Devon Energy Corporation (DVN) Q4 2011 Earnings Report, Transcript and Summary

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 and liquids-rich gas, our liquids reserve replacement rate reached 230%. This boosted oil and natural gas liquids to 42% of the company's total reserves, more than half of which is black oil. These results were achieved in spite of 2011 being a modest year for SAGD bookings. Significant oil reserve additions are expected from Jackfish 3 this year, and that will set up 2012 as another good year for company-wide reserve additions. Our total costs incurred for the year were $6.9 billion, including capitalized G&A and interest. Even though we invested $1.5 billion on unproved leasehold capture and exploration activity that did not add reserves in 2011 and more than $700 million on our SAGD projects, our F&D costs came in at less than $18 per BOE, a very competitive result. This is without reflecting the benefit of the $900 million in cash that we are receiving from Sinopec. It's worth noting that we achieved these results while decreasing our percentage of proved undeveloped reserves. In fact, Devon's PUDs account for just 26% of our total proved reserves at year end, down from 29% at the beginning of the year, which gives us one of the lowest PUD ratios in the industry. It's no surprise that gas, dry gas projects are increasingly challenged in our current environment. In 2011, we allocated over 90% of our E&P capital to oil and liquids-rich projects, and in 2012, virtually all of our capital will be directed to our oil and liquids-rich project areas. We've always believed that a balanced portfolio provides better risk-adjusted returns than one focused on either oil or gas. This philosophy has served us well as dry gas economics have eroded. Our diversified portfolio provided the opportunity to easily deploy capital to our deep inventory of oil and liquids-rich projects without having to abruptly shift our focus or overpay to establish new oil and liquids-rich projects. When considering our capital allocation for 2012, we remain focused on optimizing our long-term growth per share adjusted for debt. We implement this philosophy by determining a right combination of E&P investments, debt reduction, share repurchases and dividend payments. In aggregate, we expect our full year 2012 E&P capital to decline to between $5.1 billion and $5.5 billion. Approximately 90% of this capital will be devoted to development projects translating into top line production growth of 6% driven by oil production growth in excess of 20% and double-digit production growth in NGLs. By the end of 2012, our liquids production will be 40% of our total production and some 60% of the total liquids will be oil. In addition to the development projects that drive this growth, we're allocating 10% of our capital to exploration activity in our various oil and liquids-rich plays. Although our 2012 capital budget includes about $225 million for routine leasehold acquisitions, it does not include any large-scale acreage acquisitions that we may identify throughout the year. And on that front, we're currently working on significant oil-focused opportunities to expand our footprint in current plays and also to establish new positions in plays that we're not yet prepared to talk about. The impact of our exploration program will be enhanced by our $2.5 billion agreement with Sinopec. This joint venture materially enhances our returns and improves our capital efficiency. Not only do we recover more than 100% of our costs to date per acreage in exploration drilling, the transaction also reduces our future capital outlays. In addition, it will allow us to accelerate activity in our new venture plays without diverting capital from our core development projects. And finally, the reduction in capital outlays gives us an additional financial flexibility to aggressively pursue new plays. Cash flow from operations and the cash that we will receive from the Sinopec joint venture will fund a robust capital program for 2012 without the need to issue equity or significantly increase debt. As a result, given our reduced share count in 2012, our top line growth of 6% should translate into approximately 10% growth in production per share. In addition to investing in our core business, we've got a -- we've had a long history of returning cash to shareholders through dividends and share repurchases. Today, I'm pleased to announce that we are increasing Devon's quarterly dividend by 18% to $0.20 per quarter. Since 2004, we have increased our dividend 7 times or a total of 800%. Going forward, we fully expect to continue to regularly increase our dividend. Also, since 2004, we reduced our share count by 20%. And while Devon's common stock continues to be a compelling value based on where we're trading today, for the time being we've decided against additional share repurchases. The oil plays that we're building and de-risking in 2012 should provide the opportunity to deploy significant quantities of capital in the future. These developing investment opportunities, combined with an extremely weak natural gas price environment, uncertainty in the world economic outlook and more than $6 billion of our cash held offshore, all suggest that maintaining a high degree of liquidity and financial flexibility makes sense. As we have in the past, we will continue to evaluate the merits of additional share repurchases as we go forward. In summary, Devon is well positioned to deliver highly competitive per-share growth. We remain intently focused on optimizing margins and maintaining our position as a low-cost producer. Our balance sheet remains in terrific shape, allowing us to invest in our business based on our long-term outlook. We maintain a disciplined approach of balancing resource development with resource capture to optimize the value of our portfolio. Our deep and diverse inventory of low-risk oil and liquids-rich development opportunities provides us ample opportunity to invest at very attractive rates of return in the current environment. Simultaneously, we're establishing and testing a wide array of exciting new resource plays. All of these factors position Devon to deliver many years of profitable growth. And with that, I'll turn the call over to Dave Hager for a more detailed review of our operating highlights. Dave?

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 potential for a 105,000-barrel-per-day project for the first phase of the Pike development. This winter's drilling program consists of drilling over 100 stratigraphic test wells and acquiring 50 square miles of 3D seismic. We expect to begin the regulatory process for Pike as early as this summer. You may recall that we expect Pike to ultimately support additional phases of development before -- beyond this first phase. Devon operates Pike with a 50% working interest. In aggregate, we plan to spend approximately $800 million on our thermal oil sands projects in 2012. With the initial phase of Jackfish running near capacity and Jackfish 2 continuing to ramp up, we expect to grow our thermal oil production by 50% over 2011 to an average of over 50,000 barrels per day in 2012. We are on track to achieve our goal of growing our net SAGD oil production to between 150,000 to 175,000 barrels per day by 2020, representing a 17% to 19% compound annual growth rate through the end of the decade. On the exploration front in Canada, we continue to evaluate the oil and liquids-rich potential of numerous play types across our more than 4 million net acres. Our most encouraging results from our 2011 program came in at the Ferrier Area where we are targeting cardium oil. We drilled 8 wells in the area and saw 30-day IP rates as high as 940 barrels of oil equivalent per day. We were also encouraged by our early results in the Viking light oil play in Saskatchewan. We are still in the early stages of the evaluation of these and several other emerging liquids plays in Canada. We will continue this effort in 2012, spending approximately $350 million drilling some 90 exploratory wells. Moving now to the Permian Basin. Our total net production averaged over 53,000 oil equivalent barrels per day in the fourth quarter, up 19% over the fourth quarter of 2010. Permian oil and gas liquids production grew at 22% over the same period and, today, account for 75% of our total Permian volumes. At year end, we had 16 operated rigs running and have since added a 17th rig. And we plan to pick up 2 additional rigs over the course of the next month, bringing us to 19 operated rigs in the basin focused on drilling high-return oil opportunities. Devon was the first to apply horizontal drilling in shale in the early days of the Barnett. Today, we continue to leverage this expertise and are currently operating 15 horizontal rigs in the Permian, making Devon the most active horizontal driller in the basin. This reflects the large horizontal drilling opportunity set we have across our Permian position. These are light oil opportunities generating some of the best returns in our portfolio. Accordingly, in 2012, we expect to spend $1 billion and drill over 300 wells in the Permian. This includes 100 wells in the Wolfberry play, 80 in the Bone Springs, 75 in various conventional formations, 35 in the Wolfcamp Shale, 35 in the Delaware and 5 in the Avalon. In 2012, our Permian properties are expected to deliver 25% liquids production growth over 2011. We only recently began drilling on the 92,000-net-acre Wolfcamp shale position that we have established in the Southern Midland Basin. We brought 4 Wolfcamp Shale horizontal wells online in the fourth quarter, with the best well delivering a 24-hour IP of 935 barrels of oil equivalent per day. The results of our wells, combined with industry results around our position, give us confidence and consistent economic results in this play. We are continuing to fine-tune our drilling and completion techniques and have just finished drilling our first 7,100-foot lateral, which included a 30-stage completion. This well is just starting to flow back. We'll keep you posted and updated on our progress. Moving now to the Cana-Woodford Shale in Western Oklahoma. Our Cana gas plant was back fully operational in December, following repairs of the damage incurred last May from a tornado. This helped us achieve our target exit rate for the Cana of 275 million cubic feet equivalent per day. Fourth quarter net production increased 83% over the year-ago quarter to a record 250 million cubic feet of gas equivalent per day, including 3,100 barrels of oil and 7,400 barrels of natural gas liquids per day. This significant liquids contribution, combined with our low acreage and royalty costs, enable us to generate strong full-cycle returns in the current commodity price environment. In 2012, we plan to invest some $870 million of capital and drill nearly 200 wells in Cana. Our Cana activity will be focused in the oil and natural gas liquids-rich portion of the core area. Liquids should represent almost 40% of the production stream generated by the 2012 capital program. Cana oil and liquids production is expected to grow over 85% to an average of 16,000 barrels per day in 2012. From a reserves performance perspective, Cana was a leading growth area for the company in 2011. Extensions, discoveries and performance revisions at Cana accounted for 160 million barrels of oil equivalent of additions. At year end, we had 328 million equivalent barrels booked in the Cana-Woodford. With almost 2 billion barrels equivalent of risked resource potential and more than 5,000 risked locations remaining, we expect Cana to deliver many more years of highly economic production and reserves growth. Shifting to the Barnett Shale Field in North Texas. In the fourth quarter, we brought 70 Barnett wells online and are continuing to see outstanding results from our drilling in the liquids-rich portion of the play. Our fourth quarter net production held steady at a record 1.32 Bcf equivalent per day, including 47,000 barrels of liquids per day. We continue to achieve excellent results in the Barnett with the pad drilling. In the fourth quarter, we brought a 22-well pad online with average IPs of 3.2 million cubic feet equivalent, including 175 barrels per day of natural gas liquids. In 2012, we plan to invest approximately $950 million of capital in the Barnett and drill approximately 300 wells. We currently have 12 operated rigs running, but plan to drop 2 of these rigs sometime in the second quarter. This decision was made in conjunction with the decision I mentioned earlier to add the 3 rigs in the Permian to focus on our extensive inventory of oil opportunities. Remarkably, even with a 10-rig program for a good part of the year, we still expect our Barnett liquids production to grow almost 15% over 2011 to an average of 53,000 barrels per day in 2012. From a reserve performance perspective, extensions, discoveries and performance revisions in the Barnett Shale accounted for 120 million barrels of additions, including 5 million barrels of positive performance revisions. This marks the eighth consecutive year of upward performance revisions in the Barnett that in aggregate total over 235 billion barrels equivalent. At year end, we had 1.15 billion barrels equivalent booked in the Barnett of which 86% is proved developed. On the exploration front. As John mentioned, the execution of the JV with Sinopec marks the beginning of a significant effort to de-risk these 5 new venture oil and liquids-rich plays. In the Mississippian oil play located North Central Oklahoma, the partnership has now secured approximately 230,000 net acres. We drilled our first vertical well in the second quarter of last year to gather data and have since drilled our first horizontal Mississippian producer, yielding very encouraging results. The Matthews 1H was brought online in the fourth quarter and achieved a 24-hour sustained IP rate of 960 barrels of oil equivalent per day, of which greater than 80% was oil. Through the first 30 days of production, the well averaged 590 barrels of oil equivalent a day. These results are among the best reported in the play to date. And with an API gravity of around 40 and low sulfur content, this appears to be some of the best-quality crude oil in the lower 48. We are obviously very encouraged with these results and plan to drill or participate in approximately 15 Mississippian wells by year end. In the Niobrara, industry results to date have been mixed and somewhat challenged in some areas, but we are still in the early stages of evaluating our acreage. However, we recently completed our first well in the Turner formation on our Niobrara acreage with encouraging results. After being online for 22 days, the Waterbuck 2342 had averaged 427 barrels of oil equivalent per day. In addition to the Niobrara and Turner formations, we expect to drill Cordell, Mowry and Frontier wells in our Powder River and DJ Basin acreage this year. In total, we expect to have 35 wells drilled here by year end. In the Tuscaloosa Marine Shale, we have completed our first 2 horizontal wells in the play. The Beech Grove 68H was a short-lateral horizontal and had a series of mechanical problems but still managed to deliver a 24-hour IP of 186 barrels per day. This well is not indicative of what a properly completed long-lateral horizontal well can do in the Tuscaloosa. The second well, the Soterra 6H-1, is just starting to flow back, following the fracture stimulation. We are adding a second rig in the Tuscaloosa in March and expect to have 10 wells down in the play by year end. In Michigan, we drilled 2 vertical test wells last year and just drilled the first horizontal well in the A1 Carbonate. We plan to complete the first well later this month and are now beginning to drill our second horizontal. We expect to have approximately 15 wells drilled in this play by year end. In the Ohio Utica, Devon and Sinopec have assembled 235,000 net acres in the play. We just TD-ed our first horizontal well, the first of 15 horizontal wells that we expect to drill here this year. While we are still in the early stages of evaluating these plays, we have seen positive subsurface data and encouraging rate indications in several of them. By the end of 2012, we expect to have drilled approximately 125 wells in aggregate across these 5 plays, giving us a much better understanding of the potential of these positions. In summary, our 2011 capital program delivered strong liquids growth and record production reserves from each of our key development areas. Importantly, we also made tremendous progress in efficiently captured -- efficiently capturing significant acreage positions that will provide the next leg of oil and liquids growth in 2012 and beyond. With that, I'll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

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 of this year, we expect sequential production growth of about 1.5% to a range of 685,000 to 695,000 barrels per day. Beyond the first quarter, we expect production to steadily increase as the year progress. Now for a brief review of our revenues. Throughout 2011, our balanced product mix helped to offset the effects of lower natural gas prices. This was especially evident in the fourth quarter, with nearly 65% of our upstream revenue derived from oil and NGLs. Our natural gas hedges also enhanced our Q4 E&P revenues. Overall, cash settlements of hedges contributed an additional $151 million of revenue and boosted our company-wide price realizations by $2.42 per BOE. Looking at our hedge position for 2012. Roughly 50% of our expected oil production, or 76,000 barrels per day, is hedged through various swaps and costless collars. Of this amount, 22,000 barrels were swapped at a weighted average price of $107, with the balance collared at a weighted average ceiling of $126 and a floor of $86. We also have 880 million cubic feet per day of natural gas hedged with a weighted average protected price of $4.73. This represents about 1/3 of our expected natural gas production for the year. Turning now to our marketing and midstream operations. They once again delivered another high-quality quarter, generating $134 million of operating profit, bringing our full year midstream profit up to $542 million. That's at the high end of our guidance range and a $32 million improvement over 2010. Looking ahead to 2012, we expect lower prices to cap our full year operating profit in the $470 million to $520 million range. Moving to expenses. We continue to do an excellent job controlling costs in spite of industry inflationary pressures. In the fourth quarter, expenses in most categories were in line with our expectations and our pretax cash costs were only 2% higher than last year at $13.61 per BOE. This is especially noteworthy given that our growth in oil production, which is generally more expensive to produce. Our consistent focus on cost management and the significant scale we enjoy in our core operating regions continue to place Devon in the position of being a low-cost producer. This contributes to our ability to generate full-cycle returns that are among the best in our peer group. The final expense I will touch on is income taxes. After backing out the items that are typically excluded from analyst estimates, our adjusted full year 2011 income tax rate was 34% of pretax earnings. This adjusted rate is comprised of a 2% current rate and a 32% deferred rate, right in line with our expectations for the year. In today's earnings release, we have provided a table that reconciles the effects of items that are typically excluded from analyst estimates. Going to the bottom line: A strong operating performance in 2011, combined with the sale of our assets in Brazil, translated into record earnings of $4.7 billion. Backing out the sale of Brazil and all of the other items that analysts generally exclude, 2011 non-GAAP earnings totaled $6.14 per diluted share. For the fourth quarter, non-GAAP earnings were $1.55 per diluted share, exceeding the First Call mean by $0.07. Now for a quick review of our financial position. For 2011, Devon's cash flow from continuing operations before balance sheet changes totaled $6.5 billion, which represents a 23% increase over 2010. Also, we received $3.2 billion from the sale of our Brazilian assets during the year, boosting total cash inflows to $9.7 billion. We utilized these sources of cash to easily fund our capital program, driving 8% top line production growth, record oil and gas reserves and the acquisition of valuable leasehold that enhances our long-term liquids growth prospects. In addition to our capital program, we returned capital to our shareholders by repurchasing $2.3 billion of common stock and paying $278 million in dividends. We exited the year with $7.1 billion in cash and short-term investments and an enviable net debt to adjusted cap ratio of only 11%. As mentioned earlier, we continue to organically develop additional liquids-focused opportunities. We have the luxury of being able to comfortably fund these activities while maintaining our strong financial position. And with that, I'll turn the call back to John.

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.