in our view, as to the relative value of dry gas versus liquids-rich, our capital mix will change as well. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes, you have the portfolio of dry gas still.

And oil, right. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then on, maybe a little more specific on oil sands, hearing some faster ramps to new projects in the 9- -- 6- to 9-month time frame as opposed to previous projects have been 12 to 18 months. Are you experiencing that or expecting that for Jackfish 2? And then, should we starting thinking about the same thing as you get into Jackfish 3?

Actually, right now, on Jackfish 2, we're running a little bit ahead of where we had budgeted, and we're very happy with the performance. And so no real issues to discuss there. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Do you think you can do it in 6 months to get to peak, or is that too fast?

That's probably too fast.

David, for a project this size where we're talking about 35,000 barrel-a-day projects, you're putting a lot of steam in the ground and it just takes a number of months to ramp it up. And we'd rather, given that these are 25-year projects, we'd rather ramp them up on what we think is an operationally sound manner than trying to bring them on too fast. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So it's mainly through use of solvents and that type of thing that was speeding up some of the pace of it? That was it.

Well, we obviously look at all those things. And just, our experience right now is that a little bit slower ramp-up is what's appropriate for our projects and achievable for our projects. So we obviously are looking at solvents and things like that. And if some of those become applicable, we'll look very hard and perhaps then we can speed it up, but right now, we just don't see that scope.

David, I might add that we're not solving for the shortest ramp-up time. We're solving for the best rate of return, so the number of initial wells you drill versus the plant size and that kind of thing all impact rate of return.

Your next question comes from the line of Bob Brackett from Bernstein research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I had a question on the $400 million in fourth quarter leasehold that went to the Utica and the stealth oil play. If you acquired 125,000 acres of Utica and if you say that was at $3,000 an acre, you would have consumed that full $400 million. So are you getting sort of bargain Utica acreage, or is that a stealth play just getting a small share of that $400 million?

Well, your assumption on the price is probably not quite accurate on the Utica acreage, and we really just started acquiring the acreage in the stealth play. And frankly, we've been continuing to build, past the end of 2011, we're building on that stealth oil play position as we speak. And we see a path, frankly, for a position there somewhere in the 300,000- to 500,000-acre rage as we continue to build that position. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. So the, on the Utica, the follow up, you're spending more or less than $3,000 an acre?

We do not want to get into specific acreage prices for plays that we are continuing to acquire acreage in. It's just not in our interest, for commercial reasons.

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

Dave, I've been seeing a little bit of industry results in the Cana suggesting some good results toward the southeastern portion of the trend and I was wondering whether you might be reconsidering or reevaluating what you consider the core of the play to be.

Well, we've seen -- obviously, we agree, Mark. We've seen some results out there that are somewhat encouraging on the southeast side, but we still think that we have what we think is really the best core position in Cana. We're happy with our position that we have there. And again, we have probably about between 2,000 and 3,000 locations in the liquids-rich portion of the core to drill. And so when you look at what we're drilling at pace of 200 wells or so per year, we have a very deep inventory there for many, many years. But there have been, I agree with you, there have been some good wells made on the southeast side. But I think we need to see some more results to be really sure how, just how sustainable that is.

Okay. My follow-up, Dave, relates primarily to the Bone Springs in the Permian, an area where, in the recent past, results have been pretty good. I wonder if you could update us. I didn't hear you specifically mention Bone Springs activity in your review of the quarter.

Well, we've had a number of good Bone Springs wells in the quarter. I think we highlighted, actually, in the earnings release that we had a number of good Bone Springs wells on the order of around 600 barrels a day or so that we achieved out there. I think we had 8 wells average more than 600 barrels per day, 8 operated wells in the fourth quarter that achieved more than 600 barrels a day so we're seeing very good results out there. We see a good inventory of opportunities sitting out there. We estimate we probably have 350 to 400 locations remaining in the Bone Springs just on our existing inventory and will probably drill somewhere around 80 this year. So again, you can see 4- to 5-year inventory of Bone Springs opportunities.

Your next question comes from the line of Bob Morris from Citigroup.

Just one question here on the acre expenditure. I think you said early in the call that your CapEx of $5.1 billion to $5.5 billion had only $25 million in it for leasehold acquisitions. But given that you're continuing acquiring this stealth oil play and there might be other plays that you'll acquire acreage in and you spent $1 billion on acreage last year, what is a realistic expectation as to how much you'll end up spending on acreage this year?

Well, first, a correction: We said $225 million in that base budget plan that we had. And that really is just kind of our base level of activity coring up around existing locations that we have, et cetera. We're opportunistic so I think it's a little bit hard to say for sure exactly how much we may want to spend on new acquisitions. But again, we are focused on oil opportunities, we are -- and we're focused on building significant scale in these opportunities when we can. We want to build positions that are meaningful for a company the size of Devon. And so when we see this type of opportunity, we're -- we'll make an evaluation on the economics, and if it's justified, we will pursue it. Now exactly what that means in terms of total acreage or lease acquisition costs in 2012, it's still a little bit early to say. And we're in the process of putting together a couple new areas right now, but we need to see how they develop to say exactly what that number may be.

So the $225 million does not include anything on this new oil stealth play or any other stealth plays you may pursue?

That's correct.

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

Given your diverse horizontal breadth in the Permian Basin, can you just comment on how you see the relative rates of return in the various horizontal opportunities and what you would need to see a further raise or shifts to your rig counts, specifically the Wolfcamp Shale in the Midland Basin, how that looks in your mind versus the Wolfcamp Shale in the Delaware Basin versus the Bone Spring in Avalon?

Well, I'd say that, in our mind, that the Wolfcamp Shale in the Midland Basin, the Bone Springs and the Wolfberry all offer strong rates for return to us. The Wolfcamp Shale in the Delaware Basin so far has been more gas oriented, and so obviously, at these depressed prices, that is not drawing the attention of our capital near the way the other 3 plays are. But I wouldn't try to differentiate too much between those other 3 plays because they all offer strong rates of return.

And then my follow-up is you talked about the 5 Pike projects in your release at 35,000 barrels a day each. Can you just refresh us on the timing that you see? And how, if at all, the CapEx per flow in barrel, might be different than what you're seeing at Jackfish 2?

Yes, the first phase of camp [ph] Pike, which again would be essentially 3 Jackfish-sized projects we anticipate, we anticipate filing for a regulatory approval sometime in 2013 or so and then have a first steam for that perhaps late 2015 and then full-scale operations late 2016, early 2017. The fourth and fifth Jackfish-sized projects in Pike are still awaiting full delineation, and it's a little bit hard to say exactly what the timing they would be until we have those fully delineated; probably sometime out closer to the 2020 range to really to achieve production on those. As far as the costs go, I think we're anticipating similar costs, but there is obviously some cost inflation pressure that's taking place up there. And there's a tightness of skills, a tightness of labor up there. So each one of these are probably a little bit higher than Jackfish due to those inflationary pressures.

Brian, this is Vince. I might add that the long-term forecast we gave through 2020 for thermal oil production doesn't include any contribution from any Pike projects beyond this 105,000 barrels per day that we expect to take to, into the regulatory process in the -- sometime this year.

Okay, that ends today's call. For those of you that we did not get to your questions, the IR staff and other members of management will be available throughout the day to take your questions. And thanks for participating.

And this concludes today's conference call. You may now disconnect.