德文能源 (DVN) 2006 Q4 法說會逐字稿

Welcome to the Devon Energy Corporation fourth and Year End 2006 Results Conference Call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question and answer session. [OPERATOR INSTRUCTIONS] This conference is being recorded. If you have any objections, you may disconnect at this time. I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Good morning. And welcome to Devon's year end 2006 conference call and webcast. As usual I'll cover a few housekeeping items and then our Chairman and CEO Larry Nichols will give an overview of our 2006 accomplishments, following Larry's remarks, our Senior Vice President Exploration and Production, Steve Hadden will cover operating highlights and then our President, John Richels will finish up with a review of the years financial results and our outlook for 2007.

We'll conclude the call in an hour, so if you don't get your question answered, there will be investor relations personnel on duty today to-- so feel free to phone us later. A replay of today's call will be available later today through a link on our home page, and we're also introducing a new communications tool that we'll be sending out to those that are on our distribution list, we call that Devon direct. It's a broadcast email that includes highlights from today's call and provides links to supplementary information for those of you that want to drill down deeper and look at background information on some of our projects. We would appreciate any feedback you have about Devon direct and how we can improve it going forward.

Also later today we're going file a Form 8-K as is our practice, which will provide full year forecast for 2007. In that 8-K we'll forecast production by product and geographic region. We will forecast most expense categories and our expected price realizations or really differentials off benchmark prices. Because we announced our intention to exit is Egypt in 2006 and have announced our plans recently to exit West Africa, the results of both of these areas will be treated as discontinued operations in 2007.

Our 8-K that we're filing today will provide detailed forecast for the Company's continuing operations, which exclude Egypt and West Africa and will also provide you with additional summary forecast for Egypt and West Africa that will enable you to model Devon's 2007 results with and without Egypt and West Africa, and to adjust your model when we actually know the divestiture dates-- effective dates.

We will be mailing this-- emailing this 8-K out to everyone that's on our contact list once the filing is confirmed with the SEC. Our updated guidance will also be posted to our website and we'll make some references to that guidance in today's call.

These-- this discussion of our plans, forecast and estimates are forward-looking statements under U.S. Securities Law, and while we always attempt to provide you with the very best estimates possible there are many factors that could cause our actual results to differ from those estimates and so we encourage you to review the discussion of risk factors that will be included in our Form 8-K. One final compliance item, we will make reference today to various non-GAAP performance measures. When we use non-GAAP measures we are required to provide you with certain related disclosures. You can see those disclosures on our website, they have been posted there currently for your review.

That finishes the housekeeping items, so I'll turn the call over to Larry.

Thanks, and good morning, everyone. Simply put, 2006 was one of the best years of Devon's history, both because of our financial results and because of our operational successes. We reported net earnings for 2006 of $2.8 billion or $6.34 per share this represents the highest earnings per share in Devon's history. Our cash flow before balance sheet changes climbed 7% over last year. To reach again an all time high of $6.1 billion and using both our cash flow and cash on hand we funded the largest exploration and development program in the Company's history, and at the same time repurchased $250 million of common stock.

Operationally we had many notable accomplishments in 2006. Our achievements on the exploration front were lead by the successful production test of the Jack well, this of course was an important milestone in our Deepwater or tertiary exploration program in the Gulf of Mexico. We also made a Miocene discovery in the Deepwater in the gulf in 2006 at Mission Deep. Mission Deep plus our discovery in the lower tertiary give us six Deepwater discoveries in varies stages of appraisal and development.

In our low-risk developmental program, our U.S. onshore properties, our drill bit reserve additions were more than double the year's production and our December production rate climbed 9% in 2006. We grew our production in the Barnett Shale significantly. The December 2006 average rate was 709 million cubic feet per day up 26% over the December 2005 rate. This was driven by organic growth supplemented by our acquisition of the Chief properties. This growth continues to extend Devon's leadership position in the play and provides years of additional drilling inventory, which will add to our already dominant position. On other fronts, production in our Carthage field in east Texas grew 11%, our Jackfish side deep project in the Canadian oil sands were nearing completion to remain on schedule to begin production in the second half of 2007.

In Brazil we moved the Polvo oil development program toward first production in mid-2007 this year, again, on schedule. And finally, we had another year of strong company-wide organic reserve growth this year. Drill bit reserve additions, and by drill bit additions, I'm referring of course to discoveries, extensions and performances revisions, came in at 427 million Boe. This was above the upper end of our estimated range that we provided in December and roughly double our 2006 production. This is the second year in a row that Devon's organic reserve additions have roughly doubled the respective year's production. We achieved this growth without booking any of our 300 to 900 million barrels of resource that we discovered to date in the lower tertiary trend. The booking of those discoveries as well as any other future discoveries in the lower tertiary remains out in our future.

Our drill bit reserve additions of 427 million Boe were achieved with a drill bit capital of 5.2 billion. This results in a very attractive finding and development cost. In addition, 1.2 billion of the Chief purchase price was allocated to undeveloped-- undeveloped acreage cost. Even if you include this amount which has roughly $3 a barrel, we still have very competitive drill bit F&D. In addition to drill bit reserve additions, we spent $2.3 billion on the Chief properties and other minor acquisitions of proved properties. These acquisitions added 106 million Boe of proved reserves. Combined with drilling and acquisition we added a total of 533 million Boe of proved reserves with relate capital totaling $7.7 billion. When you do the math you will find that our all-sources F&D for the year is right in line with our guidance and a very attractive number.

Price revisions reduced proved reserves by 44 million barrels of oil equivalent. This was due almost entirely to the impact of changes in year-end prices on our North American onshore properties. As you know under the reserve booking rules, year-end-- lower year-end natural gas prices reduced the theoretical economic life of our U.S. gas prices and thereby reduced proved reserves. In Canada better economics for the project at Jackfish, based on year-end prices resulted in higher assumed oil rates and therefore lowered net reserves over the life of the project.

Let's look at these results broken down by geographic area. Our core North American assets continued the trend for last year with impressive growth. In the U.S. onshore we added 263 million Boe with the drill bit compared to production of 110 million Boe. Drill bit capital of 263 million-- drill bit capital applicable to the 263 million barrels of added reserves was $2.6 billion. So the reserves that we added in U.S. onshore were done at a very attractive unit cost. In Canada, extensions, discoveries and performance revisions added 129 million Boe reserves, compared to production of just less than 58 million Boe. With related capital for the year of 1.4 billion, Canada delivered a strong performance both from a unit cost standpoint and from a reserve replacement standpoint. We ended 2006 with 108 million barrels of proved reserves booked at Jackfish compared to 118 million barrels at the beginning of the year.

Now to the U.S. onshore, as we discussed earlier we have not yet begun to book reserves from our discoveries in the lower tertiary. Until those reserves meet various booking criteria our gulf shore properties are likely to continue to outproduce our reserve additions, and this has been the trend for sometime. In 2006 we added about 16 million Boe compared to production of 22 million Boe. The associated drill bit capital expenditures in the Gulf of Mexico were $674 million.

Much of this capital went to the Deepwater exploratory and delineation drilling including the successful Jack test where reserve bookings will come in future years. After combining the various reserve components, Devon finished the year with nearly 2.4 billion equivalent barrels of proved reserves, 13% growth over year-end 2005 and 80% of those reserved additions were added through the drill bit as opposed to acquisitions. These results also extended our company's reserve life index by 18%, our reserve life index is now up to a little over 11 years. To summarize, 2006, very good year for Devon. We delivered strong financial results, strong operating results, and most importantly, set the stage for continued profitable growth well in to the future. Based on the continuing outstanding performance of our North American exploration and development programs both onshore and offshore, we made the decision to redeploy our resources, both financial and intellectual and refocus our international asset base. This lead to our recent announcement of our decision to exit Africa.

Looking ahead I couldn't be more excited about Devon's outlook. In 2007, excluding our African assets we are targeting drill bit reserve additions of somewhere between 350 to 370 million Boe versus projected 2007 production of around 220 million Boe. With drill bit for the Company as capital expected to total 5.3 to 5.7 billion for the year, we are again looking at a very competitive performance both from an F&D standpoint and from a reserve replacement standpoint.

At that point I'm turn the call over to Steve Hadden. Steve?

Thanks, Larry, and good morning to everyone. As Larry said we had a very active year operationally including a number of high-profile successes. The full year we drilled about 2500 wells with a 98% overall success rate. At the end of December we had 130 rigs running company wide with 71 rigs drilling Devon operated wells. This was about the same level of reactivity as at the end of the third quarter. 2006 capital expenditures for exploration and development projects came in at $4.9 billion, including $1.4 billion invested in the fourth quarter. To get to the 5.2 billion of drill bit capital that Larry referred to, you must add in 300 million of capitalized G&A and interest. Now let's move to our quarterly operational highlights starting with the Barnett Shale field in north Texas. We reached another milestone with the drilling of our 600th operated horizontal well in December. It was just about four years ago that we drilled our first horizontal well in the Barnett. We are currently at record activity levels in the Barnett with 30 Devon-operated rigs running, including 12 high-efficiency rigs. Of the 30 rigs 13 are working in the core area and 17 are drilling outside the core including eight in Johnson County.

During the fourth quarter, we completed a total of 105 Barnett wells of which 43 were in the core area, and 62 were outside the core. At year end we had 43 Barnett Shale wells awaiting connection to the producing grid down from 56 at the end of the third quarter. When we announced the Chief acquisition we said we expected to grow our net Barnett production to 710 million cubic feet per day by the end of the year. We reached that target in mid-December, a couple of weeks early and in the fourth quarter our Barnett Shale production averaged 688 million cubic feet equivalent per day up 6% from the third quarter average and up 20% year-over-year. From a reserves performance perspective the Barnett Shale was the leading growth area among our U.S. onshore properties. Extensions discoveries, performance revisions in the Barnett accounted for 148 million Boe of additions. This was nearly four times our production of 38 million of Boe and even better performance that we achieved in 2005. This performance is attributable to success with our core area horizontal infill program coupled with excellent drilling results outside the core.

Associated drilling and facilities capital was right at $1 billion. At year end including the approximately 100 million barrels of crude reserves acquired from Chief we had 608 million Boe booked to the Barnett and 78% of those reserves are developed.

As a point of reference, Devon's Barnett Shale reserve base is now nearly double the 310 million Boe we acquired with Mitchell Energy in 2002 and we produced more than 160 million Boe or natural gas terms nearly a trillion cubic feet net to Devon's interest since we entered into the Barnett Shale play.

Looking forward in 2007, we plan to invest about $1.1 billion of capital in the Barnett and drill 385 wells. Current plans are to invest about 40% of the capital inside the core, drilling roughly 10 vertical wells and 145 horizontal wells, we plan to invest the other 60% outside the core where we plan to drill 228 horizontal wells. Our primary focus outside the core will be in Johnson and eastern Parker County, and we're continuing our transition to the exploitation phase in these areas where wells are drilled more densely and quickly tied into the finished gathering systems.

About 100 of the horizontal wells in 2007 will be the 20-acre infill wells. We expect this drilling program to delivery another year of very strong production growth in 2007. By year end 2007 we expect to be producing in excess of 800 million cubic feet equivalent per day from the Barnett Shale net to our interest. This puts us well on our way to reach our long-term target of producing a Bcf a day net to Devon by year end 2009.

In the Woodford Shale in eastern Oklahoma were continuing to achieve encouraging results as we refine our completion techniques. We ran four operated rigs through most of the fourth quarter and bought a total of four operated wells online. Initial production rates range from 2.7 to 6.8 million cubic feet of gas a day. Based on these positive results we plan to invest about 105 million of capital in the Woodford drilling more than 50 wells in 2007.

Moving to the Rockies, in the Washakie Basin in Wyoming, we have five rigs running throughout the fourth quarter. For the fourth quarter we drilled 16 wells in Washakie, bringing the full year total to 57 wells on Devon's operated acreage. We also participated in 80 outside operated wells during 2006. In total we added 20 million barrels equivalent of reserves or more than three times our Washakie production for the year at a drill bit capital cost of $177 million.

In 2007, we plan to invest about $150 million of capital in Washakie maintaining a five to six rig program and drilling 55 to 60 Devon-operated wells, and another 80 outside operated wells. With over 300 undrilled locations in the field we expect to be actively drilling here for years to come.

Moving now to east Texas, we continue to advance our horizontal drilling programs in both the Carthage and Groesbeck areas. First at Groesbeck, I'll update you on five wells we drilled in the fourth quarter. Our first Bossier horizontal in the Oaks field, the Everett 10-H, has produced nearly 7 million cubic feet a day with two of the five planned frac stages yet to be completed in the horizontal section. Our first horizontal well in the Bald Prairie field, also a Bossier test, IPed at 6 million cubic feet a day, and the third well a Cotton Valley lime horizontal in the Personville field is in the process of being completed.

We also drilled two new horizontal wells in the Nan-Su-Gail field in the quarter including the Painten 11-H, that IPed at 7 million cubic feet a day. The second Nan-Su-Gail well is now being completed. This year we expect to spend about $100 million and drill at least 12 new horizontal wells at Groesbeck. Northeast of Groesbeck at Carthage, we're applying the same horizontal concept during the fourth quarter we drilled two Cotton Valley sand wells. Both are follow-up wells to the very successful Haygood 11-H well that we previously told you averaged 9 million cubic feet a day for the first 30 days of production. These two new wells have been drilled and completion operations are currently underway. We will spend about $84 million on our horizontal program at Carthage this year and we expect to keep two rigs running and drill 14 horizontal wells during the year. Also at Carthage we wrapped up our 90 well vertical Cotton Valley drilling program during the fourth quarter. We had six rigs running throughout the quarter and drilled 19 wells. Fourth quarter net production from Carthage averaged about 234 million cubic feet of gas equivalent per day which is up 6% from the fourth quarter of 2005.

In 2007 we expect to spend $285 million drilling Devon-operated vertical wells at Carthage this budget contemplates a drilling of about 100 wells including 18 20-acre infill wells. Carthage and Groesbeck also delivered excellent reserve growth in 2006. The two areas together we add 43 million barrels of reserves or more than double our 2006 production from these areas. The drill bit capital of $396 million so this was another area of strong reserve growth and low F&D.

Moving to Canada, the industry is responding to the overheated cost environment that saw regional services and supply cost up by 20% to 30% in 2006 and land prices up 30%. Our returns on Canadian conventional gas projects were further impacted by the strengthening of the Canadian dollar relative to the U.S. dollar. However, improvement may be in sight, industry wide rig utilization has fallen from record-setting levels to a fourth quarter rig utilization average that was the lowest that we've seen since 2002.

A Devon's experience is reflective of this pull-back, at the end of December we were running 22 rigs, which is about two thirds as many as we ran a year ago. When the Canadian market corrects and project economics improve we expect, again, to ramp-up the conventional program in the strong conventional business in Canada.

In 2007, we're continuing to focus on thermal oil projects and we're increasing our activity on our oil properties in the [Lloyd Minister] area. At our 100%-owned Devon Jackfish project, the thermal heavy oil project in eastern Alberta, final facilities construction continues. In late December we drilled our final horizontal production well and now have a total of 24 well pairs drilled. We expect to begin steam injection at Jackfish in the second quarter of this year leading the first production in the third quarter and full production of 35,000 barrels a day in late 2008 as planned.

At our Jackfish 2 project, we filed the regulatory application on September 29, 2006, work on engineering and budgeting is currently underway, and we expect to make a decision on whether to proceed later this year, Jackfish 2 could add an additional 35,000 barrels a day of production. Finally, in our Lloyd Minister oil play in Alberta, we drilled a 109 Devon-operated wells in the fourth quarter. In 2007, we plan to spend $218 million and drill 395 wells in the Lloyd Minister area. We currently have six rigs running at Lloyd Minister.

Now shifting to the Gulf of Mexico, first at Kaskida, we drilled a side track to our 2006 discovery well in the fourth quarter. Another well operation is planned for this year. We believer this Kaskida is the largest of the four lower tertiary discoveries that Devon has participated into date. We have a 20% working interest in the prospect, which is located in the Keathley Canyon area and is operated by BP.

At Cascade this is our 50/50 lower tertiary development project with Petrobras in the Walker Ridge area. We received MMS approval for the conception deep water operating plan in the fourth quarter. We hope to approve and sanction the project for development in 2007 with first production still scheduled from Cascade in late 2009.

At Jack, also in the Walker Ridge Deepwater lease area, Devon and our co-owners continue to evaluate development options we plan to be drilling a second delineation well in the second half of the year. The Jack 3 well could potentially be drilled with the ocean endeavor deepwater rig that Devon has under long-term contract. That rig is currently awaiting the arrival of a transport vessel in Singapore and we expect delivery to the Gulf of Mexico during the second quarter. We also plan to drill a second delineation well in St. Malo in late 2007 or early 2008 Jack and St. Malo could potentially be developed jointly and the results of these two delineation wells will contribute to that planning process. Devon has a 25% working interest in Jack and a 22.5% working interest in St. Malo.

Our success in the Gulf of Mexico extends beyond the lower tertiary. Our Deepwater Miocene program-- in our Deepwater Miocene program we made a fourth quarter oil discovery on our Mission Deep prospect located in Green Canyon 955 in roughly 7300 feet of water. The discovery well encountered more than 250 feet of net oil pay in the primary middle Miocene objective, the well's currently being side tracked to further delineate the size of the reservoir. Devon has a 50% working interest in Anadarko with the operator. Also in our Deepwater Miocene program, the Caterpillar Expiration well operated by Chevron on Mississippi Canyon 782 was drilled to 27,300 feet and has been plugged and abandoned. Devon has a 25% working interest in Caterpillar.

In the eastern Gulf of Mexico we continue with the installation of subsea equipment for the two planned producing wells at Merganser in the Atwater Valley area in the fourth quarter. The independent sub production platform is now on location with installation underway. Production startup is expected early in the second half of the year. Merganser will produce into the independence hub at about 50 million cubic feet of natural gas per day, net to Devon's interest.

Next moving to the international arena, our Polvo oil project on block BMC8 in Brazil remains on schedule. We finished installing the platform in December and have become offshore hook-up operations. The FBSO conversion is nearly complete and sale-away is scheduled for later this month. The trip from Singapore should take about 35 days once it begins, and we expect to begin development drilling from the platform in March and expect first production, again, around midyear as planned. We booked about 9 million barrels of oil equivalent at Polvo in 2006 and expect to book additional reserve in 2007 as the producing wells are drilled and the projects bought on line. Devon operates this 50 million barrel Polvo project with a 60% working interest.

During the fourth quarter we began drilling the first of three exploration wells on BMC8. Two wells have now been drilled to further define the blocks potential and we're currently evaluating those results. Finally, in Azerbaijan where Devon has a 5.6% interest in the ACG oil field gross oil production climbed to 639,000 barrels of oil a day in December. Devon's share of ACG production should average over 30,000 barrels a day for 2007. That concludes the operations update. Now I'll turn it over to John Richels to review our financial results and the 2007 outlook. John?

Thank you, Steve, and good morning, everyone. I'll begin by looking at some of the key events and drivers that impacted our 2006 financial results. I will also provide some incite in to our plans and expectations for 2007. As Vince mentioned at the outset, during the fourth quarter we announced plans to divest our assets and to terminate our operations in Egypt. As a result in accordance with accounting rules we reclassified the assets, liabilities, and results of operations in Egypt as discontinued operations for all accounting periods presented. For the purposes of this conference call, I'll focus most of my comments on our continuing operations, which excludes results attributable to Egypt. In addition to exciting Egypt, on January 23rd, we announced our intention to sell all of our interests in West Africa. Since this announcement occurred in 2007. Data related to West Africa is still included in continuing operations at December 31, 2006. However, beginning with the first quarter of 2007, West Africa will also be treated as discontinued operations.

With that, let's begin with production. For 2006. Devon reported full year production of 216 million barrels equivalent with 2 million Boe's coming from Egypt, leaving 214 million Boe's from continuing operations. That's approximately 587,000 Boe per day from continuing operations and right in line with the guidance we provided in December. Our 2006 production performance was headlined once again by strong production growth in our core U.S. onshore properties. U.S. onshore production from retained properties lead by the Barnett Shale grew by nearly 6 million barrels when compared to the previous year. However, this growth was offset by 2005 property divestitures and continuing deferrals in the Gulf of Mexico in 2006, due to the 2005 hurricanes.

Fourth quarter production came in at 56.4 million equivalent barrels or 613,000 barrels per day. That's nearly 40,000 barrels of production per day or 7% higher than the fourth quarter of 2005. When you examine our fourth quarter production in greater detail, you'll find that we experienced very good growth in every producing region other than Canada. In Canada, production decreased by 5%, compared to the fourth quarter of 2005, or approximately 8,000 equivalent barrels per day. This resulted from a decrease in our conventional gas drilling activity that we discussed during our last call due to the current high cost environment in Canada.

The U.S. onshore segment grew by 22,000 Boe's a day or 7% over the fourth quarter of 2005. Due to our successful restoration of most of the hurricane impacted volumes, production in the Gulf of Mexico also increased by 9,000 Boe's per day or 17% over the fourth quarter of 2005. Fourth quarter international production grew by more than 25% driven by the ACG field in Azerbaijan.

Looking ahead in 2007, we expect to accelerate production growth. For the full year 2007, we expect to produce between 219 and 221 million Boe's from continuing operations. The midpoint of this range represents a 10% increase over 2006 production of 200 million barrels when you adjust for the sale of West Africa. This growth will be driven by the continued performance from our U.S. onshore properties, a full year of production from the ACG field in Azerbaijan and midyear start ups of production from both the Company's Merganser field in the deepwater Gulf of Mexico and the Polvo discovery offshore Brazil.

For the first quarter of 2007, we expect production from continuing operations to come in between 52 and 53 million equivalent barrels or approximately 583,000 Boe's per day. This compares to fourth quarter 2006 production adjusted for the sale of West Africa of approximately 574,000 Boe's per day.

Shifting now to price realizations and starting with oil, the WTI benchmark oil price remains strong throughout 2006, averaging $66.22 for the full year. This represented a 17% increase over 2005 prices. However, Devon's realized oil price increased significantly more, up 53% in 2006 to $58.30 per barrel, this was driven mostly by the expiration of hedges that negatively impact our oil price realization in 2005. Higher price realizations versus benchmark prices as the result of more favorable price differentials also contributed to the 2006 improvement in realized prices.

On the natural gas side the benchmark Henry Hub index averaged $7.24 per MCF for the year, a 16% decrease from 2005. In 2006, company-wide natural gas price realization were close to the mid-points of our guidance ranges. In the 8-K that we're filing today we provided detailed guidance for our 2007 natural gas and oil price differentials.

Turning now to our marketing and midstream operations, once again marketing and midstream delivered very impressive results. In the fourth quarter we generated $102 million of operating profits, bringing the full year up to $448 million this is in line with the guidance from our third quarter conference call. Our full year 2006 marketing and midstream results were aided by better than expected NGL prices and frac spreads.

Looking forward to 2007 we're forecasting marketing and mid-stream operating profit in the range of $390 to $430 million.

Now moving to expenses, most of our 2006 expenses were in line with guidance. As expected, on a year-over-year basis, almost every expense category increased due to the upward pressure on services, supplies and personnel costs. This is of course a reoccurring theme within the E&P sector. In addition, due to Devon's large presence in Canada, the strengthening of the Canadian dollar contributed to higher reported costs. Compared with 2005 the average Canadian dollar exchange rate increased by 7% in 2006. Our reported 2006 lease operating expenses came in just under $1.5 billion, or $6.95 per barrel produced. This is a few cents above the high end of the guidance range we provided in the third quarter. For the full year Devon's unit operating costs increased by 17% compared to 2005.

We're anticipated continuing although lessening pressure on costs in 2007, and are forecasting full year operating expenses to be in the range of $7.70 to $8.05 per equivalent barrel. Devon's full year DD&A expense for oil and natural gas properties came in at $10.59 per Boe, that's right in the midpoint of our guidance. The DD&A rate increased primarily due to higher capital costs and also increased estimated future development costs. In 2007, we expect DD&A costs to continue to increase, but at a lesser rate than in 2006. For 2007, we anticipate our DD&A rate to be in the range of $11 to $11.50 per Boe.

Interest expense for 2006 was $421 million, which is near the bottom of our full year guidance range. When compared to 2005, reported interest expense decreased by $112 million or 21%. This year-over-year decrease is primarily due to the lower debt levels in 2006 prior to the Chief acquisition, and also some one-time charges that we incurred in 2005 related to the early retirement of debt.

Looking to 2007 we expect to retire $400 million of debt coming due in October and to pay down our commercial paper obligations following the close of our African divestitures. Assuming a midyear payoff at our commercial paper, we're forecasting interest expense of $400 million to $410 million in 2007.

The next expense category that I will cover is the line item entitled change in fair value of financial instruments. For the full year 2006 this reported expense increased to $178 million. As many of you know, this is a non-cash charge related to fluctuations in the theoretical value of the option embedded in the Chevron exchangeable debenture on our balance sheet.

The final expense item that I want to touch is on income taxes. Devon's reported income tax expense for the fourth quarter came in at 32% of pre-tax income. After backing out the impact of items that are generally excluded from analysts estimates our adjusted fourth quarter income tax rate was 32% of pre-tax earnings, 12% current and 20% deferred.

For the full year 2006, our adjusted tax rate was 34% of pre-tax earnings with 20% current and 14% deferred. That's right at the midpoint of our full-year guidance and similar to the rates that we would expect in 2007 on earnings from continuing operations. As is our practice in today's earnings release we provided a table that reconciles the effects of items that usual excluded from analyst's estimates.

Cutting to the bottom line we reported net earnings in the fourth quarter of 582 million or $1.29 per diluted share. After backing out the impact of items that are generally excluded from analyst's estimates we had net earnings of $1.36 per diluted share. This equals the FirstCall consensus.

For the full year, our adjusted earnings were $6.34 per diluted share. This is the highest annual earnings per share in Devon's history. Before we open up the call to Q&A I want to conclude with the review of Devon's overall financial position. We began 2006 with $2.3 billion of cash and short-term investments. During 2006, our cash flow before balance sheet changes, reached a record $6.1 billion. We invested roughly $5.2 billion in drill bit capital and $2.3 billion on acquisitions, invested an additional $560 million of midstream and corporate capital, ate out roughly 200 million in dividends and repurchased in excess of $250 million of our common stock. Since closing the Chief acquisition mid-year 2006 we reduced our net debt balance by over $400 million with cash flow from operations and we ended the year with $1.3 billion of cash and short-term investments. In March, we increased our common stock dividend by 50% to rate of $0.45 per share. This is the third year in a row we have increased our dividend. In addition through stock repurchases we have reduced or diluted share count by over 50 million shares since the beginning of 2005, and as we announced in January we expect to resume share repurchases in the second half of 2007, after the West African divestitures are closed.

Looking forward, we are all very excited about Devon's outlook and we believe that we are very well positioned to continue to build value. And with they'll turn it back over to Vince to open it up for Q&A.

Thanks, John, just a couple of items, one we had misspoke a number in the call on the Jackfish year-end reserves, we said that that was 108 million barrels at year-end 2006. That's actually 186 million barrels, which compared to the beginning of 2006, we had 118 million barrels booked at Jackfish, so the net extension, discoveries and revisions including price revisions were about 68 million barrels in 2006 at Jackfish. The other thing I want to bring up, is it's my understanding that Thomas Financial's webcasting system is down and that all companies that use them -- and I think they are the predominate provider -- that their webcasts are failing today so for those of you that had to switch over to a dial-in we apologize for that failure and to those of you that listen later today we apologize as well. The webcast we are hoping to get a replay of the webcast put up on the website later today. With that, we'll take the first question.

Thank you. Our first question comes from Tom Gardner of Simmons & Company.

Good morning, everyone.

Morning.

By the way my Thomson is scrolling now. It appears to be working. But just moving on here, in your earnings release you made no mention of 2007 CapEx. I'm assuming it's the same as the December 19th, 5.6 to 5.8 billion. In light of uncertain commodity prices, what would cause you to revisit your capital spending and how frequently do you review it and what would be the lag time in making any changes going forward in '07?

Tom, we-- we tend to review that on a fairly periodic basis, we go through a capital budgeting procedure with all of our divisions and also a midyear update and keep pretty close ties on that. As you can imagine we're making most of our decisions based on longer-term horizons than just a quarter or half year. So I think as we-- if we were to move forward with any kind of reductions this year, we would have to see a fairly significant reduction in price because we're-- we have really ramped up a lot of activities for this year, which-- which are in the works. There are some areas that-- putting the breaks on activity is easier than in other areas. However, we're taking a longer-term view, and we're still very confident that we're going to see longer-term higher prices on both the natural gas and the oil side.

That's helpful. Impressive results in east Texas. I didn't hear you give an update on the Crenshaw 14-H and Nan-Su-Gail given the large [cumes] reported in the first two months and could you address the types of horizontal well applications that may not be adding value over vertical wells in east Texas?

Yes, this is Steve, when we-- the Crenshaw well was the well I believe that we completed with an IP of over 30 million a day that well now in five months has produced [cume] of 1.7 Bcf. So it had a tremendous economic return in payout very quickly. It's now settled down at about 9 million cubic feet a day. So it is currently producing about 9 million cubic feet a day. So very good well and we're very pleased with those results. I think as I summarized for you, we're at various stages of testing and exploring the application of the horizontal drilling, not only in Groesbeck and Carthage but in a few areas around the Company.

To answer your question about where it is not applicable, it really is dependent on both the reservoir and the reservoir characterization work that we do, and the completion techniques that we're working on. We have-- in the summary that I gave, I think I talked about four or five different wells. We actually looked at several different completion techniques in there in that group of wells in an effort to continue to optimize both the well performance and the economics going forward. Typically what we see in the success cases are wells that-- might cost about three times the vertical well but they deliver about five times the rate in the EUR, so it's a very good economic proposition for us. It's a little early, at least in that part of our portfolio to talk more about what's working and what's not working. We'll have some more results here certainly by the end of this quarter and have a lot more detail.

Thank you for that and just one last quick one, regarding divestiture efforts in Egypt and West Africa. How are they proceeding and what its the overall market for international assets right now?

We think the market for those international assets is quite good. It mainly comes from non-U.S., and indeed non-western players, but there's a good market there that we see is there and that the advisors we have hired to sell these properties believe is there too, which is one of the reasons that we're disposing of those assets. We're preparing the data rooms and are very confident we'll have those transactions closed, in the second quarter and third quarter, certainly by the end of this year.

Thank you, guys.

And Tom, if-- as you know the West African divestiture as Larry said we're just preparing the data rooms, but to the extent we have tested the market with Egypt as you know we announced that earlier, we're seeing a lot of interest, so there's still quite a vibrant market.

Tom, this is Vince, I'm going to take your first question now last and then exploration and development budget for 2007 is $4.9 to $5.3 billion. When you add in the other items that are included in drill bit capital we expect that to total $5.3 to $5.7 billion in 2007.

Thanks, Vince.

Our next question comes from David Tameron from Wachovia.

Good morning. Up in Canada, can you talk a little more-- I know the deep basin you pulled back some activity production turned over a little bit. Can you talk a little bit about that? And kind of at Iron River, I know it's a lower risk type place, what you are seeing and what the plans are there as far as ramping production over the next few years?

Yes. David, this is Steve. As we look at Canada, we see a couple of things going on. On the convention business, which I might say is a business that we're still very interested in that has great running room and good resources behind it, with the escalation of costs that we saw, I think over '06 we saw them as high as 20% to 25% cost escalations. That along with the movement in FX against us really caused us to take another look at the economics plus the ending power as far as the amount of activity per dollars went down dramatically. Just to give you an example, if you look at-- I think our 2005 activity level, we're probably down on an activity basis by about 40% to 45% on activity in the conventional gas business, and we're really high grading our opportunity base. Our team in Canada is very focused on generating a solid inventory but also going through in some creative ways to optimize economics on the program we are executing and to continue to develop an inventory for time when we see that business turn.

We have seen some-- as I mentioned in the discussion earlier, we have seen the rig count drop. We're also seeing some reduction in the inactivity. We're seeing competitors pull back on their investments, matter of fact industry pulled back on their investments there, and we're seeing a flattening and an improvement in the market there relative to the cost, which we think are out of line with where commodity prices are relative to the opportunities in that business. We think that that will return over time. We'll see how long that takes, and we are prepared to ramp that conventional business back up when that occurs. On the thermo side-- let me go to Iron River. On the cold flow heavy oil side in Lloyd Minister and specifically in Iron River, we're continuing to drill wells as we planned initially. We're going to ramp-up from about-- I think when we got it, it was about 3,000 barrels a day and we're going to drive it to 30,000 barrels a day by 2010.

We are well on track to do that. I will tell you that the wells have either met or exceeded our expectations from both a reservoir standpoint and a performance standpoint for those that are on. We also have been doing some upgrading of the facilities there where we'll be turning on some facilities probably here in late first quarter, early second quarter. Where the actual productivity capacity will go up in a step change as a result. Everything is going very well there, and production is on track to that it 30,000 barrel a day target by 2010.

Thanks, and then one question for Larry. Big picture, everybody talks about the majors coming back to the U.S. Are you seeing an increased interest from the majors in some of your plays? Or can you address that a little bit? Have you seen any change from the majors?

Oh, I don't think we have seen any major change. Of course, the positions that we have established through our acquisitions and our leasing effort over the years have given us a pretty significant position already, where-- like the Barnett Shale we can stick to our knitting and just drill away with having ramped up to 30 drilling rigs we're not really seeing much change, certainly not onshore. The majors have always had a continuing interest in the deep waters in the gulf, and we don't see much relative change there.

Okay. Thanks.

David Heikkinen from Pickering Energy you may ask your question.

Hi, guys. Vince, one thing, I couldn't hear you very well on the Jackfish reserves. Could you just repeat that?

Sure, sorry about that we ended 2006 with 186 million barrels of proved reserves booked at Jackfish. That compared to year end 2005, 118 million barrels booked. So that's a net change of 68 million barrels, which includes extensions, discoveries, and revisions.

Okay. And then the production ramp in Brazil at Polvo with FPSO moving out, and wells already completed, waiting hookup, how would you see that production ramp and in to what rate mid-this year?

The-- at Polvo, right now we have the platform set we're currently constructing the Derrick for the rig, the platform rig, and we'll begin driving conductor and drilling late in the first quarter, early in the second quarter. We still plan for first production midyear.

Uh-huh.

That production will begin to ramp-up relatively is quickly, and I think we'll be at about net to Devon probably 26,000 or so barrels a day net to Devon when we hit the peak. We'll ramp that up. I'm guessing we'll hit that sometime year end or so.

Okay. And then on the Deepwater lower tertiary apprassil work, everything kind of second half of the year, that's all driven by rig availability and no other reason than that?

It's driven-- it's obviously-- these reservoirs are deep and very large and very valuable, but they also require a lot of planning, so we have integrated project teams with partners where each of us have people working on both the technical issues, the issues on rig slots, and the issues on the commercial configuration to develop those. So it's really those three things that are driving the timing of these of these wells and what we're trying to accomplish. We completed the Jack test last year, and have been continually digesting that information and working through analysis of that, and that takes some time too before we go out and drill the next well. So it's-- obviously we time it relative to the availability of rig slots, but some of it that timing is also driven by those other two things.

One final quick question. On the east Texas horizontals my understanding is you-- talking about the Cotton Valley sands -- you want to have one primary sand that you are drilling horizontally as opposed to, and where you are drilling the vertical wells is where you would have multiple objectives that you would want to complete all of those objectives. Is that a fair simplification of where you would go horizontal and where you could go vertical?

Actually when you look at it we have-- the targets we are drilling are both the Cotton Valley sand and a little deeper in the Bossier, another section and in the Cotton Valley lime also up hole we have drilled horizontals in the Travis Peak. So their multiple zones. Now on any individual well as we drill these, we're drilling along-- extended ridge horizontal sections that could be 2 or 3,000 feet long and doing multiple frac jobs along that horizontal section. Now that doesn't necessarily mean we only contact one of the one thin zone that's in that horizontal section because when we frac the zone we contact those multiple layers that are within those larger sections. So we are getting a good contribution, as I said before the vertical wells, we get about as much as five times the rate that we would get from a vertical well and one of the reasons is we are contacting a lot of the formation that the vertical wells do but we're doing it over an extended area with the horizontal reach.

Okay. Thanks a lot.

Our next question comes from John Herrlin of Merrill Lynch.

Sounded like the dog liked that drilling result. Anyway, with Cascade, you said that you got conceptual approval for the FPSO or the development. How does the MMS looking at the FPSO, Steve?

Well there's a process that is well prescribed that we go through there we put together an initial Deepwater operating plan that has gone to the MMS, and they review it that conceptual plan has been reviewed a signed off by the MMS. The next step is to get the final Deepwater operating plan approved. Part of what goes on in between is just a series of questions and additional, more detailed information that the partnership will provide to the MMS to ensure that we have met all of their requirements and answered all of their questions to their satisfaction. Again, we think we're on track to both have the appropriate approvals also and sanction the project this year.

Okay. Two other quick ones for me. Your selling foreign assets, what about China, Larry?

We like what we see in China so far. We have added some good acreage there that offsets some very attractive gas discoveries, and it-- we don't see any reason to do anything with China now. We're quite excited with it, as we are with the success that we're having in Brazil.

On Jackfish, there's a lot of talk about inflation up at Fort McMurray, what are you seeing on your side for your project?

We're seeing relatively good performance as it relates to cost on the project. The project has been over two years in putting it together. We have seen some-- some cost escalation. We haven't seen it as far as escalations, we haven't seen it to the point that we have seen it on our conventional side of the business as far as just pure cost escalations. We have made some scope changes over the last two years that have enhanced the economics of the project such as having the ability to both handle and blend with condensate and/or synthetic crude which really haven't enhanced the economics of the project, but those were additional scope changes. We're now getting to the point to where we're going to look at the finalized cost here pretty quickly and have some pretty solid numbers, but I think we near a reasonable range, and we have seen some of our competitors up in the 40% to 50% range of escalation on their cost and we have not seen that on our project.

The other thing, John, it Richels, the other thing is that's always important to remember is a lot of the escalations and the cost inflationary numbers that we've seen are on the big mining projects which are much more facilities intensive than the SAGD project. We spend about half the money on the SAGD project drilling wells over time and about half of it on the above-ground facilities. So that's where-- that's where the press-- we have seen a lot in the press about the overruns, but it's been with the larger project.

Thank you.

Our final question comes from Jason Gammel from Prudential.

Thank you. Another follow-up on Jackfish. I was hoping you could address any particular marketing arrangements you might have for the output there? Have you secured export pipeline capacity, etc. and how should we think about the differentials you'll receive on that output?

Yes, Jason this is Darryl Smette. We continue to negotiate both for the purchase of condensate which looks like it's a going to be the [inaudible]-- initially use. So we continue our negotiations for the procurement of the condensate and for the markets for the blended crude. We are not at a point where we can make any announcement, but those discussions are going on with a number of parties. It's our hope that we will have most of those concluded in the next 60 days. So that's progressing very well, we think.

As it relates to differentials, when we blend and whatever product we used to blend, unless indicates condensate, we are going to end up with about a 20 degree API crude, it's basically going to look like an LLB benchmark crude up there. Right now, we think that that's differential historically has run between 30% and 35% of WTI, based on how we look at the market dynamics in terms of demand for that type of crude in the different facilities, export capacity, we think over time that that reduction from WTI will be consistent in that 30% to 35% range.

Very helpful Darryl, I appreciate that. If I could sneak one more in was there anything that prevented you from booking reserves at Cascade this year, other than a very conservative approach?

We're moving along in a very judicious manner, looking at the facts around the meeting the requirements for a proved reserve development and there's really nothing out of the ordinary that has caused us not to book reserves at Cascade. We're simply going through the process that we would go through on any of our offshore projects to meet the requirements to move resources in to the proved category. It's kind of business as usual and it's just the normal timing of the project.

Okay, thanks, Steve.

Okay. In a quick summary as you can see we think 2006 was a very significant accomplishment for Devon. A very good year. Earnings per share cash flow reached all time highs. We more than doubled the year's production with our drill bit reserve additions, and we did that at a very competitive cost just like we did last year. Most importantly, we entered 2007 poised to continue those trends and poised to continue to accelerate our production growth through 2009, which is as far as we have forecasted, beyond that we position our inventory particularly in the Deepwater and we should be able to continue that growth well beyond 2009. So we are very happy with where we are. Thank you very much for your participation in this call. Take care.

That ends today's call.