德文能源 (DVN) 2005 Q4 法說會逐字稿

Welcome to the Devon Energy corporate fourth quarter 2005 year-end conference call. [OPERATOR INSTRUCTIONS] 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 everyone to Devon's year-end and fourth quarter 200 conference call. I'm going to begin with some usual introductory remarks and then our Chairman and CEO, Larry Nichols, will give us an overview of Devon's 2005 accomplishments. Following Larry's comments, our President, John Richels, is going to cover the operating highlights of the year, and then Brian Jennings, our CFO, will cover the financial results and our outlook for 2006. At that point we'll open up the call to your questions. For any that don't get answered in this one-hour call we'll be available this afternoon by telephone.

Before Larry starts, I need to remind you that we're filing a form 8-K later today. That 8-K will detail all of Devon's 2006 full-year forecast for production, price, realizations, expenses, capital expenditures and so forth. In today's call we're going to reference some of those forecasted items, but the 8-K will provide additional detail. We'll get that out early this afternoon. For those of you that are on our contact list we'll be e-mailing out the 8-K this afternoon. You'll be getting it. You'll be receiving it. For those that are not, you can get that at our Web site, that's devonenergy.com.

Our comments today when we talk about our forecast, those are forward-looking statements as defined by the Securities and Exchange Commission. There are a number of factors that could cause our actual results to differ from these estimates. I'd encourage you to read the risk factor discussion in today's form 8-K. One final compliance item, we will use metrics today in our call that under U.S. securities law are non-GAAP performance measures. When we utilize those metrics we're required to provide certain disclosures about those measures. That information is posted on our Web site, currently. With those items covered, I'll turn the call over to Larry.

Thanks Vince and good morning everyone. The results that Devon announced today make it clear that 2005 was the best year of Devon's history. Our net earnings for the year climbed 34% to a record $2.9 billion. More importantly, earnings per share climbed more than 40% to a record $6.26 per diluted share. Cash flow before balance sheets for the year also reached a record $5.7 billion. Utilizing that cash flow from operations as well as the $2 billion from the divestiture program that we had selling our noncore assets, we funded $4 billion in capital expenditures. We repurchased 2.3 billion of Devon common stock, and we repaid $1.3 billion in debt.

More importantly, while those are good results, more importantly, we had an extremely active and successful year with the drill bit. We entered 2005 with the stated target of adding 330 million to 380 million Boes, through drilling extensions and performance revisions. A couple of months ago, just back in December, we increased that forecast to 410 to 420 million Boe. Our actual results came in even better than that with 439 million Boe of drilling and performance additions. That 339 million Boe number is the highest level of drill bit additions in Devon history, and it is almost double the 226 million Boe that we produced in 2005.

And I remind you that our reported 2005 production of 226 million Boe included 10 million barrels produced from properties we sold earlier in the first half of the year. These reserve additions were achieved with total drill bit capital of just over $4 billion. And this includes capitalized interest and administrative costs. And it also includes about $160 million for the undeveloped acreage that we acquired at Iron River in Canada. This give us another year of very attractive reserve replacement rate and unit finding costs. We are confident that these results will compare very favorably with the overall industry.

Company-wide reserves this year were essentially unaffected by price revisions. Acquisitions also of proved properties had very little impact this year, adding just about 4.5 million barrels. Once again in 2005, our core North American onshore assets drove the results. We added 219 million Boe, right at half of our total company-wide additions with our onshore U.S. properties. Drill bit applicable to these reserve additions was 1.6 billion, so the reserves were added very efficiently. These reserves added more than double our 106 million Boe of production from U.S. onshore.

In Canada, our results were also impressive. 205 reserve additions in Canada from discoveries, extensions and performance revisions totaled 184 million Boe, or almost three times the 62 million Boe that we produced in Canada. The total capital associated with that 184 million of barrels of added reserves was 1.6 billion, so those were added at an attractive cost too. These low cost reserve additions came from throughout our North American onshore asset base.

Barnett Shale, in north Texas, Devon's largest development project, was Devon's most significant source of domestic reserve growth. The Barnett provided drill bit reserve additions of 115 million Boe versus production of 34 million Boe. Drill bit capital associated with Barnett Shale was $525 million. Reserve additions in the Barnett included 54 million Boe for extensions and discoveries, and 61million Boe for performance revisions. Better than expected performance from our producing properties drove these positive revisions. These additions increased our year-end proved reserves in the Barnett to a record high of 408 million Boe.

Let me give you a little perspective on the Barnett reserves. When we acquired our interest in Barnett through our Mitchell acquisition in 2002 we booked proved reserves of 310 million Boe. Since then, we have added over 200 million Boe of proved reserves and produced 125 million Boe. To put that in natural gas terms, we have added 1.3 tcf, trillion cubic feet, of proved reserves in the Barnett in less than four years. And we believe we're just getting started. With 550,000 net acres and several thousand potential drilling locations, we have years of drilling in front of us. This represents trillions of cubic feet of potential reserve adds for Devon. And of course, Devon also continues to produce more gas than any other operator in the Barnett shale and do that by a wide margin. In 2005 we grew Barnett shale reserves significantly both inside and outside the core, while also reducing our percentage of proved undeveloped reserves from 14% to 12% of Barnett reserves. So we've not accomplished that growth by just hyping PUDs.

Devon's most significant reserves addition in Canada was 118 million barrels from the Jackfish oil sands project in Alberta. We announced our decision to develop this 100% Devon-owned Jackfish property as steam assisted gravity drainage project back in 2003. In 2005, last year, we booked the first of an estimated 300 million barrels of reserves. We invested $179 million of drill-bit capital in Jackfish in 2005 bringing our total project capital expenditures to date to $215 million. We expect Jackfish to produce 35,000 barrels a day by 2008. Jackfish II, which is still in the planning stages, could potentially double that output with first production coming as early as 2010. With little geologic risk and virtually flat production for 25 years or more, Jackfish is a very valuable asset. And this is evidenced by the very steep prices that have recently been reported for the sales of high quality oil sand projects in this area.

Other sources of reserve growth in Canada include Deep Basin and the Lloydminster. In the Deep Basin, which is a very Lakewoods-rich gas. We had 25 million Boe from extensions and discoveries net of performance revisions. This was about double what the Deep Basin produced of 13 million Boe last year. At Lloydminster we added 24 million Boe with the drill bit and, also acquired 3 million Boe associated with our Iron River acreage purchase. As you may recall, we acquired 165,000 net acres from Exxon in the Iron River purchase comprising about 800 million drilling locations. Lloydminster production was about 8 million Boe last year, and we expect this number to increase this year and for several years in the future.

Another growth driver in 2005 was the Carthage area in east Texas. We added 27 million Boe from drilling and performance revisions with a drill bit capital investment of $185 million. This 27 million add compares to 13 million Boe production at Carthage. In the Rockies, in the Washakie area in Wyoming, we added about 13 million Boe of new reserve. We produced about 5 million Boe from the Washakie and increased drilling activity to 88 wells in 2005, expending about 120 million of drill bit capital. As with Carthage, we have a large acres position, a high working interest, and a multi-year inventory of drilling locations.

In the Gulf of Mexico and international, much of our capital budget continued to be focused on long-term capital investments that did not generate significant 2005 reserve bookings. With a long-term focus in the Gulf of Mexico we added 11 million Boe with the drill bit which did not replace 2005 production. However, the 455 million of drill bit capital that we did spend in the Gulf moves up a lot closer to significant reserve bookings and production additions. We participated in successful, delineation wells on both Jack and Cascade, and we continue to build our inventory of high impact, Deepwater projects.

Outside North America we spent $337 million and added $25 million Boe approved reserves, less than our 2005 international production of 28 million Boe. However our international reserve additions did not include any bookings from our Polvo project in Brazil or from the two discoveries we made from Equatorial Guinea, specifically Esmeralda and Venus. In 2006, this year, we expect to begin bookings reserves at Polvo, and to acquire seismic drill appraisal wells to further delineate the Equatorial Guinea discoveries. Putting it all together, we ended 2005 with 2.112 billion Boe approved reserves, with only 24% classified as proved undeveloped. When you step back, from all this, we see that after producing 226 million Boe for the year and selling 183 million Boe, Devon still grew its reserve base with drill bit during 2005.

Furthermore, our successful capital program combined with a divestiture of high decline low margin properties also improved our asset base and extended our reserve life index to almost 10 years. Summarized, Devon delivered another year of significant reserve growth with highly competitive finding and development cost while continuing at the same time to make investments in long-term projects. We are setting the stage for robust growth for future years at competitive unit cost. In 2006, this year, we expect to deliver reserve additions of 410 million to 440 million Boe with related capital and this includes capitalized administrative costs and interest in the range of $4.6 billion to $4.8 billion.

Despite upward cost pressures and intense competition for rigs equipment and personnel, for the third year in a row we expect again in 2006 to deliver very attractive finding and development costs. In addition, the reserve growth we are delivering in 2004, 2005 and 2006 will translate into significant production growth beginning in 2007, as we have forecast for some time. These results demonstrates Devon's ability to achieve organic growth. More importantly, we are growing value per share. We laid out our long-term value creation strategy at the end of 2004. We said that we are positioning the Company to provide sustainable growth in value per share.

In 2005, the combination of our reserve growth and the share repurchases yielded an 11% growth in reserves per share. And this growth was achieved while simultaneously selling $2 billion of noncore properties and reducing debt. In 2006, we're committed to continue on this path by continuing to grow reserves, reduce our share count and repay debt. At this point I'll turn the call over to John Richels. John?

Thank you, Larry. 2005 was the busiest drilling year in Devon's history. 2005 capital expenditures for exploration and development projects came in at $3.8 billion including $995 million invested in the fourth quarter. To get to the $4 billion of drill bit capital that Larry referred to you have to add in capitalized interest and G& A as well as as abandonment expenditures. For the full year, we drilled a total of 2,375 gross wells with a 97% overall success rate. At the end of December, we had 121 rigs running company-wide with 72 rigs drilling Devon-operated wells. This was about the same level of rig activity as at the end of the third quarter. During the fourth quarter, we drilled 538 wells with 68 classified as exploratory wells and 470 as development wells. On the 68 exploratory wells, we had an 85% success rate and 99% of the 470 development wells were successful.

Let's turn now to a more detailed review of some of our operations. First of all in the Barnett Shale field in north Texas, Devon continues to be one of the most active operators. At December 31 we had 17 operating rigs running in the Barnett. Six of these rigs were running in the core area and 11 outside the core, including eight in Johnson County. During the fourth quarter we completed 56 wells, of which 35 were in the core and 21 were outside the core.

Devon's net fourth quarter Barnett Shale production averaged 572 million cubit feet equivalent per day, and that's up 4% over the third quarter average. In the fourth quarter our net daily production reached 580 million cubic feet equivalent per day which is slightly less than our targeted exit rate of 590 million cubic feet per day. Actually, our production capacity exceeded 590 million cubic feet per day at year end. However, we had 22 wells awaiting tie-ins to the production grid due to temporary pipeline delays. We expect those wells to be on production shortly.

In 2006 we plan to invest $800 million of capital in the Barnett and drill 325 wells, about a 50% increase in wells drilled over 2005. We expect to grow our daily production rate in the Barnett about 9% exiting the year at a rate of 630 million cubic feet equivalent per day. Current plans are to invest about half of the Barnett capital inside the core area drilling roughly 125 horizontal wells, and 55 vertical wells, including 50 to 60 horizontal infill wells. We plan to invest approximately the same amount of capital outside the core area where we will drill about 140 horizontal wells. Our primary focus outside of the core will be in Johnson County where there are horizontal wells coming on production at rates of up to 6 million cubic feet per day.

In last quarter's conference call we mentioned the Arkoma Shale Play in eastern Oklahoma. We've picked up some additional acreage in the play, bringing our total to 78,000 net acres. We are working on two prospect areas, one in the Woodford Shale and the other in the Caney Shale. In the Woodford, we have drilled seven successful Devon-operated wells, five of which are horizontals. Four of the horizontal wells came on production or tested at more than 2.5 million cubic feet per day.

We also have interest in another six outside-operated horizontal Woodford wells. In the Caney prospect area, which is in the northern part of the play, we have drilled five vertical wells and are now drilling our first horizontal. The [Arcoma] shale plays a play in which we believe we will leverage the expertise in horizontal drilling and tight gaps completion techniques that we gained from our years of experience in the Barnett Shale. Competition for the acreage is fierce but we believe that this is a shale play that has promise. The resource potential associated with the current acreage position is is between 0.5 tcf and 1 tcf net to Devon's interest. We will continue to update you as we learn more about this play.

Moving to the Rockies and the Washakie Basin in Wyoming, we have six rigs running throughout the fourth quarter. During the quarter, we drilled 18 wells up in the Washakie bringing our full year total to a record 53 wells on Devon's operated acreage. We also participated in about 35 outside-operated wells during 2005. Devon's net Washakie production averaged 97 million cubic feet equivalent per day during the fourth quarter. While we face permitting challenges, we have several hundred undrilled Washakie locations and we're working to accelerate the drilling pace to as many as 70 operated wells per year. To that end we've arranged for delivery of two new automated drilling rigs in early 2007. In the Carthage area of east Texas we completed 121 wells and 82 completions for the year.

In the fourth quarter we accelerated our activity by adding a sixth rig. Our fourth quarter Carthage production averaged 221 million cubic feet equivalent per day which is up 5% from the third quarter. We have in the neighborhood of 140 wells planned for 2006 including a 20-acre infill test program. We are in the early stages but the results of the first infill well are encouraging. The well flowed 2.8 million cubic feet per day from three pay zones. The 20-acre down spacing works. We think we have about 50 locations. And this is in addition to our existing multi-year inventory of drilling and recompletion opportunities.

We mentioned last quarter that we hold about 200,000 net acres in the north Louisiana Bossier Play east of Carthage. The value of our position is enhanced because Devon owns the mineral interest on about 75% of this acreage. We have defined seven separate prospect areas with a cumulative risk resource potential of more than 2 tcf. During the fourth quarter we tested the Devon-Donner 1/1 Bossier well at about 6 million cubic feet per day. This is in the Anadarko-operated Dixon prospect area where we have a 49% working interest. A stepout well, the Devon-Donner 7/1 has now reached total depth and is currently being completed. Another delineation well in this prospect area, the 5/1, is currently drilling.

We also began drilling a test well in the fourth quarter in another of our Bossier prospect areas. It is called the East Vernon. This well, the Stellar 118, will reach total depth this week and we plan to test it during the current quarter. Devon operates the east Vernon prospect with a 50% working interest. To further evaluate our Bossier position in 2006 we plan to conclude 3-D seismic surveys on the Vixen and North Vixen prospect areas and drill three exploratory wells.

Turning now to the Gulf of Mexico, restoring the production suspended by last year's hurricanes is still a work in progress. We said in last quarter's call that we expect to have about 70,000 equivalent barrels restored by year end. We fell short of that goal with about 58,000 barrels per day restored at December 31st. The primary reason that we are behind schedule is the delay in getting Redhawk, the Redhawk Gap field back on line awaiting repair of third party downstream facilities. Redhawk produces about 10,000 equivalent barrels per day net to Devon. We now expect to have Redhawk plus another 6,000 Boe per day from other Gulf properties back on by the end of April. And this will bring the total amount restored up to about 74,000 barrels per day. We expect to restore approximately 6,000 additional barrels per day up production over the balance of the year.

In the eastern Gulf of Mexico, we continued with the fabrication of facilities for our Merganser project in the Atwater valley area. In early January we initiated drilling the first of two producing wells. I'll remind you Merganser well is produced in the Independence Hub, which is moving toward the scheduled completion date early in 2007. Devon's 50% interest in the [Kerr-McGee] prospect operated Merganser prospect is expected to net us over 50 million cubic feet of gas per day beginning in early 2007.

In the Deepwater lower Tertiary trend, the appraisal drilling we told you about last quarter at Jackson Cascade was finished last quarter with excellent results. And Cascade on Walker Ridge 206, the joint venture finished its first appraisal well around year end. This well and an updip sidetrack well were both successful in encountering and encouraging hydrocarbon coals. We are evaluating the appraisal well results and are working with our partners to move toward the commerciality decision that in our view may or may not include a production test.

On the Jack, on Walker Ridge 758, the delineation well encountered net pay exceeding that found in the discovery well. Chevron has secured the Transocean Cajun Express Deepwater rig to re-enter the Jack delineation well and conduct an extended production test beginning later this month. The completion and testing operations will continue for several months. We expect this production test to provide the information necessary to determine a development plan. Devon has a 25% working interest in both the Jack and Cascade prospects.

At St. Malo, Devon's third lower Tertiary discovery in the Walker Ridge area, Plans to drill a second appraisal well have been delayed due to rig availability. And it now looks as though that will not spud this year. In our Deepwater Miocene program we plan to spud an exploratory well late in the first quarter on the Caterpillar prospect. This is a 28,000 foot subcell Miocene target located on Mississippi Canyon 782 in 6,500 feet of water. Caterpillar is operated by Chevron and Devon has a 25% working interest in the prospect.

Turning to the Gulf Shelf, last quarter we told you about the 100% Devon-owned Chopin discovery located on the Eugene Island Block 334. THe startup of the well was delayed by Hurricane Rita and we now expect to bring the well on line in the third quarter of 2006 at a production rate of approximately 15 million cubic feet per day. Currently drilling on the shelves are two Miocene tests, the Momba Well at West Cameron 537, and the Star Five Well on West Cameron 165. Devon operates both wells. The 100% working interest in the exploratory test well at Momba which has a roughly 120 bcf mean resource potential. The star five well, which is an offset to two successful wells drilled in 2005 is a 50 to 60 bcf prospect and we have 100% working interest in that prospect.

Moving to Canada, 2005 was Devon's most active drilling year ever in Canada. We drilled 176 wells in the fourth quarter, bringing the full year total to over 1,000 wells which was 20% more wells than we drilled in 2004. We finished 2005 with record drill bit reserve additions of 184 million-barrels equivalent to nearly triple our 2005 production and delivered 5% year-over-year production growth on the same store basis. At the end of December we were running 33 rigs and we ramped that up to 41 rigs today. This winter we plan to drill in the neighborhood of 380 wells in Canada, with about $450 million of capital. Our winter efforts are focused on the Deep Basin, northeast British Columbia and Lloydminster.

Devon has historically had a dramatic spike in Canadian activity in the first quarter. However, we've taken steps to spread some of our first-quarter activity to subsequent quarters, in order to achieve a more level work load throughout the year. This should result in increased efficiency for our staff and a more efficient use of drilling rigs, oil field services and third-party contractors. Also part of our winter drilling program is Devon's [Paktoba] Well which is located in the Canadian Arctic in the shallow-water Beaufort Sea. Paktoba, with an excess of 1 tcf of resource potential is the first well drilled in the Beaufort Sea in 15 years. This is obviously a long-term project with production dependent on the completion of the Mackenzie Valley Pipeline. We're currently drilling at 7,000 feet towards an expected TD of about 7,900 feet.

At our Jackfish thermal heavy oil project in eastern Alberta, facilities, construction, and drilling are moving forward as planned. In the fourth quarter, we cased 12 horizontal wells and started taking delivery of pipe rack modules. I 'll remind you that Jackfish is a 300-million barrel project with full production of 35,000-barrels per day expected in 2008. Devon has a 100% working interest in the project.

The Access Pipeline which we're building between Jackfish and Edmonton received regulatory approval on December 1, and we have commenced right-of-way clearing operations and are currently stringing pipe. The Access Pipeline will transport bullion from the Edmonton Hub to the Jackfish area and blend crude back to Edmonton. We mentioned last quarter that we were evaluating our acreage immediately to the west of Jackfish for a potential section project called Jackfish 2.

In October, we acquired four additional sections of land within the Jackfish 2 project area. We've been drilling stratographic test wells on Jackfish 2 and the results to date are encouraging. We have 40 additional strat wells planned for 2006. Jackfish 2 has the potential to add an additional 35,000-barrels a day of production and another 300 million barrels of reserves.

Moving now to the international area, starting with West Africa, the [Guinea] and [inaudible] exploratory wells on Block 10 in Angola, and the [Kapatula] tests of Block 24 in Angola were all unsuccessful. These results led to the noncash chargeoff of our investment in Angola that we announced last month. Following the two discoveries that we made in Equatorial Guinea earlier in 2005, unfortunately the [SA] tests on Block 10 in Equatorial Guinea was unsuccessful.

We are currently drilling the [Pena] Prospect on Block 256 offshore Nigeria. This is about a 400-million barrel prospect, in 8,600 feet of water with a planned total depth of 17,600 feet. Devon was the operator with 37.5% working interest. In Brazil, our Polvo development project on offshore Block BM-C-8 continues to move ahead on schedule. The FBSO conversion is underway in Singapore and platform fabrication is underway in the U.S.

Our final development plan was approved by Brazil's National Petroleum Agency in December. We expect first production in the second half of 2007. While we've described Polvo as a 50-million barrel project, we believe there is considerable additional resource potential on the block. In 2006 we will drill three additional wells in hopes of expanding the limits of the yield. Also in Brazil we plan to begin a two-well exploratory program on Blocks B-MC-30 and BM-C-32 in March. Both wells are in about 5,000 feet of water and will be drilled to a planned depth of about 12,800 feet. Devon has a 25%working interest in the first well which is targeting a prospect of approximately 350 million barrels, and Devon will be the operator of the second well with a 40% interest from the prospect that has an estimated 500 million barrels of reserve potential. That includes the operations update. And I'll turn the call over to Brian Jennings to review our financial results and 2006 outlook. Brian?

Thanks, John, I will begin today by looking at the key events and drivers that impacted our 2005 financial results. I will also provide some insight into our 2006 outlook. As Vince mentioned, we are issuing an 8-K today that will provide additional detail about our 2006 forecast.

For 2005, Devon reported full year production of oil, natural gas and natural gas liquids of 226 million equivalent barrels. That's approximately 619,000 barrels per day. Excluding the production contributed by properties we had divested earlier in the year, our retained properties produced 216 million equivalent barrels. That's right in line with the guidance we provided in our third quarter conference call. Our fourth quarter production came in at just over 53 million equivalent barrels, also in line with our guidance.

In the quarter ,we deferred 2.8 million barrels related to production disruptions caused by Hurricanes Katrina and Rita. For the year, production deferred as a consequence of Gulf storms totaled 4.8 million barrels. When you examine the 2005 performance of our retained properties by geographical region, on a daily basis our U.S. and Canadian production grew by 3% and 5% respectively.

Our international production as expected declined in 2005 by about 19% due in large part to the impact of our production sharing agreement at the [Spero] Field. That field is our largest international producing asset. As you may recall, our share of Spero production was reduced during the second quarter when we reached a cumulative production threshold under the terms of that contract.

Looking ahead to 2006, we expect to produce about 217 million equivalent barrels. This forecast excludes about 4 million barrels of Gulf production that we expect will be deferred during the year as hurricane-impacted production is restored. In addition to restoration of hurricane-impacted volumes, first quarter 2006 production will be impacted by an operational issue at our Panyu Field in China. Due to the failure of a production riser, Devon's first quarter net oil production for Panyu will be reduced by about 500,000 barrels. That production restriction is temporary and we expect to bring Panyu back to its full capacity in the second quarter. Consequently we expect our first quarter production to come in at about 52 million equivalent barrels.

Looking beyond 2006, our long-term production growth forecast remains strong. We are on track to deliver 8% top line production growth in 2007 delivering between 232 million and 236 million equivalent barrels. Production from an array of development projects, including the ACG Field Azerbaijan, the Polvo Field in Brazil, the Merganser Field in the Deepwater Gulf, and the Jackfish Project in Canada will fuel not only robust 2007 growth but will provide growth momentum into 2008 and beyond.

Looking to our revenues, let me spend a moment on price realizations on the natural gas side. The benchmark Henry had gas priced $8.64 for the year, that's a 41% increase over 2004. As we predicted in our third quarter conference call, gas price differentials for most producing areas widened significantly in the fourth quarter. Following the hurricanes as Henry Hub spiked to around $14 per million natural gas prices in most other producing regions were relatively unaffected.

As a consequence, our fourth quarter price realizations for Canada were only 75% of Henry Hub, and our realizations for U.S. onshore were 73% of Henry Hub. However as the Henry Hub prices moderated, the differentials have again narrowed. For 2006 we expect gas price differentials to be similar to the full year 2005 average. Devon's 2005 natural gas price realizations were reduced by about $0.15 per MCS due to the impact of hedges and fixed price contracts. In today's 8-K we provide detailed guidance for both natural gas and oil price differentials.

On the oil side, the WT benchmark price averaged $56.57 for 2005 a 37% increase over 2004 levels. Our company wide realized oil price before the impact of hedges was 86% of WTI for the year. Overall, our full year and fourth quarter floating oil price realizations for all regions came in around the mid-point of our guidance range. Hedges reduced our oil price realizations by about $10.05 per barrel for 2005. Since we have no oil hedges for 2006, on the 58 million barrels we expected to produce should oil prices remain strong we will see a significant boost to Devon's realized oil prices.

Turning now to our marketing and mid stream business, strong commodity prices and greater gas throughput in 2005 led to another year of excellent performance. Our fourth quarter operating margin totaled 161 million which pushed our full-year margin to 450 million, a 25% increase of over our 2004 results. In 2006 we are forecasting lower fracture spreads and anticipate a mid stream operating margin of $360 million $400 million for the year.

Before I move on to expenses, I want to discuss our expectations for insurance recoveries related to production impacted by hurricanes. These recoveries are not booked as oil and gas revenue but rather netted against related costs with the excess recorded as other income. These expected hurricane-related insurance recoveries are reflected in our 2006 forecast as other income, and as reductions of capital cost and lease operating expense. We expect to eventually record in excess of 150 million of other income related to the 2005 hurricane activities. However, we only expect between 50 million and 70 million to be recorded in 2006 with the balance to come in 2007. Including the 50 million to 70 million from insurance recoveries, we anticipate other revenues for 2006 to total between 155 million and 175 million.

Moving now to expenses. By now everyone is aware that along with increased oil and gas prices we are seeing cost pressures. In addition, for those companies with significant operations in Canada the strengthening Canadian dollar is also contributing to higher reported costs. On a year-over-year basis Devon's 2005 lease operating and transportation expense per equivalent barrel rose 17% to $5.95. For 2006 we expect continued upward cost pressure. Consequently, we are forecasting 2006 lease operating and transportation expense to come in between $6.60 and $6.90 per equivalent barrel.

Moving to G&A expenses, we reported full-year G&A of 291 million in line with our guidance. This represented a 5% increase over 2004. Looking ahead to 2006, we estimate the G&A costs will be in the range of $360 million to $380 million. Our 2006 G&A forecast includes approximately 70 million of compensation expense related to restricted stocks and stock option grants. About half of the 70 million of expense results from the new accounting rules for expensing stock options.

As you would expect, interest expense is declining as we reduce our indebtedness For 2005 interest expense totaled 533 million. This included 81 million of one-time charges attributable to the extinguishment of zero coupons debentures, and the early retirement of our 6.75 notes. With lower debt levels in 2006 and the absence of one-time charges we expect 2006 interest expense to decrease to around $390 million for the year.

The next expense category I'll cover is the line item entitled change in fair value of financial instruments. For the full year 2005 we reported expense -- the reported expense was $94 million. $54 million of this amount is a noncash charge related to fluctuations in the value of the option embedded in the Chevron exchangeable debentures. The remaining $40 million of this line item is primarily attributable to hedges that do not qualify for GAAP hedge accounting in the fourth quarter. This primarily relates to hedges on the offshore Gulf of Mexico production that was shut in due to hurricanes.

Moving to taxes, at 36% of pretax earnings, income taxes for the full year were near the mid point of our guidance. Looking to 2006, we expect a similar combined tax rate with about two thirds being current and one third being deferred. Going to the bottom line, net earnings for 2005 totaled $2.9 billion, a 34% increase over 2004. As a result of our share repurchases earnings per share increased even more by 43% to $6.26 per diluted share. Fourth quarter earnings per share adjusted for the items that analysts do not generally forecast were $2.33 per diluted share, just above the first call mean of $2.29 per share. Our fourth quarter adjusted cash flow before balance sheet changes increased 39% to $1.8 billion bringing our total for the year to $6 billion.

Before we open up the call to Q and A, I want to spend a moment reviewing our balance sheet. During 2005 we accomplished two major capital market initiatives. We concluded in August a 50 million share repurchase project we commenced in October, 2004. We immediately announced our plans to retire an additional 50 million shares by year-end 2007. We completed our initial 50 million share program well ahead of schedule at an aggregate cost of $2.3 billion.

In addition to repurchasing shares, we retired an additional $1.3 billion of debt in the year on top of the 1 billion we retired in 2004. Most importantly in 2005 we funded $4 billion of capital investments greatly expanding our reserve base and enhancing our long-term growth outlook. We concluded 2005 holding cash and short term investments totaling $2.3 billion. That balance, which has increased to about $2.5 billion today leaves us well positioned in 2006 to continue to build shareholder value. In the year, we would expect to gain momentum with our current repurchase program having only acquired 2.2 million shares through year end. In addition to share repurchases, we have 670 million of maturing debt in 2006 that is ear marked for retirement. Finally and most importantly we have the financial strength to fund a robust capital investment program Larry and John outlined in their remarks. And at this point I'm going to turn the call back over to Vince and open up the call to Q and A. Thank you.

Operator we're ready to take the first question.

Thank you. [OPERATOR INSTRUCTIONS] Ben Dell, of Bernstein, you may ask your question.

Hi. Thank you very much. I guess I have two immediate questions for you. The first is to get some thoughts around where you see the acquisition market now and whether that's a viable option for you going forward? The second question I had was around your target of production per share of 0.65 in 2009, whether that still stands and whether it's realistic given the slightly lower numbers in 2006?

Ben? Larry Nichols. I will take the question on acquisitions. We have over the years, over the decades, tried to buy two acquisitions when they are out of favor, when prices are low. We bought Pennzoil when the price of oil was bringing $10 a barrel. We bought Michelin Anderson when the price of gas was $2, $2.50, and MCF when gas was very much out of favor because Wall Street thought gas prices would never go much above $3.50.

When you look back on hindsight, you can see that those acquisitions were exceptionally well timed. We clearly bought a position in Barnett Shale at a price that is very cheap in relationship to what all of our peers have paid to move into that market now. For us to do an acquisition now, we would have to find a set of properties or companies that we could do that would be accretive to earnings per share earnings, cash flow per share, reserves per share all of those kinds of numbers that would give us an attractive rate of return. That is very hard to do in the market we're now in. We would have to find an acquisition that would improve the quality of properties that we have now.

Over the years as we've done acquisitions we followed those acquisitions up by a pruning process. As you know a year, a year and a half ago we sold $2.3 billion worth the properties. We've done that numerous times in the past, so that each time we've done that we've improved the quality of our property base, and each one of those steps have improved in quality. We have made it more difficult to find an acquisition that does not have inferior properties.

We also would have to find a property that adds to our long-term growth. We have been building this asset base, we've talked about it throughout this call, in the areas where we see significant long-term growth. You can find properties out there today that would enhance production in '06. But the cost of that would be to dilute our growth in '07 and thereafter, and we see absolutely no reason to do that. So, while one can never say never and while you're always looking for opportunities, the chances of finding anything that would meet those very high hurdles in this year or beyond, are exceedingly remote.

You know, it's been three years since we did an acquisition. It reflects the fact that the value we see in the marketplace is not in some of these companies that have focused on short term growth and are in favor but in our own stock, which is why we bought $2.2 billion worth of stock last year and that is why we announced our second buyback. We see no reason to change that. We remain fully committed to the share buyback that we announced, the 750 million share buyback. We see no reason to change that guidance that we gave at this time.

This is a -- I'm sorry go ahead. This is Vince. I'll take a shot at your second question. I think you asked about our long-term forecast of production per share. We're essentially on track with that plan. We see nothing that changes our view. We had forecasted production for 2006 of 218 million barrels. Our current production forecast is 217 million barrels, and that's in spite of having about 4 million barrels deferred to the hurricane in the gulf. I don't think we see anything that would indicate that that long-term forecast is unrealistic.

Great. Could I just ask a follow-up? Really a technical question. If the commodity price is flat in '06 over '05, do you know what the benefit of your hedges would be for the year?

You're saying if oil and gas prices were the same in 2006 as in 2005? Well it's almost $700 million in pretax revenue hit that we took in 2005 from the impact of hedging. So you can run that through and see what the per share impact would be.

Okay. Thanks very much.

John Herrlin, of Merrill Lynch, you may ask your question.

Yes. I've got some quick ones. Let's start with Canada. It's been warm up there. You said, John, that you're going to try and schedule out your activities. Is early breakup any sort of issue for you?

Well, John, it's always an issue. But so far, we've been able to continue with our program the way we had planned. If you'll remember, we actually had a very warm winter last year as well. And that turned around about the second or third week of February and it was very cold through March. So, we certainly need some help from the weather. The good thing is the ground isn't all covered in snow there. It's fairly bare, and so, if we get some colder weather it will continue the winter program to a normal breakup time. So far, we're not concerned that we're not going to be able to get our program in.

Okay, that's fine. With Jackfish, are you going to buy bullion on the stock market? Also, could you give us a sense for what you're anticipating for Eloise and what kind of gas consumption you're going to have per unit of production?

Let's turn that over to Darryl Smette, our Senior Vice President of Marketing and Midstream.

We're currently, John, working on a number of different options for buying bullion, and we have not yet made a decision about what bullion we're going to use. Part of the reason we decided to put in the Access Pipeline was so that we would have the option to use many different types of bullion, whether it's synthetic crude, whether it's condensated, or whether it's some combination. So, we think we've positioned ourselves to use a number of bullion options. We have not yet made that additional decision, and keep in mind that we can once we start doing that we can switch types of bullion as we go through the process whichever looks economical for us. In terms of the gas price or gas used we're running that number on about one to one ratio. One mcf, one barrel of crude oil. You know, there could be some fluctuation in that. There could be a little bit more, a little bit less, but right now, that's a one to one ratio. Eloise -- about 250 Steve is saying.

Okay, great. Okay. Two other quick ones. Given the projects you're talking about, it seems like you're going to be adding more incremental oil, overall. So should we think your view of longer term being more balanced between as being gas leveraged?

John, this is Vince. If you look at the visible growth projects we have over in the next few years, they are oil related. Of course we have growth in North American natural gas that will keep that balanced to some extent. I think our current production mixes roughly 60% natural gas. We might move a little towards oil over the next few years but not a significant shift.

Okay. Thanks, Vince. Last one for me. What kind of escalation -- have you guys done your PB 10 calculation yet, and if so, what kind of escalation did you have for estimated production and development costs?

I don't think we've completed our PB 10 calculation yet, John. In fact, I'm certain we haven't. Steve could address the assumptions in our 2006 capital budget and operating budget as far as escalation costs, but beyond that I don't know that we've got a disclosure ready.

Okay. That's it for me. Thanks, Vince.

Our next question comes from Van Levy of Dahlman Rose & Co.

Morning gentlemen, how are you? Larry, I was hoping you could run through the same exercise you did with the Barnett Shale reserves that you started with, and then added production et cetera, and the related costs and do the same thing for the Gulf of Mexico?

The -- I'm not sure I -- we've given the numbers we had on the Gulf.

Can you repeat the question, Van?

In Larry's prepared comments he went through the analysis of the Barnett Shale talking about the reserves that were acquired, the net add, offset by production, et cetera, and then what kind of reserves were left over, and kind of give us a sense of how powerful that asset was. I want to give the same sense of the Gulf of Mexico the program. How we how analyze the program in the Gulf of Mexico would probably be a better question for me.

I mean if you look at the -- I'm not sure this is exactly what you're asking, but, where we see the Gulf, is it has not been an engine of growth short term, and we recognize that and accepted that because we have been focused on our longer-term projects that we see coming to fruition. As Steve said, we plan a production test that's going to begin in just a few weeks from now on Jack, which will give us a tremendous amount of information on that project. We expect those results to be sometime late summer. When we announce those that will give us and we in turn, the investors, more guidance on exactly how we see that unfolding.

Our North American onshore has been carrying the Gulf and international as those projects, those longer projects come to fruition. They just don't have -- it's easier to do that in the Barnett because it's so near term that you can give that with some specificity. Going forward, we do see upside there as we bring on Redhawk, as we bring back on stream, as we bring Merganser on stream, but the real growth is going to come from these projects that we're drilling that we're just not ready to do.

Okay in the Barnett Shale, obviously the Chief oil and gas properties are for --

I might add that the that oil and gas companies see big bullion value out there that we're sitting on. You look at what Canada bought or sold to the Norwegians. You look at Spinnaker. You look at some of those other transactions that have come out there, there is clearly big significant value that other knowledgeable oil and gas companies are putting on those assets. So we wouldn't be pursuing that and keep pursuing that unless we saw the potential for meaningful shareholder value.

Right. Then in terms of the Barnett Shale, the Chief oil and gas transaction, looks like it's coming up soon. You guys have talked about bidding on this. And I guess -- you know, over the last, seems like over the last several quarters you've are talking a lot more about the Barnett Shale versus maybe Enron, OEG, who was a lot more aggressive about it earlier. Are you more confident in this area now? If so, why, given given your acreage position would it even make sense to bid on that asset? Seems like you have quite a lot of growth there already.

Well, we never said we were interested in bidding on it. Ordinarily, we said we were going to the data room. You can safely assume that we go to every data room that is open in the Barnett Shale, or we go to every data room that is open in any area in which we have an interest. If we open a data room on property that we sold in the past, companies come and go to those data rooms. Once you go to the data room, you make -- you decide whether or not you want to make an offer or not.

I'm not going to talk specifically about Chief or anyone else specifically except to go back to the overall comment that I made. We look at prices that people have paid for the -- to buy into parties that have bought properties in the Barnett Shale over the last several years and are, quite frankly, blown away and surprised by the very aggressive prices that people pay. In we could sneak up on someone and buy them on the cheap, we would. Is that likely? No, it's not. I don't know what else I can say on that.

All right, we've got time for one more question. Operator, do we have another question in the queue?

Ross Payne of Wachovia Securities, you may ask your question.

How you doing, guys? Thank you. With the leverage moving down here pretty notably, do you have any specific targets for debt going forward, or are we just going to kind of hang around the same level in terms of debt with free cash flow going to share repurchases?

If we, with the debt that we retired in 2005, and this is Brian Jennings speaking, we brought our net debt to cap down to around 19%. We are obviously sensitive and recognize the role that that debt plays in a company and the -- obviously the ability to leverage equity returns to shareholders is paramount to us. We have 670 million in debt that will mature this year. And we've ear marked those issues for retirement. We still have a very robust capital budget to fund this year. And as we have evidenced in the performance of last year, we much rather be putting our capital into our business, because we think we can generate the greatest returns there. With that said, as Larry mentioned in his remarks, our stock looks, given what we know about the Company and what we feel about the growth, our stock looks attractive and continuing to execute the buyback that we outlined in August, is something we intend to do. That program, of course, was given the time frame through the end of '07. So, we've got plenty of time to do it, and we'll continue to maintain ample liquidity to fund the budget.

Very good. Thank you.

Are we out of time?

Yes. Larry, you got any closing remarks?

I would just close by saying that we had an outstanding year. We added 439 million with the drill bit, almost double production. We increased our total reserves to a record high even though we sold 183 million and produced 226 million Boe. We increased reserves per share 11%. We lengthened our reserve line to ten years almost. And we did all this at a very attractive find and development cost. Most importantly, we continued to lay the foundation for robust growth in future years at very competitive costs. In 2006, we expect to deliver reserve additions at 410 to 440 with related capital of 4.6 billion to 4.8 billion . And when you're growing reserves, production follows. We're forecasting an 8% increase in production in '07over '06 and we expect that to continue because if you look at the projects that we are bringing on stream, a lot of those will not be fully on stream in '07. They will be fully on stream in '08. So that visibility for both '07 and '08 is getting to be very clear. In summary, we think we're well positioned to increase value per share with a sustainable reserve growth and production growth and to do it at attractive prices. Thank you very much for your attention in our Company.

That ends today's call.