德文能源 (DVN) 2004 Q3 法說會逐字稿

Good morning, and welcome to the Devon Energy Corporation's third quarter earnings conference call. At the request of Devon Energy, this call is being recorded for instant replay purposes. At this time, I would like to turn the conference call over to Mr. Vince White, Vice President Communications and Investor Relations. Thank you, sir, you may begin.

Thank you. And thanks to everyone who is joining us on the call today and on the webcast. We are going to start out with intro -- after my introductory remarks, with Larry Nichols, our Chairman and CEO. He will review the highlights for the quarter. Following Larry, we will have our President, John Richels give you third quarter operating highlights. And then, our CFO, Brian Jennings, will review our financial results and our outlook items. We'll hold a Q&A session following Brian's remarks, and as is our practice, we will limit the call to one hour, however, we will all be around for the remainder of the day for any follow-up questions you may have. Before I turn the call over to Larry, I've got a few quick items to cover.

First, in conjunction with our analyst meeting last month, we announced our move to the New York Stock Exchange. That transfer took place on October 12, so, we now trade under the NYSE ticker DVN. At the same time we announced that move we announced a two-for-one stock split. The distribution date for the split has been set at November 15. So the stock will begin trading on a post-split basis as of the November 15th trading session.

Now just a couple of quick compliance items. First, I'll remind you that we are providing forward-looking information in this call. While we always strive to give you the very best estimates possible, when we make an estimate, we do run the risk that our actual results will differ from our estimate. For a discussion of risks factors that can cause our actual results to differ, please see our form 8K that we filed on August 9. That's the filing that contains our most recent published estimates of 2004 revenues, expenses, and so on.

And, finally, I'll point out that in accordance with U.S. Securities Law for the non-GAAP performance measures that we use in this call, we have provided reconciliations. Reconcile those items to the closest GAAP performance measures. The reconciliations, along with our explanations as to why we view the non-GAAP measures as useful, can be found on our website. That address is www.Devonenergy.com.

With those items out of the way, I'll turn the call over to Larry.

Thanks, Vince. But before I get to the results of the third quarter, I want to cover the progress we've made on a couple of initiatives that we introduced just prior to our September 28th executive briefing in New York City. These initiatives reflect Devon's primary objective of maximizing shareholder value over the long-term.

First initiative that I want to update you on is the divesture of our non-core properties. We have now finalized the selection of assets that were offered for sale, and we're in the process of hiring advisors and assembling information for the data rooms. The data rooms will be open soon, and we expect first quarter 2005 closings for most, if not all of these sale properties. The market for North American properties is very strong, and based on the level of unsolicited interest that we have been receiving, we expect enthusiastic bidding for these properties. The assets we sold include offshore and onshore properties, both in the United States and in Canada. About half of the production from the Gulf of Mexico shelf is to be included.

The shelf divesture properties span the gulf from offshore Texas to offshore Mississippi. We are retaining shelf properties with infrastructure that we expect to utilize for future deep water or flex trend production, and we're also retraining those shelf assets that have significant exploration potential. In addition to shelf, we're also offering our interest in a few deep water fields. On a production basis, the Gulf of Mexico properties account for nearly 50% of the total divesture package. U.S. onshore properties represent about a quarter of the production that we are selling, and include properties in Texas, Mexico, Louisiana. In Canada, the properties to be sold include non-core properties located primarily in northwestern and central Alberta.

In total, the asset sales are projected to produce about 12 million barrels of liquids and 134 Bcf of gas during 2004 net to Devon's interest. That's what we expect to get from those assets in production this year. (Unit lease) Operating and transportation expenses associated with the divesture assets run a little over $6 per BOE. The property selected for divestiture are those that do not fit our own term strategic vision. They generally have shorter reserve life, higher decline rates, higher operating costs, and lower capital efficiency or limited upside when compared to our core assets. Selling these properties will allow us to focus our efforts on assets that can be more impactful.

In addition, the divestitures will improve Devon's capital efficiency going forward, therefore, less capital will be required to sustain or grow our reserves in production in the future. This will, obviously, leave us more cash for incremental projects, debt reduction, and share repurchases. We will continue to monitor these alternatives and select the allocations that, in our judgment, delivers the most growth in value per share over the long-term. In the near term we believe that the excess cash we are generating is best deployed through the purchase of our own equity. That decision led us to announce in September our program to repurchase up to 10% of our outstanding common shares.

It's no surprise that our asset base is continuing to generate significant amounts of cash over and above our capital requirements. In the third quarter we reached our goal of setting aside sufficient cash to repay all of our debt maturities through 2006. This amounts to approximately $1.6 billion. In October we began buying Devon shares. So far, we have expended $111 million, and have repurchased 1.5 million Devon shares. Assuming reasonably strong oil and gas -- oil and natural gas prices going forward, we expect to continue repurchasing our shares. Should we continue to enjoy high oil and gas prices, and realize $1.5 billion of after tax proceeds that we expect from our non-core asset sales, we will have to consider our cash deployments beyond the 10% share repurchase program that we have already committed to. In any case, selecting how to deploy excess cash is the kind of problem we like to be faced with.

Now, turning to the third quarter results, third quarter was another very strong quarter for Devon. Net earnings were $517 million, 26% ahead of last year. Earnings per share were $2.07, exceeding the first call estimate of $1.94.

First quarter oil and gas productions were a total of 679,000 Boe per day, or 62.4 million Boe for the quarter. This was in the top half of the 61-63 million Boe range that we indicated in our last quarterly conference call. We achieved this in spite of 4600 BOE per day for the quarter that were shut in due to hurricanes. Compared to previous quarters, daily production declined about 1%, driven primarily by production deferred due to hurricanes. While our gulf production was temporarily impacted by Ivan, a well instituted shutdown and evacuation resulted in Devon escaping without any personal injuries, loss of life, or any oil spills.

Total third quarter revenues reached 2.3 billion, and cash flow, before balance sheet changes, was 1.3 billion. Cash on hand climbed to 1.8 billion at September 30, bringing our net debt to cap(ph) down to 30%. This continued strengthening of our balance sheet was recently recognized by an improvement in outlook by Moody's. One other item that I'd like to call to your attention, before I turn the call over to John, the U.S. Environmental Protection Agency recently recognized Devon as Rookie of the Year in it's Natural Gas Star Program.

This program is a voluntary partnership between the U.S. Government and Industry to find cost-effective ways to reduce methane emissions. Devon was selected out of 13 first year participants in this program to receive this honor. I want to personally congratulate all of the Devon employees who enthusiastically embraced this win-win program for our shareholders and for the environment.

With this, I'll turn it over to John.

Thanks, Larry. Let's start out with an overview of the operations of the Company as a whole.

In the third quarter, capital expenditures for exploration and development came in at about $620 million, bringing the total for the first three quarters of 2004 to 1.9 billion. This puts us on track for our full year exploration and development expenditures of $2.5 billion, which is in line with our previous forecast. During the third quarter we drilled 503 gross wells, 32 of which were classified as exploration wells, and 471 of which were classified as development wells. 75% of the exploration wells were successful and 98% of the development wells were successful. As we ended the third quarter, we had 104 drilling rigs that worked in North America, 65 of which were drilling Devon operated wells. Internationally, we had 10 rigs running at the end of the quarter, and 4 of the 10 were on Devon-operated wells.

Now, I'd like to give you some area by area highlights beginning onshore in the U.S. In the Barnett Shale in North Texas, Devon continues to be the most active operator. We had 15 rigs running at September 30, 10 rigs in the core area, and 5 outside the core. Half of the 10 rigs in the core were drilling horizontal wells, and all of the rigs outside the core were drilling horizontals. During the quarter in the core area we brought 19 new vertical wells, and 13 new horizontal wells on stream, and, outside the core we added 7 new producing wells, 6 of which are were horizontals. Third quarter Barnett Shale production averaged 563 million cubic feet of gas equivalent per day, with about 40 million of the total coming from outside the core. So, total production was up slightly from the 555 million cubic feet per day that we averaged during the second quarter of 2004.

In aggregate at September 30, we had 1835 wells producing in the Barnett Shale of which 123 were horizontals, 75 in the core, and 48 outside the core. One area outside the core in which Devon, and the industry, are having particularly good results is in Johnson county. While only 8 of the 48 non-core horizontals that we have on production are in Johnson county, we have seen continuous improvement in this area. In fact, the last 3 wells that we drilled have had an average initial production rate of about 3.5 million cubic feet per day, an estimated recoverable reserves of 2.9 Bcf per well. And, based on results that we're seeing, we will be adding a second rig in Johnson county in the next couple of weeks.

We continue to drill wells across our acreage position in order to evaluate our entire 410,000 acre non-core inventory. Our objective is to determine the approach that will optimize results in each area, and we're working towards a comprehensive development plan for our entire Barnett Shale acreage base. As a result, in 2005 we plan to step up our non-core activity by drilling 100 horizontals outside the core area.

Turning to the Rockies. In the Powder River Basin coal bed natural gas play in Wyoming, we drilled 37 wells in the third quarter, and we are currently running 6 rigs. In the Huse(ph) Creek area, gross production increased to a record 33 million cubic feet per day, which is 25 million per day net to Devon's interest as a result of additional well head compression and the latest round of drilling on federal leases. Devon's net production from the Powder River Basin is running about 75 million cubic feet per day. Still in Wyoming, in the Washakie Basin we ramped up our drilling activity in the third quarter as wildlife stipulations were lifted in late June. With that ramp up, we had up to 4 rigs running during the quarter, and we drilled 16 wells, and connected 10 wells to sales. A 5th rig has been added, and we plan to drill an additional 20 wells by year end, assuming no regulatory delays. Devon's net Washakie productions is currently a little over 80 million cubic feet equivalent per day.

In Southeastern New Mexico we drilled 4 good Devonian wells in the Rio Blanco area, and are just completing a 5th. Total production from these Devonian wells is running about 13 million cubic feet per day net to our interest. We are also preparing to complete an exploratory well, the Mad Dog 15-1, which was drilled to another Devonian structure in the area. Devon has a 50% average working interest in these Devonian Rio Blanco wells.

In the Carthage area of East Texas we continue to increase net production, up about 10% from the second quarter to 191 million cubic feet per day. In the third quarter we drilled 16 new Cotton Valley wells, and recompleted 12 wells, adding combined net initial production of 15 million cubic feet per day. We plan to complete 16 additional new wells, and 15 additional recompletions by year end. Carthage has been a very good area for us, and in 2005 we expect to increase our activity level at Carthage with 84 new drills and 65 recompletions.

Moving now to the offshore Gulf of Mexico, as you heard Larry mention, we are still recovering from the effects of hurricane Ivan. Some of our facilities in the main pass and south pass areas sustained some minor damage, however, it's primarily the damage to third party pipelines and receiving facilities that's causing some of our production to remain shut in. It has been a real challenge for the industry to complete the required repairs, however, we expect to have substantially all of our production restored by year end. Brian will quantify the production impact for you later on in the call.

Now, to our drilling activities in the Gulf, as we reported in September, the fourth and final commitment well in our deep water joint venture with Chevron-Texaco resulted in another discovery. The Jack prospect which is a lower Tertiary prospect located on Walker Ridge 759 encountered more than 350 feet of net oil pay. Jack is Devon's third discovery in this emerging trend, following Cascade and St. Mallow, which are also in the Walker Ridge area. Appraisal(ph) drilling is planned for each of these discoveries in 2005, and we expect to production test one of those wells in 2005.

Also, during the third quarter we participated with a 35% working interest in the Sardinia(ph) well, the first lower Tertiary test in Keathly Canyon. While this well was plugged and abandoned, it did encounter significant reservoir sands and hydrocarbon (shoals), so we are encouraged about our other lower Tertiary prospects in the Keathly Canyon area.

As part of our ongoing joint-venture with Chevron-Texaco we have recently begun drilling on the Macaloo(ph) prospect on Mississippi Canyon block 937. Macaloo is a 30,000 foot sub-salt mioteam(ph) prospect in about 4200 feet of water. Chevron-Texaco is the operator, with a 3/8 working interest and Devon is participating with a 1/8 working interest. Since we’ve already completed the 4 wells that earned Devon 25% of Chevron-Texaco's interest in the joint venture blocks, we are now paying only our proportionate share on this and the other wells in the joint-venture. The well is currently drilling ahead below 7200 feet. We plan to spot another deep water exploratory well later this month on a prospect called Chillcoot(ph), which is also a 30,000 foot sub-salt mioteam target. Devon has a 20% working interest in this prospect, but we brought in a partner who will pay approximately 75% of our share of the well costs. Chillcoot on Green Canyon block 320 is in 2500 feet of water and it's operated by Kerr McGee.

On the deep shelf, we are now drilling the Joseph prospect located at High Island block 10. Joseph is interesting because it targets lower Tertiary rocks but it's near the coast in only 30 feet of water. This shell operated well in which we have a 20% working interest is planning to go to 24,000 feet and, if successful, Joseph could open up a new shelf play. Joseph is currently drilling below 11,000 feet.

Also, in the third quarter we had a discovery on the shelf, on the Star prospect which is located in West Cameron 165. This well was drilled to just over 12,000 feet, and found close to 40 feet of net pay. It was tested in two separate zones and brought online in early August. The well is currently producing 12 million cubic feet of natural gas per day and over 100 barrels of condensate per day from just the lower zone. Devon has a 100% working interest in this well and it looks like we may have a follow-up location to drill.

Turning to our Gulf of Mexico deep water development projects, the Red Hawk [Cell Star](ph) at Garden Bank 877 came online in mid-July and continues to produce at facility capacity in excess of 120 million cubic feet of gas per day. As you may recall, Devon has a 50% working interest in Red Hawk. Our Magnolia deep water project at Garden Bank 783 remains on track. The tension lake platform was set in place and certified as storm safe in August. The rig has been installed and platform facilities construction and well tieback operations are under way with first production expected in mid-to late November.

At the Nansen/Boomvang complex, sub-sea tieback operations to Boomvang were completed in early October on 2 2003 satellite discoveries. Eastbreak 598-1 and Eastbreak 599-1 added a combined 6500 equivalent barrels per day net to Devon, and with the connection of these latest two wells Devon's net production from Nansen/Boomvang is averaging about 40,000 equivalent barrels per day.

Finally, in the Gulf of Mexico the Atwater Valley Partners, of which Devon is a member, are getting very close to signing an agreement for the independence hub that will serve several natural gas deals in the eastern deep water gulf. Our 50% owned Merganser(ph) discovery on Atwater Valley block 37 will produce in to independence and we've committed about 60 million cubic feet of daily production to the project with first production expected in 2007.

Moving to Canada. Our summer drilling program initially called for the drilling of over 300 wells in the third quarter. However, unseasonably wet weather crossed most of our operating districts in July and August, severely limited field access and drilling operations, in fact, in some areas road bands have been put in place for the third time this year. The actual number of wells we drilled was just above -- was at -- was 161. By the end of September, the weather had improved and we were able to increase our drilling activity, we had 25 rigs running in Canada and 2/3 were operated by Devon. In spite of the reduced activity level we were able to grow Canadian production over the third quarter of 2003 and hold sequential quarterly production just about flat.

Looking at the first three quarters of 2004 our Canadian production is a little over 3% ahead of the corresponding period in 2003. This growth in volumes is being primarily driven by production growth in the deep Basin, the Foothills and the Lloyd Minster areas where, in aggregate, Devon's year to date 2004 production is up more than 20%. At Lloyd Minster, in spite of the weather, we were able to drill all 185 wells that were planned for our 2004 summer drilling program. Through September 30, 148 of these wells had been tied in, driving Devon's net production to a new record, at over 22,000 barrels equivalent per day.

On our Jack Fish thermal heavy oil project in Alberta, the 30 day public hearing notice period, that's required under the regulatory approval process expired in early October. We've been informed that no public hearings will be required, so we anticipate receiving regulatory approval around year end. For those of you who are new to Devon, Jack Fish is a 300 million barrel steam assisted gravity drainage project 100% owned by Devon. Phase I of the project is sized to produce 35,000 barrels per day when fully onstream in 2008. After receiving final approvals we will begin drilling well pairs and building the production facilities early in 2005.

Moving outside of North America, we had 10 rigs running at the end of the third quarter, and during the quarter we drilled a total of 22 wells on international projects. In Brazil, we drilled a successful discovery well on block BMC-8, which is a Devon operated block offshore in the prolific Campos(ph) basin. The discovery well encountered 150 feet of pay and a subsequent sidetrack found 200 feet of net pay with 18-21 degree gravity oil. There are a number of producing fields on trend, just to the north and to the east of the block, so we are very encouraged with these results. We plan to drill a third well as early as next month to test an additional structure on the block as we move toward commerciality.

Devon has a 60% working interest in BMC-8. Building on the success, and as we announced in August, we were the successful high bidder on two offshore blocks in Brazil's bid round 6. Block CM 61 and CM 101, in the inner Campos Basin, are located in a highly prospective area. And, as some of you may know, these blocks were among the choice blocks that PetroBrauth(ph) had originally retained and now has been required to relinquish for new competitive bidding. Under the terms of the agreements pertaining to these blocks, we will be acquire 3-D seismic and drill two exploratory wells on each block within the next four years.

In West Africa, offshore Equatorial Guinea field wide production at Shapiro remains very strong, currently over 300,000 barrels per day. Devon's net share is running about 45,000 barrels per day. Also, in Equatorial Guinea, we drilled an exploratory well in the third quarter on block P that was unsuccessful and has been plugged and abandoned.

Offshore Nigeria we are now in the process of finalizing our selection of partners for both blocks 256 and 242. We have a drill ship under contract and we expect the to spud the tari prospect on block 256 in early 2005. Tari(ph) is one of several high potential prospects that we have identified on block 256. We expect to operate that well with a 37.5% working interest.

Finally, in China, on the Devon operated Panyu project we brought 6 more producing wells on line in the third quarter, bringing the total to 25. Field wide production at Panyu averaged just over 82,000 barrels of oil per day in September, yielding about 19,000 barrels per day net to Devon.

So, with that, I will now turn it over to Brian Jennings for the review of Devon's third quarter financial performance. Brian?

Thanks, John. Solid operating performance drove up oil and gas prices and lower overall expenses characterized our third quarter financial performance. As Larry mentioned in his opening remarks, our third quarter 2004 production of oil, gas and natural gas liquid totaled 62.4 million barrels of oil equivalent or approximately 679,000 barrels per day. That was at the upper half of our forecasted range. It was a 1.5% decrease from the 689,000 barrels per day that we reported in the third quarter of 2003, and about 1% decrease from our second quarter 2004 results. Volume shut in due to hurricane activity drove our sequential quarter decline almost entirely. In the third quarter we deferred 420,000 barrels of production. As a result of the lingering impact of hurricane Ivan, that was the largest of the storms to move through the gulf, we expect to defer another 700,000 barrels of production in the fourth quarter.

In our September investor meeting we forecast full year 2004 production in the range of 251 million barrels equivalent. With three quarters complete that forecast implies 62 million barrels of production in the fourth quarter of 2004. However, as a consequence of the prolonged shut in of volumes related to Ivan we now anticipate fourth quarter production in the range of 61 to 62 million barrels.

Shifting to prices, oil, gas and natural gas liquids prices continues to be strong during the third quarter. The benchmark Henry Hub gas price averaged $5.75 per Mcfe(ph) in the quarter, up 78 cents from the third quarter of last year. In the quarter, our realized gas price averaged $5.17 per Mcf, or 58 cents under Henry Hub. During the quarter our natural gas hedges reduced our realizations by about 6 cents. Our floating gas price realizations were all pretty much within our forecasted differential ranges.

Moving now to oil prices. In the third quarter the WTI benchmark price averaged $43.80 per barrel. This price was $13.54 per barrel higher than the same period last year. In the quarter our realized oil price averaged $29.19. That was $4 higher than the third quarter of last year. There are several reasons why our realized price in the quarter failed to attract the increase in the benchmark price. First, we were negatively impacted by our oil hedges. During 2003 we entered into hedges on approximately 65% of our 2004 oil production. The hedges capped our realizations in the high 20's on the impacted barrels. Looking forward, many of our current hedges will expire in 2004. For 2005, we currently have hedges in place covering about 72,000 barrels per day of oil production. To put that in perspective that's about half the amount of oil we hedged in 2004.

In addition to the negative impact of hedges in the quarter oil price differentials widened for most types of crude. Our third quarter 2004 floating price realizations were $4.74 per barrel below WTI, compared to $3.09 below WTI in the third quarter of last year. Recently, we have seen basis differentials for both oil and gas widen from their respective WTI and Henry Hub benchmarks. Accordingly, we would expect price realizations to be lower relative to benchmark prices in the fourth quarter from most oil and gas producers. Looking ahead, we now expect that our fourth quarter floating oil price realizations to be $5.75 to $6.50 under WTI, and our floating gas price realizations to be 75-85 cents under Henry Hub.

Before we move into expenses, I want to briefly review our marketing and mid-stream results. Robust gas, oil and NGL prices in the third quarter led to another quarter of strong performance from our marketing and mid-stream division with margins for the third quarter totaling $89 million. Based upon the actual performance for the first nine months of the year and our outlook for the fourth quarter, we now expect our full year 2004 marketing and mid-stream margins to come in between $320 and $330 million.

Moving now to expenses, in the quarter most of our expenses were in line with our guidance ranges. A notable exception was, however, general and administrative expenses. G&A expense came in at 59 million for the quarter, this was 26% less than the third quarter of last year, and well below our 2004 guidance. But we expect our fourth quarter G&A expense to be higher than our third quarter result, somewhere in the range of $60-$70 million, it will be significantly less than the 86 million we reported in the fourth quarter 2003. We said in the past, that as various contracts expire and the dust settles from the integration of Devon and Ocean(ph) that we expect it to continue to realize additional efficiencies. Improvement we are seeing in G&A expense reflect to capture these efficiencies.

Our third quarter leaf operating and transportation expenses were in line with our guidance of $5.17 per barrel. We remained in line with our previous guidance despite being negatively impacted by both hurricane Ivan and the strengthening Canadian dollar. The $5.17 per barrel expense represents an 11% increase over the third quarter of 2003. We believe that this year over year increase is in line with what our peers have been recently reporting. We are pleased that we have been able to offset this year-over-year increase in unit operating cost with reductions in G&A and interest expenses.

Moving down our P&L, production taxes for the quarter came in at 48 million, that's about 2.4% of our oil, gas and NGL sales revenues before hedges. This compares to our forecasted range of 3.1 to 3.6% of sales. During the quarter, we recognized a $22 million credit to production taxes resulting from tax rate reductions for certain new Barnett Shale wells. Of the $22 million credit 18 million was related to a catch-up for prior periods. Going forward, we would expect production taxes to return to the previously forecasted guidance range.

Our interest expense also came in below guidance. At 109 million for the third quarter our interest expense was below the range implied by our full year guidance. We do expect our fourth quarter interest expense to be approximately 5 million higher than third quarter as a consequence of higher rates on our floating rate obligations. Our assumption is based on expectations that live oil will increase another 25 basis points during the fourth quarter. As we look into 2005, we expect further -- to further reduce our interest expense as we retire 917 million of maturing debt obligations.

Final expense item I would like to cover is the line entitled change in fair value of derivative investments. This non-cash expense results from the 760 million of Chevron-Texaco exchangeable debentures that we carry on our balance sheet. As most of you know, we own 14.2 million shares of Chevron stock into which these debentures are exchangeable. As the price of Chevron stock fluctuates we are required to adjust the recorded liability to reflect the change in the value of the option embedded in the exchangeable debentures. This change in the value of the embedded option is reflected through the income statement as the change in fair value of derivative investments. During the third quarter the value of Chevron stock increased. Consequently, we were required to recognize this $47 million non-cash expense.

Before we open up the call to Q&A, I want to focus on third quarter earnings and cash flow. For the quarter we reported net earnings of 517 million or $2.07 per diluted share, to allow you to compare our third quarter results to first call estimate, we have detailed in our press release non-cash items that are typically excluded by security analysts in their earnings estimates. In aggregate for the quarter these items decreased our diluted earnings by about 4 cents per share. Adjusting for these non-cash items we posted diluted earnings of $2.11 per share for the quarter, 17 cents per share better than the first call-mean estimate of $1.94. In the third quarter our cash flow before balance sheet changes totaled approximately 1.3 billion, after deducting capital expenditures and dividends, we generated approximately 500 million of free cash flow in the quarter.

Larry mentioned earlier that we ended the second quarter with 1.8 million of cash in the bank. We also disclosed that we have repurchased following at quarter end 1.5 million shares of Devon common stock. In spite of spending in excess of 110 million to repurchase shares our cash balance today totals 1.9 billion.

In summary, during the third quarter we posted solid operating performance boosted by strong commodity prices. We enhanced our performance, we've lowered G&A and interest expense, allowing us to capture and bring to the bottom line the impact of stronger oil and gas prices.

At this point, I'd like to turn the call back to Vince and we'll move into Q&A.

Go ahead, Operator, and give us the first question in the queue.

(Operator instructions) Our first question from Arjun Murti, you line is open, please state your company name.

Thank you. I'm with Goldman Sachs. Larry, at the analyst meeting in New York you were very clear about the lack of any real desire to do acquisitions. I'm sure you don't care to talk about specific packages, but, obviously in (indiscernible) put up some properties that you do have an interest in and there's some nearby acreage. Without necessarily commenting specifically on those, unless you'd like to, might that be the type of property package that could be an exception to the rule on not wanting to do acquisitions.

Arjun, you're breaking up a bit. Was that a package in Canada you're referring to?

Incana. Incana property package of the deep water properties.

Sure. There are, while we have -- as I've said repeatedly this year, we don't see any gaping holes in our current structure or in our asset mix. There're always properties out there one would like to add to the package and the ones that are additives to the positions we're already in. Having said that, because of the incredibly robust market that exists for packages, oil and gas properties, I think the odds of us buying one are approaching zero. There are just a lot of people out there paying top dollar. You can look at the properties we bought three years ago in the Barnett Shale, that was the right time to move into Barnett Shale. There are properties there are people paying very high premiums to get into relatively small positions in that area. They'd be good properties, that would be additive to us, but we don't see any reason to average up our costs dramatically by bidding into this current market.

That's very helpful. And maybe, one follow up. Any change to the estimated reserve range at the Brazilian discovery based on the results of the discovery sidetrack well?

Reserve range?

For our Brazil exploration activities.

This is Steve Hadden, the SVP for Exploration and Production. No, we are continuing to do the evaluation and work with that, our current view that we shared with you in September in New York is still the view we have at this point. We have some follow-up work that we're going to do in the fourth quarter including drilling another well on a second shoal in the block, and continue to move toward proving commerciality.

Thank you.

Our next question comes from David Kahani, your line is open. Please state your company name.

Yes. Friedman Billings & Ramsey. Houseman(ph) made a nice discovery in the Monkman(ph) area, and I believe you have good trend acreage there. Could you give us some color, either John or Steve?

David, it's John. Yeah, let me take you back. You recall in 1998 we actually made the first discovery in the lower Permian trend in British Columbia, that discovery was called Weejay(ph), and it really opened up a new fair way in British Columbia. There had been no discoveries in that Permian trend in that area. We followed that up with several additional discoveries, I think it was in 2001, or the beginning of 2002, we brought that onstream when the Grizzly Valley pipeline, which was the west coast, now Duke(ph) pipeline that transported those gas volumes up to the Pine River station and out through the West Coast system was put in place. We've had production for some time. We are pretty much at full capacity on that pipeline right now. We do have some significant acreage still on that trend, and that's essentially southeast of the Monkman area. That's an area that we'll continue to pursue in the future as we see additional opportunities to move the gas out of the area.

Their test was around 40 million a day. Is that comparable to what kind of experience you've had with Weejay? It was about 40 million a day.

Sorry, David, you're breaking up a little, too. That is consistent. The well that flowed the best for us was actually that first well, and not on an open flow basis but rather on a choke back basis at about line pressure, that flowed at 90 some odd million cubic feet per day. So, there are some very, very prolific wells in the area and the structures are quite large as well. So, we have seen, and we've seen several others in the meantime, in both that Permian trend and in some shallower zones that produced -- those kind of production volumes.

Moving over to the independence potential platform in the deep water, Steve, what do you think the cost net to Devon would be, what kind of range would you expect?

Assume going forward about $70 million for Devon spread over 2005 and 2006 and early 2007.

And one last question on G&A, do you think you can continue to see some improvement going forward from synergies?

This is Brian. We said, I think quite publicly, that if you're not focused on bringing down your costs they are going to trail up in a market like this. And, I think every employee of Devon as evidenced by our results, is focused on reducing costs. We're going to continue to try to get the benefits to continue to capture synergies from not only the Ocean transaction but other transactions that we've done in the past. We don't get it all day one but we work every day to try to realize it. As we mentioned, we don't expect the fourth quarter G&A numbers to be less than the third quarter numbers but we'll be trying to reduce them in the future.

And one last question, with the Repatriation Bill, what's the benefit and also the tax benefit to net to Devon?

As many U.S. corporations with operations outside of the U.S. we've obviously watched the bill progress with great interest. It will allow us to repatriate and reinvest in the U.S. in capital that otherwise would have been subject to tax rates -- much higher tax rates. So, the goal of the bill was to allow us to bring back dollars at a much lower tax rate? We think that will be capped around 500 million that will be allowed to be rebought back into the U.S. and reinvested. There are some other benefits in the bill but not significant to us.

And what does that mean, the $500 million? Does it allow you to be more efficient? Do you pay down debt with it? Do you buy back stock?

The goal of the bill was to allow you to recapture capital and invest it. So, we would be spending it in capital projects.

Thank you. Our next question is Ken Beer with Johnson and Rice.

Larry, or Brian, if you could give us a little more of a timetable for the asset sales. I know, Larry, you spent time on your initial comments, but just to give us a sense as to when you think all of this might be completed? And, then, also, has the disruptions from Ivan hampered that timetable? Were you forced to readjust your timetable because you got wells still shut in?

The process as we stated in September, as John mentioned, it's been, obviously a very busy October and now into November on getting the properties identified, getting advisors selected. We're very close and obviously getting the data rooms together. We'll have people in data rooms, I would expect, looking at data in November. We expect to close most of these transactions in the first quarter. There may be some that roll into the second quarter of '05. There are some people that have approached us to acquire larger pieces, and want to move on, what I would characterize as expedited time schedules, and, we've had a lot of interest as was mentioned. The issue about whether the hurricanes impacted the process, no, it's just a question of getting the data together, packaging it correctly, making sure we've identified the upside of the packages so we can get full value for our shareholders.

And as you present your '05 guidance, are you going to look at this package as discontinued operation and therefore, just give us volumes that would exclude the impact during the partial first quarter or maybe even full first quarter volumes?

Ken, this is Vince. In terms of providing guidance for 2005 production, we will when we provide more detail guidance. We'll give you what we expect our keeper assets to do and then we'll also tell you what the sales assets are currently producing, and then as we actually execute the sales and announce them we'll update you so you have a good idea of what our quarterly productions going to look like as we go forward.

I might add, the reason some of the sales might slip over in the second quarter is that on a few of the properties there are some third party rights of first refusal where you have to give notices to the third party and give them a certain specified amount of time to consider whether or not to exercise that. And if they take the full amount of time it might be a little longer to get some of the factories closed.

And just the follow-up, Larry, conceptually, if you’re sitting there with another billion, billion and a half dollars, your balance sheet is to the point where as you’ve already pointed out you can hardly even pay down any more debt. Is the thought behind raising the billion, billion plus to take that and really turn around and be even more aggressive on stock buyback, or can you put it to use in your CapEx program and really ramp up your CapEx program by hundreds and hundreds of millions of dollars.

The primary, the starting motive for selling these properties is that they are properties that don't fit what we want to do. They are non-core, as I said. They are on sharp decline, they have shorter reserve life. They are not properties where we think we can get the most bang for our buck by spending a lot of capital dollars to try and keep the properties flat or growing. We have better places to spend our money. Regardless of any other considerations, these are properties that we would sell because they don't fit our strategy, just as we've done many, many, many times over the Company's history. So, the uses of the capital really were unrelated to the desire to sell these properties. What we do with that capital is, of course, consideration of what we do with our surplus cash flow coming from operations, and as we said repeatedly, now that we have the debt where we want it, we have announced a share buyback program, we've announce the divestiture program, assuming both of those go successfully, and assuming the oil and gas prices stay high, then we'll certainly be able to look at either new capital projects that we might find, or to look at additional share buybacks.

Thank you, guys.

And our next question comes from Phil Pace with CSFB. Your line is open.

Phillip Pace, CFA: Good morning, guys. I wonder if you could be more specific on timing of the appraisals you have planned in the deep water gulf, and could you clarify with the drill shift in West Africa, it sounds like you sold down that interest and, wondering if you're paying a proportionate share of the cost for the well in Nigeria, and what the drill ship will do after the first well.

This is Steve. Let me back up. As you look, let’s take the last thing first, when you look at Africa and 256, we are in the process of finalizing the arrangements and negotiations on selling down to an operating interest of 37.5%. And, I think, as you identified, as part of the drilling program that we are beginning in West Africa we went and took the lead in negotiating with Transocean on an 11-well contract on drilling, and went in with three other partners. Currently, the plan is the first well will be, the first 5 will go to Shell and they'll drill their first well and then we plan to go to our well on 256 in January.

By joining with Shell and Exxon and Conoco-Phillips in doing this 11(ph) rig program, we bring down our collective costs because you can manage that rig more effectively and reduce our mobilization and demobilization costs quite significantly, so it's a win for us.

Phillip Pace, CFA: How many slots are you likely to get in '05? (inaudible) potentially drilling in '05.

In '05, essentially, we have at least two in '05.

And the other part of Phil's question was appraisal of lower Tertiary discoveries, was that right, Phil?

Phillip Pace, CFA: Yeah.

Phil, on the lower Tertiary, the appraisals, as you know, we have three lower Tertiary discoveries that we are looking at appraisals for next year, (indiscernible) St. Milo and now Jack. We think, sometime in the first half of the year, probably in the first half of the year we will look for getting those appraisals drilled during that period of time. In addition to that, we're hopeful in working towards obtaining a test on one of those prospects that's actually a production flow test, in order to further move toward the commercialization of those discoveries.

Phillip Pace, CFA: Is there any timing on the drill on the well at La Jolla?

That is also scheduled for first half 2005 spud day. We want to see the results, from BosPomp(ph) which will become public at some point. That's the BP prospect that is really the other half of the La Jolla prospect.

Phillip Pace, CFA: Looking forward to that. Thanks, guys.

So are we.

Thank you. Our next question from Irene Haas with Sanders Morris Harris. Your line is open.

How do you feel about your S&D(ph) cost goal, in the analyst conference you mentioned about 9 to 11 barrels, is that still good? Feeling any sort of cost escalation on onshore business?

I think, the question, Irene, what do we think about our S&D costs this year, as we conclude this year, and the impact of higher cost on S&D in the future, is that correct?

Yes.

Based on what we know today and the guidance we gave in September, you know, obviously, haven't changed any guidance from what we expect to deliver in S&D in 2004. I’ll pass it back over to Steve and he can talk to you about cost. We obviously budgeted in our -- currently in 2004 and in 2005 budget into our expectations cost increases, but Steve may give you some more color on that.

Irene, just to back up what Brian said, we are continuing along with our capital program as planned. We are seeing some pressure on rig rates and services as we move into the fourth quarter, but we believe we'll stay within the guidance range both on capital and on reserves. Obviously, as you know, when we come into the year end, we begin to have to look at price revisions relative to reserves, and we don't have those numbers yet, but relative to our current view and the guidance we gave in September we plan to believe to remain between $9-11 a barrel on S&D.

And you still think $7 and $9.50 is doable for '05?

Yes.

Thank you.

And our next question comes from Shawn Reynolds with Petrie Parkman. Your line is open.

Morning, guys. What has to happen in Brazil for that to be deemed commercial?

I'm sorry? Was your question, Shawn, what has to happen in Brazil for the BMC-8 prospect to be commercial?

Correct. You drilled a discovery well, you drilled a successful side track, you're drilling the third well, is the third well if that’s successful, is that enough to go forward on a development plan or do you need to drill maybe one more structure after that?

Let me give you a little picture on that. From BMC-8 perspective, as you mentioned, we drilled the first discovery well and then drilled a side track to delineate there’s a couple of shoals there, and the first shoals is the one that we drilled the discovery and the side track on, and our strategy is to move to the second there's another shoal, there's actually several shoals on the block. We're going to move to the second shoal, drill and test it. What that actually does is help us to determine the type of commercial development we would go forward with. As you may know, in that trend – and in that area, there are producing fields to the north that could provide an opportunity for some tiebacks if we continue to develop the field and increase the reserve size as we move toward our commercial assessment ,you would have probably, and most likely, the stand alone development on the block. What we want to do is go and test the second shoal and evaluate that work. We may come back to the first shoal and then continue some appraisal work there, and then we'll make a determination as to the type of development we'll go forward with and therefore, what the commerciality of the block would be at that point.

Is it fair to infer then that maybe, from what you have you think you have something commercial on the first shoal, you are just trying to determine how large it is, and whether you want to tie it back or go forward with the stand alone?

I didn't hear the question.

Can you hear me now? I was saying is it fair to infer then from your success on the first shoal that you probably have something that is commercial, you're just trying to determine, going forward, whether you want to do a tieback or if necessary just do a straight tieback or you might have something large enough to justify a stand alone development project.

Absolutely. That summarizes it effectively. We're evaluating it on the commercial side to determine exactly what commercial configuration we'll use to produce it. Keep in mind, we haven't completed the appraisal on the shoal A yet, either, so we are still moving forward with that, too.

I'm not sure, did you mention anything about Angola and the plans there?

Angola? Plans in Angola?

Our plans in Angola. In Angola, we have two blocks, block 10 and 24 that we plan to drill on next year in 2005. If you refer to the executive presentation that we did in September, we outline our plans there. There are several wells on those blocks that we plan to drill. We'll begin that drilling program in early 2005.

Thank you.

We've got time for one more question before we complete the call.

And that question comes from Bob Morris of Banc of America Securities. Your line is open.

On the Barnett Shale your production increased third quarter over second quarter. You've had good wells here recently. Do you see, before (inaudible) you'd seen that drop in 2008. Are you beginning to change your view a little bit there about how you can hold or grow production there, and in that regard, how are the horizontal infills in the core area coming in versus expectations ?

I just want to confirm your question, we're having a little trouble hearing you. Was your question about our production profile going forward in the near to medium term as it relates to the Barnett?

Yes. Given that it was up in third quarter over the second quarter, given recent well results both outside the core area and what you're seeing on the horizontal infill inside the core area.

As you know with the Barnett, we have a very strong position there and a lot of acreage, and a lot of potential, and we outlined that in September. Our central division team, and our team in the Fort Worth Basin have done a great job optimizing our production activity there, and moving forward with our drilling programs both in the core, which has been significant this year, and emerging in the non-core area. As John mentioned, we've had some success, continued success, with the horizontal wells in particular in Johnson county, which we've begun to see, both improved recovery and improved initial production rate, which is part of our plan going forward, to continue to move in intelligently, use the technology and our understanding to optimize the performance, and then move forward with the expansion, in particular in the non-core area. What you're seeing is partly a result of that, and the performance that our teams delivered there. Going forward, as we looked at it on a risk basis, we thought we would hold the Barnett relatively flat, as we continue to refine our drilling technology, and our completion technology and begin to ramp up our drilling activity, as John had mentioned, to something upwards toward 100 wells next year in the non-core. So, there's potential to do better than that, certainly, and we are really focused on that. We'll just see how it turns out. Right now we are confident with our current view going forward with flat production on a risk basis, should things go our way we push it harder and hopefully see improvements in that area.

How about the horizontal infills inside the core area. Are those coming in better or in line with expectations?

I think they're, basically leading our expectations as we're moving forward. We're relatively early in the program in the New York presentation we talked about them as longitudinal wells where we're drilling these infield horizontal wells. We've had some early results on a well or two that are very encouraging. We had one that was not so encouraging, but we're continuing to use that as a pilot, and as I said before, get our arms around the technology then expand that program with the opportunities we have in the core with our tremendous acreage position we have there.

Great. Thank you.

That concludes the hour, and as I said earlier, we'll be available for the rest of the day. Thank you for joining us for the call.