Devon Energy Corporation (DVN) Q4 2010 Earnings Report, Transcript and Summary

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 the Devon website. Before we get to the business of the call, we are obligated to remind you that the discussions today of our expectations, plans, forecasts and estimates are all considered forward-looking statements under U.S. Securities Law. And while we always strive to give you the very best estimates possible, there are many factors that could cause our actual results to differ from these estimates. For a discussion of those risk factors, see the Form 8-K that we're filing today. One other note, we refer to various non-GAAP performance measures in today's call. When we use these measures, U.S. securities law requires us to provide certain additional disclosures. Those disclosures are available for your review on our website as well. Before we jump into the call, I have a couple of things to remind everybody of. First, our strategic repositioning that took us out of the Gulf of Mexico and international businesses triggered accounting rules for discontinued operations. However, the accounting standards for discontinued ops do not apply to our Gulf of Mexico divestitures, so that creates a confusing situation. While we've excluded the international production volumes for all periods presented and collapsed the revenues and expenses associated with the international operations into the discontinued ops line item on the income statement, the results from our divested Gulf of Mexico operations are included in our continuing operations for the portion of 2010 up to the point of sale of those assets. For that reason, we're providing supplemental information in our press release today that isolates our results from go-forward North American onshore operations. Similar to the last several quarters, the accounting treatment for discontinued ops affected the comparability of earnings estimates from TheStreet during the fourth quarter. However, now by this time, most analysts are reporting fourth quarter estimates for continuing operations only. The first call mean [ph] of those analysts that forecasted continuing ops was $1.40 a share. And our actual results of non-GAAP earnings of $1.46 per share exceeded those expectations by $0.06. With those items out of the way, I'll turn the call over to our President and CEO, John Richels.

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 the highest reported earnings per share in Devon's history. Cash flow before balance sheet changes climbed 21% over the prior year to $5.7 billion. And when you combine that with almost $7 billion in divestiture proceeds received to date, Devon's total cash inflows approach $13 billion in 2010. With that cash flow, we funded our E&P and Midstream capital budgets, including $1.2 billion of acreage capture focused on oil and liquids-rich plays. We retired $1.8 billion of debt, ending the year with a near-bulletproof balance sheet and with debt and net debt as adjusted capitalization ratio of 10%, including cash on hand of $3.4 billion. And in addition to our capital program and debt reduction, we also returned more than $1.4 billion to our shareholders through our stock buyback program in dividend payments. In 2010, we repurchased over 18 million shares. We've continued to be active in the market subsequent to year end. And through last week, we had repurchased a total of 23.5 million shares or just over 5% of our outstanding shares. With an aggregate cost of $1.6 billion, this gives us an average cost to date of $69.60 per share. Finally, we had another strong year of company-wide reserve growth. We added 464 million barrels, boosting year-end proved reserves to an all-time record of 2.9 billion barrels. This means that our North American reserve additions more than replace all of the year's production and the roughly 200 million barrels of proved reserves associated with our divestiture. We ended 2010 with record proved reserves in spite of selling properties worth more than 20% of our enterprise value during the year. Looking more closely at the 2010 reserve activities. Our drill-bit reserve additions, so that includes discoveries, extensions and performance revisions for our go-forward North American Onshore business, total of 389 million Boe. These additions were 175% of our 2010 North American Onshore production. When we announced the $500 million pipe joint venture with BP -- you'll remember that's our joint venture in the oil sands in Canada, we said that our 2010 drill-bit F&D would likely come in between $14 and $16 per barrel. Following that announcement, we stepped up our acreage capture and spent another $700 million an acreage in the Permian Basin and in our Cana play and on other undisclosed new plays, bringing our total acreage capture for the year up to $1.2 billion. This resulted in total drill-bit capital of $6.1 billion, including capitalized G&A and interest. And in spite of the additional acreage capture, our organic North American Onshore finding and development cost came in, in line with the original estimate at $15.74 per Boe. This positive result is because our drill-bit reserve additions far exceeded our original estimate. It's worth noting that we achieved our 2010 F&D results without increasing our percentage of proved undeveloped reserves. In fact, at December 31, our North American onshore undeveloped reserves accounted for just 29% of total proved. It's important to remember that the one-year F&D cost can be somewhat arbitrary. I will remind you that when we reported our 2009 results, we told you that the $6.59 per barrel F&D cost for 2009 was unrealistically low. If you combine our 2009 and 2010 results for the go-forward business, you arrive at an average F&D for the two years of a little over $10.60 per barrel, some very competitive result even with the unusually large acreage acquisitions in 2010. Price revisions for our North American Onshore properties gave us a net positive boost in 2010, adding another 71 million barrels. Positive gas-price related revisions principally from the Barnett Shale more than offset negative price revisions related to higher oil prices and the sliding scale royalty impact on our thermal oil sands in Canada. This underscores the value of a balanced portfolio of properties. Taking into account the net price revisions, our total North American Onshore reserve additions from all sources were 464 million Boes, more than double our North American production. That boosted Devon's North American Onshore reserves to 2.9 billion equivalent barrels, representing 9% growth over year-end 2009. And that's important, because this reserve growth really supports our future production growth. Looking to 2011, we're forecasting our North American Onshore production to total between 236 million and 240 million equivalent barrels. This implies a growth of 6% to 8% over our 2010 production of 223 million equivalent barrels. The preliminary forecast that we provided last November called for a 20% increase in oil and liquids production for 2011. However, updated liquids yield data from some of our emerging plays has resulted in a slight shift in the gas to liquids ratio. We now expect our 2011 production growth to be driven by oil and liquids growth in the high teens. Before I turn the call over to Dave, I'd like to update you on the status of the $3.2 billion sale of our assets in Brazil to BP. While we had expected this transaction to close in 2010, we have not yet received approval from the government of Brazil. However, we've seen nothing that would lead us to believe that this transaction will not ultimately be approved. So with that, I will turn the call over to Dave Hager for a review of our quarterly operating highlights and our 2011 capital budget. Dave?

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. With the initial phase of Jackfish running near capacity and no major turnarounds scheduled in 2011, we expect our thermal oil production to grow nearly 3 million barrels over 2010 level to about 12 million barrels in 2011. At Pike, our Side B [ph] oil sands joint venture with BP, we began appraisal drilling in the fourth quarter and plan to drill about 150 stratigraphic core wells this winter. We also are acquiring some 60 miles of 3D seismic data. This drilling and seismic information will help us determine the optimum development configuration for the initial phase of development. We hope to begin the regulatory process for the first phase of Pike around the end of the year. In aggregate, we plan to spend about $600 million on our thermal oil sands project in 2011, as we continue toward the goal of growing our net Side B [ph] oil production to between 150,000 to 175,000 barrels per day by 2020. This represents roughly a 20% compound annual growth rate in Side B [ph] production through the end of the decade. At year end, we had 440 million barrels of reserves booked in our thermal oil sands. As we move through the development of Jackfish and Pike projects, we expect to book roughly 1 billion additional barrels of net resource. In our Lloydminster oil play in Alberta, we drilled 57 new wells in the fourth quarter, which brought our full year total to 191 wells. In 2011, we plan to spend about $100 million drilling approximately 170 wells in the Lloydminster area, allowing us to hold production steady at roughly 40,000 barrels equivalent per day. Also in Canada, in 2011, we plan to spend about $150 million testing more than a half dozen different oil and liquids-rich gas plays that we have identified across our vast land base. This includes fractured oil shales, tight oil carbonates and tight oil plastics in the Deep Basin. Specifically, we plan to drill 13 wells this year testing the Viking-like oil play on our 900,000 acres of feed title lands in the Kindersley area of Saskatchewan. In the Deep Basin of Alberta, where we have nearly 600,000 net acres, we will drill several wells targeting the Cardium light oil play and the liquid-rich lower Cretaceous zones including the Cadomin Formation. These are just a few of the areas we'll be testing in 2011 to better understand the potential for commercial success in these new plays across our vast Canadian acreage position. We will keep you updated as we move forward. Shifting to the Rocky Mountains, we are currently testing the oil potential on our 220,000-net acre position in the Powder River Basin. We are in the early stages of evaluating several Cretaceous oil objectives, including the Parkman and Niobrara. In 2011, we plan to spend about $50 million and drill 15 wells testing these play concepts. Moving to the Permian Basin, our net production averaged 45,000 oil-equivalent barrels per day in the fourth quarter, up 16% over the fourth quarter of 2009. Our fourth quarter oil NGL production at Permian was up 23% over 2009 and accounted for 73% of our total Permian volumes. We continue to be very active in the Basin with 17 operated rigs running. In 2011, we expect to spend $650 million and drill about 300 wells in the Permian. Growth from our Permian assets is expected to contribute approximately 3 million barrels of liquids growth over 2010 levels to 14 million barrels in 2011. In our Wolfberry light oil play, we currently have six operated rigs running. Since drilling our first Wolfberry well in late 2008, we have drilled more than 140 wells, allowing us to derisk large portions of our 197,000 perspective net acres. Our drilling results to date support EURs of between 100,000 and 150,000 barrels of oil per well across roughly 160,000 net acres. On our 37,000 net acres located in the northern part of the play, we have had marginal success. However, this acreage has potential in some additional zones. In 2011, we plan to spend $250 million in the Wolfberry and drill approximately 125 wells from our inventory of more than 1,000 risk locations. Also in the Permian Basin, in the Avalon Shale play, we are currently running four rigs. Devon has assembled over 200,000 prospective net acres in this condensate and liquids-rich gas play. Although we are still in the early stages of evaluation and drilling, results have varied depending on the location within the broader play area, we are beginning to see some trends. In the fourth quarter, we drilled three Devon-operated wells in the central portion of the play. One of these wells was brought online with an average 30-day IP rate of 360 barrels of condensate per day and 1.7 million cubic feet of gas per day. In 2011, we plan to spend $160 million in the Avalon and drill about 75 wells, as we continue to delineate the play on our acreage position. Elsewhere in the Permian, we continue to see solid results from the Bone Springs oil play, where Devon has 170,000 net acres. In the fourth quarter, we brought four Bone Spring wells online with an average 30-day IP rate of more than 400 barrels of oil equivalent per day. We have three rigs running in play and plan to spend $85 million to drill approximately 45 Bone Springs wells in 2011. Our four remaining operated rigs in the Permian are targeting conventional formations. This includes objectives such as the Delaware, Wolfcamp, Clear Fork [ph] and Wichita-Albany, they were accessing primarily with horizontal wells. In the fourth quarter, we drilled some very strong conventional wells, including a Delaware horizontal well on our cut-and-dry unit that came online with a 30-day IP rate of 700 barrels of oil per day. In 2011, we plan to spend a little over $100 million and drill 50 wells in these conventional targets. Moving north to the Texas Panhandle, where Devon has assembled approximately 62,000 net acres in the Granite Wash play, we stepped up drilling activity during the quarter with the addition of a fourth rig that was relocated from the Barnett. In the fourth quarter, we brought five Devon-operated wells online, with average IP rates of 2,730 oil equivalent barrels per day, including 580 barrels of oil and 870 barrels of NGLs. Production history from our Cherokee Granite Wash wells continue to support EURs of about 1 million barrels equivalent. At roughly $7 million to drill and complete, these wells generate outstanding full-cycle rates to return. In 2011, we plan to spend $175 million and drill 55 wells with an average working interest of about 50%. Our activity in the Granite Wash is expected to contribute approximately 1 million barrels to our company-wide year-over-year liquids growth. Moving to the Cana-Woodford Shale in Western Oklahoma, we continue to add to our acreage position during the fourth quarter and now have approximately 243,000 net acres. Devon is currently operating 23 out of the 39 rigs running play-wide. In the fourth quarter, we continued to aggressively derisk our position and secure the term acreage we acquired last year. We continue to see outstanding results from Cana. In the fourth quarter, we brought 21 operated wells online, with average five-day IP rates of 4.9 million cubic feet equivalent per day, including an average of 66 barrels of condensate and 174 barrels of NGLs. Fourth quarter net production from Cana averaged a record 137 million cubic feet of gas equivalent per day, with over 20% of this production stream coming from condensate and NGLs. This is a 17% increase on a sequential quarter basis. I also want to briefly update you on the status of our Cana infill pilot program we initiated last year in the core area. Production history from our 500-foot spaced wells continue to perform well, supporting an 8 Bcf type curve. These results support that we have eight to 10 wells per section and that's a likely spacing in the core area. However, to date, we have only booked five wells per section in the core area. From a reserves performance perspective, Cana was a leading growth area for the company in 2010. Extensions, discoveries and performance revisions at Cana accounted for 105 million Boe of additions. Related drill-bit capital was $729 million, including roughly 200 million of additional acreage capture. At your end, we had 175 million equivalent barrels booked at Cana-Woodford. With some 11 Tcf equivalent of risk resource potential, and more than 5,000 risk locations remaining, we expect many years of highly economic production and reserve growth from Cana. In December of 2010, we began processing gas in our new Cana liquids extraction plant. The facility has an initial processing capacity of 200 million cubic feet per day and is capable of extracting up to 15,000 barrels of liquids per day. The plan is expandable to 600 million per day inlet capacity as we grow Cana volumes. This facility allows us to capture additional value from the liquid-rich Cana gas stream. In 2011, we plan to invest over $800 million of capital and drill more than 200 wells. By year end, we expect our net production from Cana to reach 250 million cubic feet equivalent per day, including 14,000 barrels per day of condensate and NGLs. This will contribute approximately 2.5 million barrels to our company-wide year-over-year liquids growth. Shifting to the Barnett Shale field in North Texas. In the fourth quarter, our net production held steady at a record 1.2 Bcf equivalent per day, including over 42,000 barrels of NGLs and condensate per day. We continue to achieve outstanding results from the Barnett, with pad drilling and improved drilling efficiency. In 2010, we were able to offset rising service costs by further reducing the number of days it takes to drill a well. In 2010, we averaged just 13.3 days from spud to rig release, down from 14.4 days in 2009. In the fourth quarter, we completed a 21-well drilling program from a single pad in which we averaged just 10.6 days from spud to spud. From a reserve performance perspective, extensions, discoveries and performance revisions in the Barnett Shale accounted for 112 million barrels of additions, including 26 million barrels of positive performance revisions. This marks a the seventh consecutive year of upward performance revisions in the Barnett that, in aggregate, total over 230 million barrels. Drill-bit additions more than replaced our Barnett production of 70 million equivalent barrels for the year. Related drill-bit capital was $1.1 billion. At year end, we had 1.1 million barrels equivalent booked in the Barnett, with thousands of remaining unbooked locations. In 2011, we plan to invest about $900 million of capital in the Barnett, running a 12-rig program. This will result in us drilling 300-operated Barnett wells and participating in about 25 non-operated wells. The 2011 program is focused on the liquids-rich areas of the play. This level of activity will allow us to generate significant free cash flow and maintain current production levels. Our expected year-over-year production growth in the Barnett should add approximately 2.5 million barrels to our company-wide year-over-year liquids growth. When you step back and look at the overall results of our 2010 capital program, you see that from both the perspectives of both reserve additions and production trajectory, the results were very good. What is not reflected in these numbers is the tremendous resource capture beyond proved reserves that we accomplished over the last year. Last August, we told you that we had acquired 260,000 net acres in new plays that we are not ready to discuss. Our goal was to identify and establish large first-mover positions in highly economic plays that had not yet become competitive. Since that time, we have continued building these positions and now have roughly 750,000 acres and a handful of new plays. In 2011, we have allocated roughly $200 million of capital to continue building these positions, acquire seismic and test several of these new play concepts. While it is unlikely that all of these plays will be successful, we are excited about the potential and expect to have positive news later this year. In total, we expect our full year 2011 E&P capital expenditures to be between $4.5 billion and $4.9 billion for our North American Onshore business. As John mentioned, with that level of spending, we would expect overall production growth of 6% to 8%, led by high teens growth in oil and NGL volumes. When you add roughly $1 billion for capitalized G&A and interest, Midstream and other corporate capital, our total 2011 capital amounts are expected to fall between $5.4 billion to $6 billion. With that, I would turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

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 plays drove this result. Our 2011 budget calls for first quarter production of 630,000 barrels equivalent per day, up slightly from the fourth quarter. However, continued curtailments due to third-party facility outages and unusually severe winter weather in Texas and the mid-continent region have negatively impacted first quarter production by about 1 million barrels or approximately 10,000 barrels per day. That production has now been restored, and we are currently producing approximately 630,000 barrels per day. Assuming no additional surprises, positive or negative, we would now expect first quarter reported production to average 615,000 to 625,000 barrels per day. Looking beyond the first quarter, we expect production to increase in each of the remaining quarters of 2011. The plan calls for the biggest jump in the second quarter, up to 645,000 to 655,000 barrels per day as we tie in a large well pad and the liquids-rich area of the Barnett, and we'd begin to see the impact of the increased activity levels in Cana and the Permian Basin. Moving to price realizations. It was another strong quarter for oil. The WTI benchmark price rose steadily throughout the fourth quarter and averaged $85.15 per barrel. Our company-wide realized price came in at $68.35 in the fourth quarter or 80% of WTI, right at the midpoint of our guidance. The escalating oil price environment boosted our fourth quarter realized price by almost 10% over the previous quarter and our full year realized oil price by 27%. On the natural gas side, the Henry Hub Index averaged $3.84 per Mcf for the fourth quarter. Our realized gas price before the impact of hedges came in at 87% of Henry Hub or $3.32. We had fourth quarter hedges totaling 1.6 Bcf per day or nearly 2/3 of our natural gas production, with a weighted average protected price of $5.87. Cash settlements from our hedging position increased our average realized price by $1.32 to an all-in realized price of $4.64 per Mcf. For natural gas liquids, in the fourth quarter, our realized NGL price improved to $34.65 per barrel or just over 40% of the WTI Index. An increase in seasonal demand combined with higher overall prices led to a 19% increase in realized prices over the third quarter of 2010. For the full year of 2011, we expect Devon's realized NGL price to range between 35% and 40% of the WTI benchmark price. We expect continued supply growth from the industry to keep downward pressure on NGL pricing in 2011. Taking a brief look at our hedging positions, for the first quarter of 2011, we now have approximately 784 million cubic feet per day swapped at a weighted average price of $5.43. For the full year, we have an average of 730 million cubic feet per day swapped at an average price of $5.49. In aggregate, this hedging position represents roughly 30% of our expected natural gas production for the year. To facilitate a portion of this hedge position, we sold call options on 19,500 barrels of oil per day for 2011 and 2012 at $95 per barrel, and call options on 588 million cubic feet per day of gas for 2012 at $6 per Mcf. Additionally, we now have collars in place, covering 45,000 barrels of oil per day with a weighted average floor of $75 an average ceiling of $109. We will be posting a hedging schedule on our website after the call that will provide some more detail on these hedge positions. Turning now to our Marketing and Midstream division. Our Marketing and Midstream operations once again produced another high-quality quarter, generating $127 million of operating profit, bringing our full year operating profit to $510 million. Increased gas throughput and strong cost control drove our solid performance. Looking ahead to 2011, we expect our full year operating profit for our Midstream division to be between $485 million and $535 million. Turning to expenses. In the fourth quarter, lease operating expenses were right in line with our expectations at $418 million or $7.36 per barrel produced. In spite of higher Canadian dollar exchange rates and upward pressure on oilfield services and supply, our LOE per Boe remained flat when compared to the third quarter. Looking forward to 2011, we expect industry inflation to continue. As a result, we are forecasting a moderate increase in LOE to a range of $7.50 to $7.90 per Boe. For 2010, Devon's full year DD&A [depreciation, depletion and amortization] expense for oil and gas properties also came in at $7.36 per Boe, a 6% decline from last year. Overall, our DD&A rate benefited from the sale of our Gulf assets. We anticipate that our DD&A rate will increase to a range of $7.40 to $8 per barrel in 2011. Moving to G&A expense. The company did a very good job of controlling G&A costs during 2010. As John said, for the full year, our reported G&A expenses totaled $563 million. That is a decrease of $85 million or 13% versus 2009. This significant reduction in G&A is entirely attributable to the operational efficiencies achieved through our strategic repositioning. We expect our 2011 G&A expense per Boe to remain roughly flat with 2010. Turning to interest expense. For 2010, it totaled $363 million, right in line with our expectations and up slightly from 2009. However, it's important to note that our 2010 interest expense included a one-time $19 million charge related to the early retirement of senior notes that we repaid in June. Excluding this charge, interest expense actually declined by $5 million as compared to 2009. As we look forward to 2011, we expect our interest expense to decline to a range of $300 million to $340 million. The final expense item I would like to touch on is income taxes. Devon's adjusted full year 2010 income tax rate came in at 32% of pretax earnings, comprised of a 2% current tax rate and a 30% deferred rate. As we discussed in last quarter's conference call, additional carryover benefits from a prior-year tax return led to a lower-than-forecasted current tax rate in 2010. These carryover benefits and the accelerated depreciation provisions that were passed into law in December also reduced our adjusted fourth quarter current tax rate. In Q4, our current tax rate was a negative 12% and deferred taxes were 42% of pretax income for an overall adjusted tax rate of 30%. Looking to 2011, we would expect an income tax rate similar to that of 2010 with less than a third of the tax expense being current. Cutting to the bottom line. For the full year 2010, our adjusted earnings from continuing operations were an impressive $2.5 billion or $5.75 per diluted share. Higher oil and gas revenues and strong cost control, combined with a reduced share count, increased diluted earnings per share by nearly 80% over 2009. In the fourth quarter, our adjusted earnings from continuing ops came in at $1.46 per diluted share. As Vince mentioned earlier, this result exceeded the mean earnings estimate by about $0.06. Before we open the call to Q&A, I would like to conclude with a quick review of our financial position. As John mentioned, cash flow from operations and proceeds of asset sales closed to date approached $13 billion. During the year, we deployed our cash inflows to fund all of our capital investments, resulting in a greatly expanded reserve base and Midstream infrastructure while enhancing our long-term growth prospects. In addition to our capital program, we also repaid $1.8 billion of debt and returned more than $1.4 billion to our shareholders through our stock buyback program and dividend payments. Devon ended the year with one of the strongest balance sheets in the industry. At December 31, our debt had declined to $5.6 million and cash on hand was $3.4 billion. While Devon clearly possesses a great deal of financial strength and flexibility, we're fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our growth per debt-adjusted share. The upcoming year is a great example of how our disciplined approach to the business will benefit our shareholders. Our focus on maximizing returns on our capital investments is leading to top line production growth of 6% to 8% in 2011. We expect our shareholder-friendly initiatives of stock buybacks and debt reduction to boost our debt-adjusted production per share to a double-digit growth rate. We believe this disciplined per share growth we are delivering in 2011 will compare very favorably to our peers. At this point, I will turn the call back over to Vince for the Q&A.

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.