德文能源 (DVN) 2007 Q4 法說會逐字稿

Welcome to Devon Energy's fourth quarter and year end 2007 earnings 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. This call is being recorded.

A this time I would like to turn the conference over to Mr. Vince White, President of Communications and Investor Relations. Sir, you may begin

Good morning everyone and thank you operator for that promotion. Welcome to the Devon's year end 2007 conference and webcast. I am going to start the call with a few preliminary items and the our Chairman and CEO, Larry Nichols will give a high level overview of 2007 as well as updates on a couple of strategic initiatives. Following Larry's remarks our Senior Vice President of Exploration and Production, Steve Hadden will cover our operating highlights and then, finally, our President, John Richels will finish up with a review of the years financial results as well as outlook for 2008. We will conclude the call in about an hour so if you don't get your question answered please feel free to contact us after the call for follow up. A replay of this call will be available later today through a link on our home page and will also be distributing a new issue of Devon Direct as well as posting it to the Devon Web site. Also today we will file a Form 8-K as we do each time this year which will provide the forecast for the year ahead. This 8-K includes forecast for 2008 production by product and geographic region, expense estimates and our expected differentials to benchmark oil and gas prices for the year.

The forecast in today's 8-K treat our remaining operations in Africa as discontinued operations. However, in addition to the forecast for our continuing operations we are providing summary forecast applicable to the divestiture properties. This will enable those of you that maintain models on Devon to include or exclude West Africa as you choose. As you may remember our decision to sell last year our African operations triggered the accounting rules for discontinued operations. Under those rules the revenues and expenses for the discontinued operations are collapsed into a single line item near the bottom of our statement of operations. However we are providing an additional table in today's news release that includes a detailed statement of operations for the discontinued ops. As indicated on this table net earnings from discontinued operations were 212 million in the fourth quarter and 460 million for the full year 2007. However, I'll remind you that that does not mean that the discontinued operations would have contributed that level of earnings if we were not selling them. That's because the accounting rules for discontinued operations requires us to stop recording depletion expense on the properties that we are selling once they are declared discontinued operation. Had we continued to depreciate our African properties we would have had net income associated with the divestiture properties of 196 million for the fourth quarter and 368 million for the full year 2007, and both the quarterly and the full year figures include the $90 million gain we recognized in the fourth quarter on the sale of Egypt.

Accounting for discontinued operations also complicates the comparability of our earnings estimates. Most of the analyst that report to First Call excluded the impact of discontinued operations for the fourth quarter. The Mean estimate of earning per share from the analysts that excluded discontinued operations was $1.91 for the fourth quarter. That compares to our non-GAAP earnings from continuing operations of $1.93.

For those analysts that included discontinued operations in their estimates, the Mean was $1.94 a share, and that compares to our non-GAAP diluted earnings including discontinued operation of $2.16 per share for the fourth quarter so in any case we beat the Street expectations. Before I turn the call over to Larry we are obligated to remind you that discussions of our expectations, plans, forecasts and estimates are considered forward-looking statements under U.S. Securities law. And while we always make every effort 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, for a discussion of the risk factors that could influence our actual results you could refer to our Form 8-K that we will be filing today.

One final compliance item. We'll make reference today in the call to various non-GAAP performance measures. When we provide these measures we are also required to provide certain related disclosures and those disclosures have been posted on the Devon Web site. That concludes my remarks and I'll now turn the call over to Larry Nichols.

Thanks, Vince, and good morning everyone. Now for the fun. The earnings release that we released this morning really shows that Devon had its best year ever in our twenty-year history as a public company, 2007 was a great year. We grew oil and gas production 12% over 2006 up to 224 million Boe. We reported record net earnings of 3.6 billion. We reported record earnings per share of $8 per share. Cash flow before balance sheet changes climbed 21% to also reach an all time high, 7.3 billion. With cash flow from operations we funded 5.4 billion in exploration and development capital. In addition we repurchased 326 million of common stock and we repaid 567 million of maturing debt during the year. In laying the foundation for the future we drilled over 2,400 wells with a 98% success rate, growing proved reserves to a record 2.5 billion equivalent barrels. Our fine and development costs came in lower than our forecast and did not include any reserves from our deepwater gulf projects. We began operations on three of our significant projects that that we talk about in 2006 and seven, the deepwater Merganser field in the Gulf of Mexico, the Polvo Offshore field in Brazil and the Jackfish Oilsands project in Canada. In the Barnett Shale we achieved a 33% production growth and drill bit reserve additions of more than three time the years production, very good performance in the Barnett Shale.

In Canada, we increased annual oil production from Lloydminster by 40% to 33,500 barrels per day and added 22 million barrels with a drill bit. Not to be out done our marketing and midstream operations also delivered record results contributing more than $0.5 billion in operating profit for the year. And we finished the year in a very strong financial position with 1.7 billion of cash and short term investments on hand and net debt to adjusted cap ratio of just 18%, very strong balance sheet.

In this today's release we did provide summary reserve report data and I have a couple of observations about those results. The drill bit reserve additions, and by drill bit, I of course mean discoveries, extensions and performance revisions, came in at 390 million Boe. This exceeded by 30 million barrels the upper end of the estimated range that we provided in December. These drill bit additions are nearly 1.75 times our 2007 production from continuing operations. With a total drill bit capital of 5.8 billion which includes capitalized interest and G&A and drill bit revision reserve additions of 390 million Boe, clearly our organic F&D costs should be among the most competitive among our entire peer group. Price revisions gave us a net positive boost in 2007, adding another 44 million barrels. Takes these into account and looking at all sources including price revisions we added 437 million Boe at a cast of 6.1 billion. As with our drill bit only F&D our all sources F&D should be very, very competitive within the industry. And these results were achieved in spite of our investments during 2007 of roughly $600 million in high impact future growth prospects which did not add and were not planned to add any reserves during the year. Foremost to come among this type of expenditures is of course, our deepwater Gulf of Mexico expiration and development projects and particularly the lower tertiary. We are actively pursuing these long-term projects in offshore China as well as Brazil, our second thermal project in Canada, the Jackfish 2 projects and a variety of other North America onshore play projects that are included in that 600 million.

Looking to 2008, we are forecasting another year of strong production reserve growth with an even largest component focused on long-term growth. We are forecasting 2008 production of 240 to 247 million Boe with drill bit reserve additions of 390 to 410 million Boe. With drill bit capital expected to be somewhere in the 6.1 to 6.4 billion in 2008 we should again achieve very respectable, very competitive finding and development costs while devoting even more capital to our longer term growth projects. In 2008 we expect to spend about $1 billion on these longer term growth projects. The investments we are making in those projects today will help ensure that we have a very robust development, a pipeline of development projects not just into the next decade but throughout the next decade.

We also recently announced that we have hedged a meaningful part of our expected 2008 production mostly on the natural gas side. Our decision to hedge was based on several factors as most of you know the nature of our capital budget has shifted over the last few years toward longer cycle time projects with long-term associated capital commitments. Examples include the Jackfish Sag-D projects, our oil tertiary exploration and development projects. These were projects that required continued investment independent of short-term commodity price fluctuations. When we initiated this hedging activity gas storage, in early January, gas storage was at near record levels. Over the past few weeks natural gas storage levels have moved closer to five-year averages of being led by the record withdrawals that we had last week.

While this has somewhat lessened our concern regarding gas storage, we still believe the potential for gas price volatility remains. The extent of that volatility will be driven both buy weather conditions during the remainder of the winter and by economic conditions and the persistent concerns about a recession affecting the U.S. The hedges we entered into were very attractively priced and reduced the potential impact of gas price volatility. In fact both the swap price of $8.24 and the floor price of $7.50 on the natural gas collars that we were able to execute for 2008 are higher than the average natural gas price for any year in history except for one year 2005 when we had the hurricanes. Weighing these factors we believed it was prudent to enter into these hedges for 2008. To give you a quick update on West Africa. We closed the sale of Egypt last year and are soliciting the final governmental approvals to close the 205 million sale on our Gabon operations.

We received a variety of attractive bids for the other West African properties and are working through the negotiations with the various purchasers and governments on those properties. Although this is proven to be very time consumer we are optimistic we will complete these buy mid year. With the anticipation of the completion of our African divestitures the board has recently reauthorized the 50 million share repurchase program that we suspended in 2006. We could have considerable free cash flow in 2008 especially following the closing of the remaining divestitures. We believe that Devon stocks looks very attractive versus alternate investments and expect to opportunistically repurchase shares with our excess cash.

Before I turn the call over to Steve I want to take a few moments of pride and I hope you'll indulge me. In January Devon was named one of the Fortune Magazines 100 Best Companies to work for. At number 48 on the list, Devon has the distinction of being the highest ranked oil and gas producer to ever appear on that list. In addition of all those companies, we had the fourth lowest in employee turnover rate. That is really a rather commendable rate with competition for employees in our industry at very fierce levels being selected one of the best places to work gives us a distinct advantage in a very competitive market. Selection for this type of an award is mainly based on feedback, independent feedback that is done by the outside agency in talking to our own employees and we want to thank all those employees for their support and for the culture that we've created here.

With that I'll turn it over to John. John?

(inaudible) Steve Hadden. Thanks, Larry and good morning to everyone. As Larry mention from an operations perspective, 2007 was an outstanding year. We delivered 12% production growth and pushed proved reserves to a record 2.5 billion barrels of oil equivalent. This was a result of a highly-successful capital program including the drilling of 2,440 wells, with a 98% overall success rate, nearly 94% of those wells were in low risk development projects which continued to provide a solid reliable platform from which to grow. At the end of December we had 122 rigs running company-wide with 87 rigs drilling Devon operated wells. We were are drilling at a similar pace today, 2007 capital expenditures for exploration and development projects came in at $5.4 billion, including 1.6 billion in the fourth quarter. To reach the 5.8 billion of drill bit capital that Larry referred to, you would add roughly $400 million of capitalized G&A and interest to the E&P total.

Moving now to our fourth quarter operating highlights starting with the Barnett Shale field in north Texas we are currently drilling 32 Devon operated rigs including 14 in the core and 18 outside the core, 20 of these operated rigs are the newer high efficiency models. Production growth for the field continued to exceed our expectations in the fourth quarter. You may recall that last August we increased our 2007 exit rate targets for the Barnett to 875 million cubic feet per day about 10% above the 800 million cubic feet per day target we set at the beginning of the year. During the fourth quarter we blew through that target as well and we are producing around 950 million cubic feet per day on December 31. In fact our net Barnett production averaged over 930 million cubic feet of gas equivalent per day for the fourth quarter up 9% from the third quarter average and up 35% year-over-year. We'll remind you that these production numbers are net to the Devon's interest not gross operated volumes by Devon.

Reasons for the rate acceleration include improvements in drilling efficiency which resulted in more wells drilled during the year, and we realized better average well results. We began 2007 expecting to drill about 400 wells but increased activity during the year to include more in fill wells and more wells outside the core area ultimately drilling 582 wells in the year. Our average well results also continue to improve. We bought 116 wells on line during the fourth quarter at an average rate of 2.1 million cubic feet of gas per day compared to average rates of 1.9 million cubic feet per day in the fourth quarter of 2006. About a year and a half ago a Devon stretch goal for the Barnett Shale product was one BCF per day net to the Devon's interest by the end of 2009. It now looks as though we will reach that target sometime during the second quarter of 2008, about 18 months ahead of the original schedule.

Looking into 2008 with planned level of activity in the Barnet Shale that's similar to what we experienced in 2007. We will also continue execution of our 80 surface acre infill drilling program as well as drilling a few trial horizontal infill wells on 40 surface acres and on 20 surface acre locations. We expect our Barnett Shale program to deliver another year of strong production growth in 2008. From a reserve performance perspective the Barnett Shale was the leading growth area for the company again in 2007. Extensions, discoveries and performance revisions in the Barnett accounted for 158 million barrels of oil equivalent of additions. This was well over three times our production of 50 million Boe for the year. Associated capital was $1.6 billion.

At year end we had 724 million Boe booked in the Barnett and 87% of those reserves are developed compared with 78% developed at year end 2006. So pud bookings in the Barnett are only 13% of year end proved reserves.

In the Woodford Shale in eastern Oklahoma we current very well five operated rigs running. We brought a total of 12 new operated wells on line during the fourth quarter and now operate about 60 wells in the play with gross operated production running about 47 million cubic feet per day. Until now our Woodford activity was focused on drilling to hold acreage principally but in 2008 we will shift to developing that acreage. We plan to invest about $160 million of capital in the Woodford and double our operated well count by drilling about 60 wells during the year.

Moving to the Rockies in the Washakie Basin in Wyoming we had four rigs running throughout the fourth quarter. During the quarter we drilled 16 wells in Washakie bringing the full year total to 49 wells on Devon operated acreage. We also participated in 112 outside operated wells during 2007. Devon's net production at Washakie averaged about 103 million cubic feet per day in the fourth quarter up 4% from the third quarter average and up 14% year-over-year. In 2008 we planned to invest about $125 million of capital in the Washakie, drilling approximately 130 wells. Two high efficiency rigs are expected to be delivered later this year to increase our drilling time per well. With over 300 undrilled locations we have plenty of running room at Washakie.

Shifting to East Texas at Carthage we wrapped our 2007, 93 well vertical Cotton Valley drilling program during the fourth quarter. We had six rigs running throughout the quarter and drilled 32 vertical wells. In 2008 we expect to spend about $200 million on this low risk repeatable vertical program drilling 100 wells. Also at Carthage our horizontal drilling program continues to deliver solid results. During the fourth quarter we drilled and completed three new Cotton Valley horizontal wells including 100% working interest Langford 6-H well that IPed for 4.6 million cubic feet a day. In 2008 we plan to spend $160 million as we step up our Carthage horizontal program. We expect to run four rigs and drill 23 horizontal wells for the year today. Today we have about 100 horizontal locations identified at Carthage.

In total our Carthage net production averaged a record 277 million cubic feet of gas equivalent per day for the fourth quarter, up 7% from the third quarter average and up 19% from a year ago. From reserves perspective Carthage delivered impressive growth again in 2007. We added 46 million barrels of oil equivalent of reserves, three, three times our 2007 production with drill bit capital of $426 million delivering strong reserve growth at low F&D. With the combination our horizontal and vertical drilling programs we believe we can continue to grow Carthage production and reserves well into the future.

Southwest of Carthage at Groesbeck we are still in the early phases of evaluating our acreage position and optimizing our site selection, drilling and completion techniques. We've made good strides in improving our consistency and reservoir performance from the wells we have drilled in some areas is very good. We bought on line two strong horizontal wells at Groesbeck in the fourth quarter.

In the Nan-Su-Gail field the Nail- B 12 H IPed at 24 million cubic feet per day and in the Oaks field the Thompson 12H IPed at 12 million a day.

As we did in the noncore Barnett we will move very deliberately until we mature our understanding and are prepared to maximize the return from our position. While we still have more to learn we believe we have an attractive horizontal play in the Groesbeck area with a sizeable number of potential horizontal drilling locations.

Now moving to Canada, at the Devon operated Jackfish thermal heavy oil project in eastern Alberta we began injecting steam last year and are now selling oil. We are seeing some minor start up issues as we monitor and adjust the systems but early reservoir response is good and we have not detected any design problems with the above-ground facilities. Production will ramp up gradually headed toward an expected sustainable production rate of 35,000 barrels of oil per day.

At Jackfish 2 we awarded primary engineering contracts in the fourth quarter of 2007 and in mid 2008 we hope to receive regulatory approval and formally sanction the project. If all goes well we could begin sight work in the fall. Jackfish 2 is planned to have the same design as Jackfish with production capacity of 35,000 barrels a day and 300 million barrels of recoverable resources.

At our Lloydminster oil plant in Alberta this exceptional assets is demonstrating the breadth of our Canadian portfolio. We are increasing production dramatically at Lloyd with low F&D costs at very high rates of return. We ran a four rig program in the fourth quarter and drilled 145 new wells. This brought the full year total to 429 wells. Lloydminster production averaged 38,000 barrels per day in the fourth quarter, up 9% from the third quarter and up 46% year-over-year, 2007 drill bit reserve additions at Lloydminster totalled 22 million barrels of oil equivalent just about double the years production. Drill bit capital was $241 million. In 2008 we plan to spend $280 million and drill another 475 wells in the Lloydminster area.

Now shipping to the Gulf of Mexico, in our lower tertiary exploration program we are preparing to drill the objective section on the Chuck prospect located in Walker Ridge 278. The objective is a large sub salt structure but we won't have any results to report until the well has been logged and evaluated. Devon is the operator if Chuck with a 39.5% working interest. Also drilling is there lower tertiary Green Bay prospect. Green bay is in Walker Ridge 372 and approximately 6300 feet of water. The prospects was spud in the fourth quarter and is currently drilling below 20,000 feet. Green Bay is about between 20-miles north of the St. Malo discovery and about 18 miles east of our Chuck prospect. Devon has a 23.4% interest in Green Bay.

We are conducting a appraisal and development activities on each of the four lower tertiary prospects where we've made discoveries. At St. Malo also located in the Walker Ridge area we reached a planned depth with our second delineation well the St. Malo #3 and have completed coring in the Wilcox. We will now plan to drill another 2 to 300 feet when we finished here the rig will mobilize and move on to the St. Malo #4 appraisal well.

At Jack also in Walker Ridge we plan to drill the Jack 3 appraisal well with the Ocean Endeavor rig after it completes its work on the Chuck exploratory well. The results of these appraisal wells at Jack and St. Malo will help the partners determine the optimum development approach for these projects. Devon has a 25% working interest in Jack an 22.5% working interest in St. Malo. The partners in the Cascade discovery are planning the next round of appraisal operations to be performed in the second quarter of 2008. Devon has a 20% working interest in Cascade which is in the deepwater Keathley Canyon lease area west of Walker Ridge.

At Cascade, the first of the Devon's lower tertiary discoveries slated for development we awarded the remaining contracts for facilities supply, construction and installation in the fourth quarter. Later this year we plan to drill the first of two initial Cascade producing wells. We anticipate first production at Cascade in the first half of 2010. Devon and Petrobras have equal 50% working interest in Cascade.

In our deepwater myozene exploration program we expect to begin drilling on the Sturgis north prospect located on Atwater Valley block 138 in the next new days. On previous discovery at Sturgis encountered 100 feet of net oil pay. The Sturgis north prospects is adjacent to the original discovery but we'll test a separate structure. Devon has 25% working interest in the Chevron operated prospects.

Now moving to Brazil we continue development drilling on the Devon operated Polvo oil project on block BMC-8 during the fourth quarter. Due to some mechanical issues production at Polvo has not ramped up as quickly as expected however we are pleased by what we learned about the reservoir from the drilling the first few wells. We believe our resource estimates at Polvo are solid but it's going to take little bit longer to reach peak production than we initially planned. We continue to move forward with our exploration program in Brazil where we are building an inventory of high potential prospects. We current very well ownership in nine blocks in Brazil comprising 1.3 million gross acres and 700,000 net acres in three offshore basins. We have 17 prospects identified to date with gross unrisk potential ranging from 100 to 460 million barrels per prospect. Seven of the blocks are located in the [Polvolific] Campos space and where hydrocarbon discoveries and production have been established in plays from the [curtascious] pre salt to the myozene . We are partnered with Petrobras in four of these blocks in the Campos Basin. In addition to the presence in the Campos we have acquired two Frontier deepwater blocks one in the [Bar] Basin and one in the [Canamo] Basin.

In 2008 we will drill our first presalt exploratory well on block BMC 30 in the Campos Basin. Then in January 2009 the Devon operated deepwater discovery drill ship is expected to arrive in Brazil to commence drilling seven planned wells over a two year period. That concludes the operations update. Now I will turn it over to John Richels to review our financial results and the 2008 outlook.

Thank you, Steve, and good morning everyone. This morning I will take you through a brief review of the key events and drivers that shaped our 2007 financial results and our outlook for 2008. As Vince mentioned, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. So I will focus my comments only on our continuing operations which exclude the results attributable to West Africa.

Let's begin with our production. For 2007 our full year production was 224 million barrels of oil equivalent or approximately 614,000 Boes per day. Compared to last year, you'll find that company-wide production increased by 65,000 Boe per day or nearly 12%. Our U.S. onshore and international operating segments drove this year-over-year growth. We grew production from U.S. onshore by nearly 40,000 barrels per day or 13%. Increased drilling activity in the Barnett Shale coupled with overall reservoir out performance in the Barnett were the biggest drivers of our U.S. onshore growth. We also nearly doubled production in the international sector to 54,000 barrels per day in 2007 driven by the performance of the ACG field in Azerbaijan and initial production from our Polvo field in Brazil.

For the fourth quarter of 2007 production came in at 58.1 million equivalent barrels or 632,000 barrels per day. This represented a 10% increase in fourth quarter production over last year and marks the seventh consecutive quarter of production growth. In addition we exceeded the fourth quarter guidance provided in our third quarter conference call by just over 1 million barrels. This was driven by several of our core properties in North America delivering better than expected results and the lack of any significant hurricane downtime in the Gulf of Mexico.

Looking ahead to 2008, we anticipate continued strong production growth. The midpoint of our 2008 forecast range implies a 9% increase over 2007 driven by growth from our established onshore properties in both the U.S. and Canada, the ramp up of production from our Jackfish steam assisted gravity drainage project in Alberta, a full year of production from Merganser in the Gulf of Mexico and the continued ramp up of production from our Polvo project in Brazil. We expect production for the first quarter of 2008 to be up slightly at about 640,000 Boes per day with growth expected each quarter for the remainder of the year.

Moving to price realization starting with oil, the WTI benchmark roses steadily throughout 2007 and ended the year with a fourth quarter average of $90.92 per barrel. Ultimately the full year WTI index averaged $72.39, a 9% gain over 2006. In addition to the strength in benchmark oil prices most regional differentials narrowed when compared to last year. The most important to Devon was the robust international oil market reflected in premium pricing for our light sweet oil in Azerbaijan. Overall company-wide price realization rose to 88% of WTI or $63.98 per barrel for 2007. As a result of the improvement in differentials 2007 realization actually outpaced the rise in WTI by a couple of percentage points. On the natural gas side the benchmark Henry Hub index averaged $6.86 per Mcf for the year, a 5% drop off from 2006; however, in the fourth quarter the Henry Hub index rebounded by 13% from third quarter lows to $6.97 per Mcf. For the year Devon's gas price realization came in at the top end of our guidance range at approximately 87% of Henry Hub, a 3% improvement over 2006. Price realization were especially strong in Canada and in the Gulf of Mexico; however, this regional strength was partially offset by widening price differentials in the Rockies prior to start up of the Rockies Express pipeline. In today's 8-K we provide detailed guidance for expected oil and natural gas price differentials for the upcoming year as well as details of the hedges that Larry mentioned. The hedge volumes in the 8-K include another 25,000 MM BTU of gas hedges entered into after we issued Monday's press release.

In addition to strong upstream performance, Devon's marketing and midstream operations also produced outstanding results. Driven by strong gas processing margins fourth quarter operating profit totaled $148 million in and brought full year marketing and midstream profit to $509 million. This is the highest level in company history and $73 million more than the 2006 total. Looking forward to 2008 we expect marketing and midstream operating profit to increase once again to somewhere in the 510 to $550 million range.

Moving to expenses, as we indicated in our third quarter conference call our reported 2007 lease operating expenses came in at the high-end of our guidance range. Full year LOE was $1.8 billion or $8.16 per barrel produced. The increase in the 2007 LOE rate reflects higher oil transportation costs largely related to production growth in Azerbaijan, increased work over activity in Gulf of Mexico and upward pressure related to the strengthening of the Canadian dollar. In 2007 the average Canadian exchange rate increased about 6% over the 2006 average. Unit LOE for our U.S. onshore segment grew at a much more moderate pace of 5%. For 2008, we anticipate continued but more moderate pressure on cost. Our forecast incase 2008 lease operating and transportation expenses to range somewhere between $8.90 and $9.25 per equivalent barrel. For 2007 Devon's full year DD&A expense for oil and natural gas properties came in at $11.85 per barrel, about a $0.05 above the high-end of our full year guidance range. Over time of course you would expect a unit DD&A rates to gravitate towards the average unit finding and development costs. As a result we expect our DD&A rate to come in between $12.75 and $13.25 per Boe in 2008.

Moving on to G&A expense, full year G&A expense for 2007 was $513 million, higher employee related costs drove G&A just above the high-end of our guidance range. Looking to 2008 we anticipate a continuation of the current tight employment market resulting in additional upward pressure on personal expenses. Consequently we are forecasting our 2008 G&A cost to be in the range of 590 to $610 million including approximately $90 million of non-cash equity based compensation expense.

Turning to interest expense, interest expense for 2007 was $430 million at the low end of our guidance range. Commercial paper and credit facility balances accounted for just over 20% of total interest expense for the year. Looking to 2008, we expect our interest obligations to decline as we continue to pay down commercial paper and credit facility borrowings. Our forecast assumes a midyear close on the remaining West African asset divestitures and a simultaneous pay off of our commercial paper balances. Based on these assumptions and our expectation for lower interest rates in 2008 we expect 2008 interest expense to decrease by about 20% to a range of 340 to $350 million.

The final expense item I would like to touch on is income taxes. Devon's reported income tax expense for 2007 came in at 26% of pretax income. When you back out the impact of items that are generally excluded from analyst estimates you get an adjusted current tax rate of 12% and a deferred tax rate of 20% for a total income tax rate of 32%. The main contributor to the lower than expected current tax rate was increased intangible drilling cost deductions due to higher E&P activity levels. Looking to 2008 we expect a similar combined tax rate with about one-third being current and two-thirds deferred. In today's earnings release we provided a table that reconciles the income tax effects of items that are usually excluded from analyst estimates.

So moving to the bottom line, fourth quarter reported earnings from continued operations were an impressive $1.1 billion or $2.45 per diluted share. That's a 120% increase in earnings from continued operations over the same period a year ago. After backing out the impact of items that are generally excluded from analyst estimates we had net earnings from continuing operations of $868 million or $1.93 per diluted share. For the full year our adjusted net earnings from continued operations increased by 13% to $2.9 billion or $6.38 per diluted share, an all time record. To some it up from almost every perspective 2007 was a great year for Devon. With that I'll turn the call back over to Vince to open it up for Q&A.

Thank you, John. Operator, we are ready to take the first the first question.

(OPERATOR INSTRUCTIONS) . Dave Kessler, Simon's and company. Good

With respect to the Barnett, both yourself and the industry are having very prolific production growth there. It seems like kind of across the board people have a very deep inventory there. Obviously you guys have one of the deepest. Do you foresee any potential infrastructure constraints in the near future whether it be transportation, gathering, processing? And if so can we talk a little bit about your development plans for handling that?

Yes this is Darryl Smette. Obviously you are correct that Devon and a number of other participants in the Barnett Shale has great success and that has put a strain on infrastructure not only gathering systems but export systems and processing plants. Devon has in place firm transportation, enough processing capacity at existing plants and our own gathering system where we can handle all of the production Devon four seize being produced into the future. So while we do see some constraints in the area, we think that we have positioned ourselves not only to produce the volumes but be able to to have it gathered, processed and transport to do a variety of markets throughout the United States.

Great. Building off that a little bit, kind of locking in all those plans, you guys or have you projected what you estimate to be kind of a peak Barnett production for you guys or goal for a peak production?

Yes, this is Steve Hadden, Dave. You saw that we talked earlier that we set a target or a stopping off point of a BCF per day by the ends of 2009 not too long ago, maybe a year or so ago and we've blown through that pretty quickly. Our goal is to continue to drive the efficiency with the drilling and completions that we are seeing across the business and continue to work to have those volumes grow. We are seeing better wells performance as I mentioned in the earlier comments, better well performance year over year as we've been progressing. We've also had success with our in fill drilling program that continues to add to our inventory. And this inventory of drilling is very, very deep for us and we will go on for a very long time. So as we look out for the foreseeable future for the Barnett Shale for Devon we expect growth that can continue to occur and these efficiencies to continue to deliver good growth. So our goal per se is not any one stopping off point because we will continue to grow well beyond the BCF a day of net once we hit that in the second quarter and that will continue for years.

Great. Thank you for that clarification. If I can just ask one more question, when you kind of look at the deepwater, what do you see as the chief technological challenges as you progress with getting those prospects and projects commercialized? And I guess as part of that discussion, if you could talk about where you are with respect to securing FPSO for Cascade and realizing you're not the operator, but would love to get the color on that?

Yes, we've, relative to cascade, we are continuing to move forward with that development and specifically to the FPSO for Cascade it's already been secured. The contract has been let. The vessel is actually in Singapore being retrofitted as we speak. So we are well on our way and right on our path for first production in 2010 and we'll drill the two wells, the two producing wells last half of this year and then into 2009, get the FPSO out there, have the subsea work done in 2009 and into early 2010 and be ready for first production there. As far as overall challenges to getting through a sanctioning decisions in commercialization obviously these things are technically challenging and relatively complex as you go through both the size and magnitude of what these things could be. And we are working through the those things with integrated project teams with our partners. The challenges include everything from working through all the options for drilling and completing the wells most efficiently and effectively for the reservoir to working on the configuration for the producing facilities that would deliver the best economics and long-term performance for that reservoir as we continue to characterize it with the appraisal drilling that we are doing. So we are right in the midst of working through those things with the integrated project teams and with Jack and St. Malo probably looking at some sanctioning decision in 2009.

Great. Thanks so much for those clarifications.

Let me just add one think this is Larry, is and that goes back to the use of the word peak on the Barnett Shale production. And that sort of implies it's going to ramp up quickly and ram down equally quickly. The model that we really see for Devon's portfolio and we do have by far the largest and most in depth portfolio with it concentrated in the core and the near core where the best rock is and always will be. But what we see is that after many years of growth, the rate of growth will gradually flatten out and there will be a flat plateau for an extended period of time and then a fairly gradual decline. So it is not like the word peak sort of implies it's going to shall up and chute down and chute up and chute down and that is not at all what we see with the portfolio that we have there.

Thank you for that clarification.

Our next question will come from the line of Joe Allman with JP Morgan.

Good morning, everything. Joe Allman. Can you tell us where the price reserve revisions were and just confirm, it sounds like most of the performance related revisions were in the Barnett Shale?

Yes, I will tell you that, Joe, the majority of the performance revisions were in the Barnett Shale. And Carthage we had good performance revisions in Carthage as I mentioned in the call. When you look at the price effects, I think the pricing revisions we saw were principally positive revisions in the thermal projects in Canada based on the year end pricing. And then there was some impact in the Barnett Shale and then a few other things cross really smaller things just across the portfolio as we look at that. From an international standpoint there was a negative price revision that was a result of simply higher prices and the impact on the production (inaudible) contract at Azerbaijan. If you look at the performance revisions the performance revisions came principally again from the Barnett Shale and Carthage and the reason that's occurring is the fact that we are drilling horizontal wells in those areas and, for instance, one of the largest contributions to the performance revisions that came from the Barnett Shale came from wells that were a vintage of about 2003. So what we are doing is going in, we are drilling these horizontal wells. We are booking them very judiciously initially and then we are looking for performance. And as we get more and more well performance and see those curves flatten out then we are having additional performance revisions. In addition to that, we work very closely together on our, both our midstream and marketing facilities along with the producer producing facilities to do things like lower line pressures, optimize flow rates, add additional compression, those type of things and those are continuing to have an effect on the performance especially in the Barnett Shale. But these horizontal wells for instance we are drilling them in Carthage as well. We book them. We want to see how they go hyperbolic and once we get confidence on a performance basis then you see these positive revisions come in.

That is helpful. And then where the reserve additions aside from the revisions were the reserve additions as much you expected in early 2007 and just add on there the finding costs in '07 were higher than the finding costs in '06? What was the big driver there and what would you be expecting in at a terms of 2008 not necessarily a specific number but kind of a similar finding cost in '08 versus '07?

Relative to the additions and extensions that we saw they were basically on target to where we would have expected to be. When you look at the, some of the issues about the finding and development costs that may appear to be a bit higher in some areas that's principally driven by what Larry talked about early in the call. We spent $600 million on projects that we think are going to deliver great value and long-term growth for the company. But they are not delivering any reserve in the given budget years. So I think that's going to be the principal reason of that variation that you saw there.

How about in 2008, are there similar large expenditures that aren't necessarily going to result in reserves such that the finding cost is going to be about roughly the same?

Yes, I think we are going to see similar numbers in 2008.

And then really quickly, cost, I mean overall are you seeing cost, drilling and complete costs coming down here still plateauing? Could you just give comments on that?

Yes, from a cost standpoint overall we certainly see the rate of increase coming down on average across the, across the business when you look at it on average. I think you could roughly say that as a company the drilling and completion costs that we see are probably escalation might average around in a 5% range or something like that. But when you look across the portfolio, for instance, in Canada we've seen significant reductions in drilling and completion costs in that market which we had anticipated and would continue to anticipate because that market was pretty much over heated. On the other extreme when you see the deepwater side of our business, those costs still remain relatively high because demand for rigs, et cetera, is still pretty tight.

Okay. Very helpful. Thank you.

Joe, this is Vince. I might add to what Steve said that our drill bit reserve additions for the year and the resulting finding and development costs were really right in the sweet spot what have we had forecasted at the beginning of the year. So very much came in in line with our expectations and those did not change throughout the year.

Thanks, Vince.

Our next question will come from the line of Brian Singer with Goldman Sachs. Please proceed.

Thank you. Good morning.

Good morning, Brian.

On Jackfish, what should we expect in terms of quarterly progression, sales and do you have any initial thoughts on what you have seen so far in terms of steam ratios?

I think what we will see is a pretty steady rise over the next year and a little bit to the peak of 35,000 barrels per day. We've always estimated that on average once we started steam injection and got up and running that ramp up could take as long as about 18 months. And we are very pleased with the reservoir performance so far as I think we mentioned before in some of our calls, we think the Jack fish reservoir is in the top quartile of the oilsands reservoirs. And the results that we've seen so far from the reservoir indicate that that's true. From a facility standpoint the design looks very good. As you probably know when we begin to produce the oil and the water together hear, the specific gravities of the two are very close and we have to work through some issues on both chemicals and operations of the plant to simply line it out and that's something that we had expected. We are working through those thing right now. So we think over the year will you see a steady ramp up in the volumes as we go forward.

We should not expect full production first, second quarter of 2009?

We will probably get the full production year end thisn year sometime in that time frame.

Okay.

Brian, it's John, I think what's important is the point Steve was making here as you bring these facilities on, there are stops and starts and things that we anticipated. What we are really pleased about is the reservoir performance and we haven't seen any of the very significant facilities related issues that you have in some other projects in the industry over time. So all of those things are positive.

Sound like you are well on your way to Jackfish 2? Are those some of the data points that you have seen that give you confidence to proceed? Sounds like thing are well on your way there.

I think we are very, very eagerly awaiting get to go a sanctioning decision and the regulatory approval. Obviously with Jackfish 1 under our belt what we were able to do there and construction both the plant and seeing the reservoir performance is at least early on is really consistent with our thinking. That certainly does continue to encourage us from a technical standpoint on Jackfish and we'll just, we'll look at the numbers once we have the early engineering and the economics together and make that sanctioning decision sometime this year.

Similar type of questions, on Polvo, I think you mentioned it's taking longer for you to head towards peak production, can you talk about when you think you will get to peak level now?

What actually happened Brian we had delays in hook-up and completion of the facilities initially and some of the construction issues around the drilling rig. That was one of the bigger things that slowed us down before we even got to drilling the wells. Then we drilled three wells, actually drilled a fourth but it was a long reach well it was probably 4,000-meters long trying to reach out to a, another part of a reservoir and we had a drilling problem there and flow shoot failed and essentially we had to redrill that well then slowed us down a little bit and we are in the process of redrilling that well in fact it's near its P.D. right now. We think we will continue to have the production growth from this point forward. Again we've drilled three of about 12 to 15 wells that we'll drill in the development phase of the program. That ramp up we thought we reached a peak of about 26,000 barrels per day net this year. That will probably happen, we'll probably get to some peak in early '09.

Great. Thank you.

(OPERATOR INSTRUCTIONS) . Gill Yang with

Could you comment, Steve, on what you think the reservoir quarter is for Jackfish 2 in comparison to Jackfish 1?

I think it's top quartile. We think it's the same. It's right in the same area and in and amongst same leasehold that we have up there. So it's going to be of similar quality.

Okay. Going to the Barnett you commented, it sounds like the wells or there is a leveling off earlier than you thought. And I guess that was the big effect was on the 2003 vintage of wells. Are you now booking all the new wells since, subsequent to 2003 with that assumption or do you potentially revise up all the bookings in between, for 2004 and 2005, six, seven, as they flatten out as well?

Yes, it's more the latter than the former, Gill. We are seeing, we book them with an initial factor, there's an end factor that they use to try to guess, estimate what that hyperbolic will be and where they flatten out. Once we have the performance obviously if they were 2003 wells we have a few years of performance under our belt, our confidence and certainty goes up in increasing those reserves on those wells then we try and factor in technically that understanding into future wells. But we'll rely-- We lean more heavily on performance in making these additions, these performance revisions and therefore we won't go back through and take all the once up to the 2003 performance level. We'll just want to see the performance of each subsequent year and make those bookings. Now, over time we may adjust our initial bookings a bit higher but we probably won't take the whole bite at one time.

Given that you are seeing the performance in 2003, you are saying in 2007 you didn't book, assuming that improved performance, you are still booking assuming the original performance?

That's kind of a, generalities are a little bit tough but when essentially we had enough performance on the '03 wells to make that adjustment, we didn't go back through to the '04 through '07 wells and make a similar, make the same adjustment. So as we get more performance in our and our confidence rises there you will see more of these performance revisions from this incredible reservoir.

Would the '08 wells be booked on the new knowledge of the '03 wells?

They will be booked based on our knowledge of the area many it's an accumulation of knowledge and understanding and just depends on where the wells were drilled and what our engineers think is reasonable certainty for those initial bookings.

Last question is could you, maybe either Steve or Larry, could you just comment on, you commented that there's long-term billing dollars spending on long-term projects. Can you just comment on rough what will the distribution of the different kinds of projects, Gulf versus Brazil versus onshore, resource plays, that kind of thing.

I don't have a percentage firmly but the bulk of it is in the deepwater followed by the Jackfish 2 project for this year depending on how much we get done. That's going to be the largest two components.

Is there much spending on new resource play exploration?

Oh, yes. There is a good deal of that in East Texas, a variety of areas some of which we talked about, some of which we haven't where we are looking to, out there into the future not just, I mean our goal for a long time has been not just to have the good solid short-term growth that you get out of resource place like the Barnett Shale, where we are, our U.S. onshore bread and butter growth grew 13% this year just from the blocking and tackling that we do on the U.S. onshore but to looking at longer-term plays that will allow to us achieve that kind of growth for a long time into the future.

Okay. Thank you very much.

Our next question will come from the line of Mark Gillman with Benchmark. Please proceed.

Guys, good morning. Just one, Steve, on the Barnett resource space. In light of the favorable performance could perhaps update us on where you might stand vis-a-vis the prior risk estimate of overall Barnett resources and whether you're inclined to adjust the recovery factor any higher?

Well, we are going up to date that in the very near future. We were at I think 14, roughly 14 TCF on that risk basis I think that you're referring to, Mark, and I think you've heard us talk about the 80-acre, the 40-acre and 20-acre wells that we'll be drilling. So this is just an incredible reservoir. That's about 11 to 13% recovery in the gas in place and we think it may go higher. But we'll update that here in the very, very near future.

If I could, is it correct you did not book any Cascade reserves despite sanction?

We did not book any, no, we did not book any lower tertiary reserves didn't not book any Cascade reserves specifically.

I want to add for all of you that we are planning on doing an update on Barnett and some, as well as resource potential throughout our portfolio sometimes in the spring and we will be announcing a date in the near future.

Thanks, guys.

Our next question will come from the line of Jason Gammel with (inaudible)

You had a very successful high-grading of the international portfolio over the course of 2007. I just want to see if you are reasonably happy now with the composition of that portfolio with focus on drilling in Brazil and China, or if there are areas that you were actually looking to supplement the international portfolio with? And then I guess on the other side of that is there anything within the portfolio that you would consider noncore, thinking make are maybe ACG in particular?

We will be happy with the portfolio once we have successfully exited out of West Africa. And we are hopeful that we'll get that done sometime here fairly soon. Which is the middle of the year. At that point in time we will be happy with the portfolio and we will see how it evolves. Brazil in particular is an area where significant reserves have been discovered. We've got as Steve described a large portfolio there and we very much want to see as it plays out. Azerbaijan still has some growth . They are still expanding in that field and it's not a core area for us in the sense that it's an area that we are going to grow or expand but it is a quality resource for us to keep in the portfolio. We have made and are making a lot of money off of that and in China also is an area where we have an interesting portfolio where we are using the same, a lot of the same technology and expertise we have in the U.S. deepwater in offshore China and offshore Brazil. So we will be fairly happy with that

Thanks for that incite, Larry. If I could follow up with one quick one. My recollection is that the Devon shares that are converted into Chevron shares mature this year is there any accounting treatment that we should be looking for moving forward? I think you actually have quite a bit more value in those Chevron shares than what the debenture are liable for.

Yes, you're referring to the exchangeable debentures that are exchangeable into the Chevron shares that we own and you are correct that they mature this year and we have several options available to us and we will consider those options and do what makes the most sense from a business perspective and really aren't prepared to say what that is at this point Jason. By the way, welcome back.

Thanks, Vince.

Jason, I will remind you that to the extent that we've had some of those exchangeable debentures to us in the last while we've paid them off using our strong balance sheet to do that.

Absolutely. Thanks, guys.

Operator, we will take one more question.

Our last question will come from the line of David Heikkinen with Tudor Pickering.

Good morning, wanted to talk a little bit about the strategic decision to start hedging in '08 and thoughts going into '09 given a pretty clean balance sheet and generating free cash flow. Can you talk through the decision-making process to start locking in some hedges?

Yes, with the concern particularly earlier this year or earlier in January with the large amount of gas in storage and with the twin concerns of both the U.S. sliding into some kind of recession as well as the overhang of gas that existed at that time we had some concerns about where natural gas markets very short term might be, that they might be volatile. As I said in my comments, the concern about gas storage has dissipated somewhat with the record withdrawals that we've had so that gas storage is now in line with five-year average. But we still have two more months to go before the winter is out and who knows what that's going to be. We just thought it would be prudent when we looked at the fairly remarkable swaps and collars that we get off, we thought getting a little insurance by giving up a little upside above numbers that we thought were fairly high to get a little downtime protection seemed prudent to give us a little insurance against short term volatility.

From early January to now would it be a surprise for you to do more hedges? Are you seeing a change now in where you think the commodity prices will be?

We've got about two-thirds of pushing two-thirds of our expected gas production hedged which is a rather large percentage. As you alluded to -- and a little oil where are the concern is not that much on oil. Because there are so many places around the world that can drive oil prices higher. It's, I think there are more upside pressure on oil than down side in general and worldwide economies there not just the U.S. economy which has more impact on natural gas prices. So I think we are fairly comfortable with where we are now.

Thanks, Larry.

And David, just to reiterate a point here, we've really, we were able to put some of these hedges in place in the last short while at very, what we think are very, very good prices because of the cold weather that we are having. But it really relates, nothing has changed other than we recognize that there is potential for a lot of volatility. There's still two months of winter left and who knows how that's going to look, then there's a bit more uncertainty around prices in the short-term. The point I want to make is we are really looking at a short-term perspective here. We still remain or are of the believe that we are going to see relatively strong prices through the end of 2008 and into 2009 on the natural gas side. So this really is just to address the concerns or the uncertainties that Larry mentioned in the shorter-term.

Thanks.

And as you correctly alluded when you started off your question, the debt is very, we have very little debt, very strong balance sheet , very strong cash flow and cash flow margins, budget for the year is well within our expected cash flow. So it's really no change in any of those drivers that we talked about in the past is driving this, it's just seeing some remarkable, remarkably attractive collars and swaps that you can get off in the face of some concern over

With that, that was our last question let me just say in summary that we are very pleased with 2007. Not only for what we accomplished in that year alone with production growth of 12 percent, taking reserves to an all time high, good strong earnings, record earnings, record earnings cash flow, but more importantly with what it portends for the future as we look at the success rate we had with the drill bit, bringing in very attractive F&D from across our portfolio, very attractive reserve growth and seeing the asset quality we had and the strength we have will continue that into 2008 and beyond. So we are very excited about 2008 coming off of a very strong 2007. With that we thank you for your attention and appreciate your interest in Devon. Take care.

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Good day.