德文能源 (DVN) 2005 Q3 法說會逐字稿

Welcome to the Devon Energy Corporation third quarter earnings conference call. At this time all participants are in a listen-only mode. [Operator Instructions] I'd like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Welcome everyone and thank you for joining us for Devon 's third quarter 2005 conference call and webcast. I've got a few introductory remarks and then our Chairman and CEO, Larry Nichols, will offer his comments about the third quarter and the remainder of the year, then our President, John Richels, will review operations followed by Brian Jennings, our CFO, who will provide a financial perspective on the quarter and the remainder of 2005. As is our practice we'll then open our call to your questions and cut it off about 11:00. We try to wrap them up -- these calls up in an hour.

First compliance item I have to cover is to remind you that we typically provide full-year forecast in a form 8-K filed with the Securities and Exchange Commission. The recent hurricanes have caused us to slightly modify our 2005 production forecast and we communicated that information in our recent news releases. During today's call we plan to tweak our forecast for a few other line-items for the fourth quarter so that we're providing you the very best insight possible into what the rest of the year looks like. We will issue a form 8-K later this week that will document this update. After the 8-K is issued it will be posted on the estimates link from the investor relations menu on devonenergy.com. So, we'll be e-mailing it out to our distribution list and then anyone else can obtain it off the website.

All discussions of plans, forecast, estimates and expectations are what's called forward-looking statements as defined by the Securities and Exchange Commission. For a discussion of risk factors that can cause our actual results to differ from our estimates, I'd encourage you to see the form 8-Ks that I mentioned. One final compliance item that I'll call your attention to is non-GAAP performance measures. Under current U.S. securities law, certain metrics we use, that we used in this -- that we will use in this call are defined as non-GAAP measures and when we utilize those metrics we're required to provide reconciliations to the closest GAAP performance measure along with our explanation as to why we find the no -GAAP measures useful. If you'd like to see a very interesting information, you can find that on our website. With those items out of the way, I'll turn the call over to our Chairman and CEO, Larry Nichols.

Thanks, Vince and welcome everyone to our call today. As can you see from the results that we reported, the third quarter of this year was another outstanding one for Devon . The Company generated $744 million of earnings for the quarter, setting an all-time record for both net earnings and earnings per share. When you add back the $0.24 per share for items that analysts typically exclude from their estimates, we had adjusted earnings of $1.87 per share, beating the first call estimate mean of $1.80 per diluted share. Cash flow before balance sheet changes, climbed $300 million over 2004 levels to 1.6 billion. We also reduced our average diluted share count by 9% over the last year, which, of course, amplifies our per share growth even more. We retired $668 million of debt during the quarter and repurchased $567 million of our stock. This completed the first 50 million share repurchase program and we have now in the fourth quarter commenced repurchasing stock under our second 50 million share program.

In spite of these activities, we still ended the quarter with 1.9 billion of cash and short-term equivalents. We had an excellent quarter operationally. We had positive results in our high-impact exploration program with successful rolls in Equatorial Guinea, in the Gulf of Mexico and in U.S. on-shore. We have continued to advance our on -- our large-scale developmental projects at Jackfish in Canada, at Palbo (ph) in Brazil and in the Barnett Shale in north Texas, and we've continued to move forward in the Bossier play in Louisiana and the Woodford Shale play in Arkon -- in Arkoma -- it's in Oklahoma, plays that will reload our core North American drilling inventory. All in all, it was a very rewarding quarter of executing the game plan that we have consistently articulated.

Before I turn the call over to John, I want to thank our employees and their families who were directly affected by the two major hurricanes that hit the Gulf of Mexico in August and September. Dozens of Devon's Gulf employees lived directly in the path of Katrina. A number of those employees lost their homes in the storm. In the face of those personal hardships, those employees remain incredibly dedicated to ensuring that Devon's personnel and assets were safeguarded. I'm also very proud of the response of Devon employees that were not directly impacted by the storm. Employees throughout the Company responded with overwhelming generosity and compassion for their fellow employees, many of our Houston area employees took in friends and relatives who were forced to evacuate their coastal communities. Donations of cash, clothing, toys, household goods and time poured in from all of our Company offices. On a wider scale, Devon and many other energy employees pledged donations to hurricane relief efforts. Devon itself pledged $2 million and we've begun to disperse those promised funds to various agencies.

Our Gulf team also did a good job in responding to the hurricane from an operational standpoint. We safely evacuated over 300 people and secured the facilities in advance of the storms. Following the storms, they moved to get critical vessels and equipment necessary to complete post storm underwater inspections and restore production as soon as possible. In addition, Devon had no reports filled throughout the entire ordeal. Last week, we reported that we had restored about 50,000 Boe per day on our offshore production. We expect to have another 20,000 barrels per day back on stream by year-end. This will bring us to 70,000 barrels per day that we restored at year-end with approximately 17,000 BOE per day of capacity remaining shut in as we go in in 2006. It remains uncertain at this time when that production will be brought back on line. However, this represents less than 3% of companywide production and we're well insured for both physical damage and lost production. With that, I'll turn the call over to John RIchels. John?

Thanks, Larry. In August, we said that we expected to spend 3.2 to $3.4 billion of exploration and development capital during 2005. This is in addition to the roughly $200 million we spent on the Iron River acreage acquisition from Exxon that we told you about last quarter. During the third quarter, our E&P capital expenditures totalled $913 million, bringing the year-to-date E&P capital expenditures to 2.6 billion. We have about 800 million budgeted for E&P projects for the fourth quarter, so it looks like we'll be near the top of the forecasted range for range for full-year capital spending. With the success that we've had in our Barnett Shale area and in our exploration program, we expect reserve additions for the year to come in at or above the top-end of our forecasted range. So, in spite of some increases in capital, we expect to deliver very competitive finding and development costs in line with our previous guidance.

At the end of the third quarter, we had 118 rigs running Companywide with 73 rigs drilling Devon operated wells. During the quarter, we drilled 659 gross wells with 48 classified as exploratory wells and 611 as development wells. Essentially, 100% of the development wells and 73% of the exploratory wells were successful giving us an overall success rate for the quarter of 80, sorry, of 98%.

I will begin the operational highlights with a review of Devon 's Gulf operations and the impact of the hurricanes. As Larry said, we've restored 50,000 equivalent barrels per day of our offshore production and we expect to have another 20,000 barrels per day restored by the end of the year. The most significant asset that's currently offline is Red Hawk. It produces about 10,000 equivalent barrels per day, net to our 50% working interest and it is currently awaiting pipeline repairs. Production that will likely remain offline beyond year-end includes a portion of the-- of the production in the Devon -operated Eugene Island area where we lost three platforms. Now most of this production can be rerouted through other nearby facilities so there will be no need to replace the lost platforms. And as we disclosed in or our press release last week, we are insured for physical damage and business interruption. The Conoco-Phillips operated Magnolia deepwater tension leg platform weathered the storms and is back on production. Well completion operations are also back on track. We've now commenced production from 5 of 8 planned wells. Production from Magnolia, which is on Garden Banks block 783, is now running about 10,500 equivalent barrels per day, net to Devon 's 25% interest.

The recent hurricanes impacted not only production operations in the Gulf but drilling projects as well. We really want to commend BHP Billiton, the operator of our Cascade pro -- project, for the safe and efficient manner in which they've managed this deepwater drilling project through an unprecedented hurricane season. We mentioned in the second quarter conference call that we had begun drilling in appraisal of our 2002 Cascade discovery on Walker Ridge block 2 -- 206. The deliniation well was drilled to the northwest of the discovery, encountered hydrocarbons and extends our view of the boundaries of the reservoir. We are very encouraged by the results and are now drilling an updip side track to the southwest of the discovery well. We expect to conduct a production test of this well in 2006, which we hope will lead to sanctioning of the project for development. Devon and -- and Petrobras each have a 25% working interest in Cascade and BHP is the operator with a 50% working interest.

Chevron's also done an outstanding job through the recent hurricanes of operating the appraisal well to our 2004 Jack discovery on Walker Ridge 759. The well is proposed to be drilled to 29,350 feet. It's currently just over 28,000 feet and it's gone under -- has undergone extensive evaluation. Although we've not reached total depth, we're highly encouraged by the open-hole information obtained to date. We plan to return in the first quarter of 2006 with Transocean's Cajun Express drill ship to conduct an extended production test. Successful test results are an important step towards the sanctioning decision for Jack. Just to remind you, we have a 25% working interest in Jack.

In our deepwater myocene program, we plan to spud an exploratory well later this year on the Caterpillar prospect. This is a 28,000-foot subsalt myocene target located on Mississippi Canyon 782 in about 6,500 feet of water. Devon has a 25% working interest in Caterpillar and it's operated by Chevron.

Turning to the shelf, last quarter we told you about the Devon operated Shopan (ph) discovery on Eugene Island block 334. The startup of this well has been delayed by Hurricane Rita. We now expect to have it on production at between 10 and 20 million cubic feet per day by mid-2006. Devon has a 100% working interest in Shopan and this discovery has positive implications for the broader Eugene Island 334 area and may lead to additional drilling.

On the deep shelf, the Cadillac exploratory well was unsuccessful. This was a Cotton Valley test on Viosca Knoll 251. Devon had a 10% working interest in Cadillac.

Turning now to our on-shore operations in the Barnett Shale field in North Texas, we continue to have good results both in the core area and in the non-core. During the third quarter, we brought our 2,000th operated well on production and at the end of the quarter, we were running 18 operated rigs in the Barnett, that's up from 14 operated rigs at the beginning of the year. Eight of the 18 rigs we're drilling outside the core and five of these eight rigs we're drilling in Johnson County. In our second quarter conference call, we said that we expected to get our Barnett production up to a record 590 million cubic feet equivalent per day by year-end 2005. We're approaching that number well ahead of schedule with current production running at about 575 million cubic feet per day. However, we did not set a Barnett production targ -- production record during the third quarter. Hurricane Rita caused some outages at downstream facilities and forced us to shut in portions of the Barnett for a few days. This reduced our third quarter Barnett production by about 1.1 BCF equivalent for the quarter or an average of 12 million cubic feet per day. In spite of the outages, we remain on track to meet our forecast of a 2005 exit rate of 590 million cubic feet equivalent per day and a 2006 exit rate of 630 million per day.

As we mentioned last quarter, Devon has initiated a core area horizontal in-fill pilot program. We've now completed about one-fourth of the planned pilot wells and the results are encouraging. These horizontal wells are yielding average initial production rates of about 2.3 million cubic feet equivalent per day. Although it is still early in the pilot program, we're very encouraged with the results to date and it appears that we may ultimately drill as many as 350 additional horizontal in-fill wells. On a risk basis, this represents an excess of one-half trillion cubic feet of additional potential net to Devon in the core area alone. We are also encouraged with the results that we've had to date in another shale play that we're working in the Woodford Kaney (ph) shale play in the Arkoma basin in eastern Oklahoma, Devon has assembled 70,000 net acres with working interest ranging between 50 and 80%. These shales are at depths of 4,000 to about 10,000 feet. We have early production results from three horizontal wells and they're quite encouraging. Our economic model assumes a cost of about $3 million per well. Initial production of 2.1 million cubic feet per day and about 2 BCF of recoverable reserves. This would indicate an economically viable project of the one half to 1 TCF of risk reserve potential net to Devon's interest. We'll keep you updated as we drill more wells and as we have more production history.

In Washakie basin in Wyoming, we ramped up our drilling activity during the third quarter as seasonal drilling restrictions were lifted in late June. We had as many as six rigs running during the quarter and we drilled 11 wells. We planned to drill an additional 20 wells by year-end, thereby, completing our 55 well program for the year. Devon 's net Washakie production is running a record 94 million cubit feet per day.

Moving to east Texas. In the Carthage area, we continue to increase production in the area with out Cotton Valley drilling program. We're running five rigs and in September we drilled the 64th well of the 93 well program planned for this year. Devon 's third quarter Carthage production averaged 210 million cubit feet of gas equivalent per day. Just east -- just east of Carthage in north Louisiana, Devon holds roughly 200,000 net acres in the Bossier play. Devon holds a mineral interest on approximately 153 thousand of these acres and this really dramatically increases the value of our position since ownership of the minerals interest means that we have no royalties to pay. We have defined seven separate prospect areas on our acreage, each with reserve potential of sever -- several hundred BCF.

During the third quarter, we reached the total depth of approximately 16,800 feet on the Devon / Donner 1-1 well on the Vixen prospect. This well is currently being tested in a follow-up well, the Devon / Donner 7-1 is underway. Anadarko operates these two wells and we have a 49% working interest. Last quarter, we also drilled an exploratory well in our north Vixen prospect area in the Bossier play. This well encountered 2,300 feet of gas-charged Bossier section. While the well tested tight, we're encouraged by the results and we're now acquiring 3D seismic over the area to help us better position the next well in the prospect. We expect to spud an exploratory well in another our -- another of our Bossier prospects, East Vernon, in mid-november and in 2006 we plan to complete three 3D seismic surveys on our acreage and test three additional Bossier prospects.

In South Texas, in Matagorda County, we completed the well that we mentioned in -- in last quarter's call. The Otis Ayers (ph) 1 well is producing 22 million cubic feet of gas per day from the lower Frio (ph) formation. This is a 100% Devon well and we're now drilling the first of four or five possible offsets.

Moving now to Canada. In the third quarter, we drilled 22 wells on Devon operated leases in the Deep Basin, all of which were successful. Nine of these were in the Wapiti and Bilbo areas and tested at a combined production rate of 26 million cubic feet per day. In our Lloydminster oil play in Alberta, we drilled 125 Devon operated wells in the third quarter and have drilled 231 wells year-to-date. Lloydminster production averaged about 23,000 barrels of oil per day in the quarter. Lloydminster includes the Iron River area where, as you may recall, we acquired an extensive acreage block from Exxon in the second quarter. We have drilled 49 wells at Iron River to date, and these are the first of more than 800 wells that we have planned for Iron River.

At our Jackfish SAGD Heverol (ph) project in Eastern Alberta, facilities are under construction and the first production wells were drilled during the third quarter. Just to remind you that Jackfish is a 300 million barrel project with first production scheduled for 2007 and full production of 35,000 barrels per day expected in 2008. We've mentioned in the past the potential for expanding the Jackfish project beyond the first phase. In that regard, we are currently evaluating our acreage immediately to the west of Jackfish where a second project, Jackfish 2, has the potential to add an additional 35,000 barrels per day of production and about 300 million additional barrels of reserves. We drilled 42 stratographic test wells last winter and plan to complete the delineation this winter drilling approximately 40 additional stratographic wells. If we decide to proceed with the project, construction on Jackfish 2 could begin as early as 2008 with initial production two years later.

Finally, moving to our international projects, starting in West Africa, I'll begin with our operations offshore Equatorial Guinea, where gross production from the Zafiro field remains strong, currently, roughly 260,000 barrels of oil per day, with Nev -- Devon 's net share running about 33,000 barrels per day. Also in Equatorial Guinea, we had two potentially significant off -- offshore discoveries during the third quarter. The Esmerelda (ph) exploratory well that we mentioned in last quarter's call, reached a total depth of 16,000 feet during the third quarter. Esmerelda is located on Block B near the Zafiro field and in operated by Exxon Mobil's affiliate Mobil Equatorial Guinea Inc. The Esmerelda well encountered hydrocarbons in three zones in the myocene formation. The most significant of these zones had 90 feet of net gas condensate pay. This appears to be a complex reservoir system that will require further drilling to confirm commerciality and to determine the path forward. However, we're excited about the discovery and its potential.

In 2006, we plan to reprocess seismic data that will help us better understand the reservoir system and potentially drill a follow-up well in late 2006 or early 2007. Devon has a 23.75% work interest in in Esmerelda. We also had a third quarter discover on the Vemus (ph) prospect, which is located on Block P in Equatorial Guinea. Vemus is operated by Devon and the exploratory well was drilled to 7,100 feet and encountered about 150 feet of net oil pay. The well was subsequently sidetracked down dip to delineate the discovery and logged 114 feet of net oil pay. The hydrocarbon system at Vemus consists of multiple channel sands similar to the Zafiro field. A good deal of technical analysis and further drilling is required to define the reservoir and to determine commerciality. Detailed seismic interpretation and ABO analysis is planned for 2006 and we plan to drill as many as three additional wells in this area next year. We're excited about the implications of the discovery and its potential to become another significant field for Devon in West Africa. The Vemus prospect is in relatively shallow water and is close to shore and could be brought on produ -- production by 2008. Devon has a 38.4% working interest in Block P.

We see these two discoveries as potentially significant additions to the overall exploration effort in Equatorial Guinea. We expect them to contribute to the stable, long-term production base for Equatorial Guinea thereby reinforcing the current producing fields.

Also in West Africa, we have a couple of high potential wildcats that are planned for the fourth quarter. In Equatorial Guinea, again, we plan to test the Siete (ph) prospect in Block N and in Angola on Block 10 we expect to test the Ingivai (pg) prospect. Ingivai is the first of two exploratory tests planned for this block.

Turning to Brazil, our Palbo (ph) development project on offshore block BM-C-8 continues to move ahead on schedule and we -- as we negotiate contracts for the necessary production equipment and facilities. A final development plan was submitted to Brazil's national petroleum agency in September and we expect approval in November. We expect to begin construction in January with first production projected for the second half of 2007. While we described Palbo as a 50 million barrel resource, we believe there's considerable additional potential on the block. We plan to drill three additional wells at BM-C-8 next year in hopes of expanding the limits of the field.

Building on our success at Palbo, Devon was the successful bidder on four offshore blocks in -- in Brazil's recent bid round seven. Through joint bids with Petrobras, we were awarded a 50% interest in two blocks that Devon -- that will operate and a 35% interest in the third block that will be operated by Petrobras. Both these three blocks and BM-C-8 are located in the Campos Basin. Given their extensive knowledge of the area and their track record of success, we are excited about our partnership with Petrobras. Devon was also awarded a 100% interest in a fourth block located in the Camaroon Basin to the north of the Campos Basin. Our share of the bonuses on the four new blocks is approximately $46 million. With the edition of these blocks, Devon now holds in excess -- excess of 800,000 net acres offshore Brazil. In 2006, in addition to the delineation wells at Palbo, we are planning our first exploratory tests on blocks BM-C-30 and BM-C-32.

Finally, in Azerbaijan, where Devon has a 5.6% carried interest in the 5 billion-barrel ACG oil field, gross field production has climbed to more than 350,000 barrels of oil per day. We expect to reach payout under our carried interest arrangements in 2007. Under this scenario, our net share of peak production would be in excess of 30,000 barrels per day beginning at payout. So that concludes our operations update, now I'll turn the call over to Brian to review our financial results. Brian?

Thanks, John. I will begin by looking at some of the key drivers of our third quarter financial results and update for you our fourth quarter outlook. Looking first at oil and gas production, Devon 's third quarter production totalled 55 million equivalent barrels. That's just ahead of the 54.6 million barrels we had forecasted in our update following Hurricane Rita. Hurricanes reduced our third quarter production by about 1.8 million barrels. Adjusting for the deferred hurricane volumes, we were on track to exceed the 56 million barrel forecast we had outlined in our second quarter conference call. For those of you looking at our regional results, our production forecast did include 900,000 barrels of production in Canada that were recognized in the third quarter related to a shut-in gas settlement with the province of Alberta. For those of you that have followed Devon, you will recall that we were forced to shut in natural gas production in certain areas in Alberta where bitumin is produced. Of the 900,000 equivalent barrels we recognized in the quarter about 800,000 of these barrels were related to prior reporting periods.

Looking ahead, we had previously forecasted fourth quarter production of 56 million equivalent barrels. However, as we disclosed last week, given the ongoing impact of Hurricanes Rita and Katrina, we now expect to produce about 53 million equivalent barrels in the fourth quarter.

Moving now to price realization, first to oil. The WTI benchmark price increased in the third quarter, averaging $63.16 per barrel. Oil price differentials in the quarter narrowed compared to the second quarter. Our Companywide realized price, before the impact of hedges, was nearly 90% of WTI, up from 86% of WTI in the second quarter. Prices were especially strong in Canada as heavy oil differentials narrowed. Overall, oil price realization for all of our geographical regions came in at or above the top of our guidance ranges. Despite this recent narrowing of oil differentials, we are still comfortable with our full-year differential guidance for oil.

As expected, financial hedges did reduce our third quarter realizations. Looking ahead, Devon 's fourth quarter oil price realizations will be impacted by hedges on 55,000 barrels per day of production. That volume is 9,000 barrels per day less than our previous guidance. The reduction of hedged volumes resulted principally from the unwinding of hedges associated with deferred Gulf production. As we've previously discussed, our oil hedges expire at the end of 2005 and we currently have no oil hedged 2006.

Shifting to natural gas prices, the benchmark Henry Hub gas price averaged $8.53 per MCF in the third quarter. Differentials, however, were wider than expected and all of our producing regions outside of the Gulf Coast. While third quarter oil price realizations were at the high end of our guidance ranges, our natural gas price realizations came in at the low end of our guidance. Companywide gas price realizations for our unhedged volumes were just 85% of Henry Hub in the third quarter. In addition, natural gas hedges and fixed price contracts reduced our third quarter price realizations by about $0.13 per MCF. Natural gas differentials have remained wide in the fourth quarter. Looking forward, we now expect fourth quarter natural gas price realizations to approximate 95% of nimex (ph) for our Gulf volumes and 75% of nimex for our U.S. onshore and Canadian volumes. As with oil, our 2006 gas production remains unhedged.

Before we move into expenses, I want to highlight another strong quarter of performance from our marketing and midstream operation. Marketing and midstream margin for the third quarter totaled $111 million, an 18% increase over our second quarter results. Based upon our performance in the first nine months and our outlook for the fourth quarter, we are increasing our 2005 margin forecast. We now expect our full-year 2005 marketing and midstream margin to come in between 380 and $400 million. That's a $50 million increase over our previous guidance.

Moving now to expenses. Most expense items were in line with our guidance. I'll cover only the items that were exceptions or where we have refined our outlook for the fourth quarter. Our lease operating and transportation expense totaled $319 million in the quarter, or $5.80 per equivalent barrel. While this per-unit expense is in line with our full-year guidance, the result was slightly above the range we forecasted in our second quarter call. Looking ahead, we expect our fourth quarter lease operating and transportation expense to come in at around $5.90 per barrel. Third quarter DD&A expense came in at $8.96 per barrel, which remains in line with our full-year guidance. Looking forward, cost pressures within the industry are likely to push our full-year DD&A expense to the high end of our guidance range of $8.60 to $9 per barrel.

Looking at interest expense, we reported interest expense of $164 million for the quarter. Of that expense, $51 million resulted from the early retirement of our 6.75% notes which we redeemed in the third quarter. We had announced our intention to call these notes in our second quarter conference call and highlighted this charge at that time. Excluding the charge, third quarter interest expense totalled $113 million, that's just above the high end of our guidance range. Our drift to the high end of the range was due to the impact of rising interest rates on the variable portion of our debt portfolio. Looking at the fourth quarter, we expect our interest expense to total between 100 and $110 million.

The next expense item I'll cover is the line item entitled change in fair value of financial instruments. As you know, we don't typically provide forecast for this line item. For the third quarter, that reported expense was $134 million. 90 million of this amount is a non-cash charge related to the Chevron exchangeable debentures on our balance sheet. As discussed in previous conference calls, Devon owns 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 options imbedded in the debentures. In the third quarter, the value of our Chevron stock holdings increased by 125 million driving the $90 million expense. The remaining $44 million of this line item expense is attributable to hedges that no longer qualify for gas hedge accounting. This primarily relates to hedges on offshore Gulf of Mar -- Mexico production that was shut in because of the hurricanes.

Third quarter income tax expense was in line with our guidance at about 35% of pre-tax income. We had forecasted that we would defer one-third of our third quarter income tax. However, in the quarter, almost half of our tax expense was deferred. This increase in deferred tax came about because our actual 2004 income tax liability was lower than originally accrued, resulting in a $76 million transfer from current tax expense to deferred tax expense in the quarter.

Moving to the bottom line, net earnings for the quarter totalled $744 million or $1.63 per diluted share. Adjusting for items that are generally excluded from [INAUDIBLE] assessments, as detailed in today's earnings release, diluted earnings would have been $1.87 per share for the quarter or $0.07 better than first call estimate of $1.80 per share. This level of earnings translates into cash flow before balance sheet changes and 1.6 billion for the quarter.

Before I turn the call back over to Vince and we open up the call to Q&A, I want to take a moment to update you on our cash position. With our 1.6 billion of cash flow in the quarter, we comfortably funded roughly 1 billion of capital expenditures. In addition, as discussed in of our second quarter call, we repurchased in the 3 quarter -- in the third quarter, $567 million of Devon common stock, approximately 10.4 million shares. Bringing to a conclusion our initial 50 million share repurchase program. Balancing our share repurchase activity, re -- we retired in the quarter two maturing debt issues totaling $268 million and redeemed our 6.75% notes, bringing our debt reduction for the quarter to $668 million. We ended the quarter after funding capital expenditures, share repurchases and debt reduction with 1.9 billion of cash and short-term investments and a net debt to adjusted cap ratio of 23%. Following quar -- quarter end, we initiated share repurchases under our recently announced second 50 million share repurchase program. To date, we have repurchased an additional 2.2 million shares, at a cost of $132 million. Again, balancing our repurchase activity, we retired yesterday 235 million of maturing debt, bringing our total debt reduction for the year to over 1.3billion. That said, our liquidity remains strong with our cash and investment balance today topping $1.6 billion. All in all another outstanding quarter for Devon. At this point, I'll give it back to Vince and we'll move into Q&A. Vince?

Thank you. [Operator Instructions] Our first question comes from Steve Enger of Petrie Parkman.

Hi, guys. A couple of things on Esmerelda first. That was thought to be a very large structure going in in terms of what you found in net pay. Do you still see that as a very large structure? And then second, and most importantly, what would you see if it does end up being predominantly a gas discovery as options for marketing that gas?

Yes, this is Steve Hadden. Esmerelda, again, as John mentioned, we've shared as much of the technical or more detailed information that we could in the -- in the discussion that John had, but I will tell you from a big-picture standpoint, we do think Esmerelda is a high-impact opportunity. We do think the -- the structure and the opportunities in the channels in the area have significant size and potential impact. Obviously there's technical work and some other things that John described that we need to do to move forward. And we're still working through the commercial issues as it relates to the --as -- as it relates to the -- the products we might produce. So, in essence, we still think the structure is significant. We think, obviously, there's some encouraging results that we've had to date and we'll work with our partner to continue to -- to move towards the commercialization.

Okay, and, Steve, when you guys talked about it as being complex, is part of that perhaps that the first well was drilled high in structure so you still have uncertainty as to the fluid content?

No. Without -- without getting into too much detail, we -- we simply have known -- known going in and have recognized that the geology as it is within Zafiro is relatively complex which can have certainly some larger structures but also have a complex channel system involved at the same time. And those are the issues that we're really talking about when we talk about the complexity of the -- of the opportunity.

Okay. Thanks on that. And on the lower tertiary results which sound encouraging, can you say anything more about the correlation you see between appraisal well and discovery well results and then do you have any better insight on reservoir quality issues now with additional wells?

What I -- what I can say is that we're continuing to be very encouraged by the results that we've seen to date. On both of those prospects, we're working closely with our partners, especially within our technical teams and our technical teams are in the process of looking at that information and -- and -- and really getting into it a bit further. And at some point, we'll probably have more information to share with you.

Okay, and last from Young, Caterpillar, is that also a high-impact kind of opportunity for you? In terms of size, several hundred million barrels?

We believe it's a -- it's a deeper water myocene opportunity, and we think it can have a impact within our expiration program.

Thanks.

Our next question comes from Ben Dell of Sanford Bernstein.

Hi, guys. I have three questions. The first is really on the cost inflation standpoint. I noticed that year-on-year, the real ability to hold down cost is driven by your DD&A following on from the divestments. Do you have a feeling where DD&A for Bower (ph) is going to be going in '06 and '07 and whether you'll be able to constrain the cost inflation in that? And my second question was on the deep water, whether or not you have the rig availability or rig signed up so you can fulfill you're '06 and how confident you feel looking into '07 given the tightness in the market? And -- and my last question is really on acquisitions. Given the increase in the cost of finding and development costs, do you feel a return to the acquisition trail is something you'd be interested in right now, especially as the equities trade off, given that you've sort of recompleted your restructure?

This is Vince. I'll -- I'll take the -- the first question, which was about DD&A rate into '06 and '07. I'd point out there's a -- a lot of moving parts here and that we haven't given guidance for '06 yet, that'll be forthcoming later in the year. But, just from a high-level perspective, you -- our -- our DD&A rate is approaching our projected finding and development cost, so, you know, I wouldn't expect a lot of continued upward pressure on DD&A as we move forward, assuming that we continue to deliver results that are in line with our targets.

We shift it back to Steve here for the rig comment.

Yes, we can talk about our deepwater program. Yes, we have, working with our partners and in -- in where we're operating internationally for the deepwater wells we currently have on the schedule, we do have rigs secured and we feel relatively confident there. We're also making other longer-term arrangements to secure rig slots for the -- for the foreseeable future to continue to drill our deepwater portfolio.

Okay.

And, Ben, this is Larry Nichols. With regard to acquisitions, we're always looking at acquisitions and comparing those acquisitions to buying back our own stock and achieving whichever -- pursuing whichever one produces the best result. While you referred to F&D costs and certainly for the industry they are going up, you should recognize and remember that F&D costs for us have actually been coming down over the last several years and as John said, we expect our F&D cost to -- for this year to be well within the -- the guidance that we've -- we've given, which is a very good and a very competitive number. So I don't think we're so much as driven by the F&D costs as we are looking for opportunities. As we've said in past conference calls, we really think the asset portfolio that we have assembled really fills all the key niches that we want and while we'll continue to look for other opportunities whenever we find them, if we find them, we'll do them. If wedon't, we won't.

Okay, great. Great. Thank you very much.

One thing, Ben, that I -- this is Vince again, I -- I'd add to Larry's comment is that when -- when we buy our own stock back, we're not just by buying prude reserves we're buying contingent resources and -- and unproved resources in acreage that we quantify in the several billion barrel range. So, we think we get a -- get a lot more than just approved barrels.

Sure, so when -- when you look on a per--barrel basis, given so today's stock price, I mean what sort of EV per barrel would you say you're buying back your stock at?

Bill -- .

I don't think it's so much as -- as per barrel as -- as Vince said. We're not just looking at prude producing barrels. We recognize that we think our -- our reserves are conservatively stated in relationship to some of the sellers' reports that we see out there for engineering. We see the upside we have in -- in all the different projects that were itemized in this call, and -- and we think, at least we thought in the last -- the last year and a half that buying our stock is a better buy in essence, with the first 50 million share buyback. We did a $2 billion acquisition and we think the results we achieved from that were better than the results that we've achieved on -- on -- on all of the different matrix of doing other acquisitions that we saw out there in the marketplace at the time.

Okay.

And, Ben, one finally point is, of course, we have a significant marketing midstream business that wouldn't be -- the value of which is not reflected in the barrel count and -- and of course when you look at the opportunities that we have in pursuing right now that the reserve, the prude reserves may not give it an indication of the potential of the Company -- would not give an indication of the potential we see in the Company. So don't forget the midstream business. It's significant.

Sure. All right, great. Thank you very much.

Our next question comes from Ray Deacon of Harris Nesbitt.

Yes, hey, good morning. I had a -- a question about Jack. Are you -- are you actually at your -- have you gone through the main target there and could you just give me some background as far as, you know, this lower tertiary play, what your results have been to date and how encouraged you are about the play going forward?

Yeah, I sure can. This is Steve. To just to answer your first, the first -- the second part of your question first. When you look at our lower tertiary results to date, we feel like we -- we've had some very, very strong results. We have three discoveries to date that we're continuing to move towards commercialization. We're in the process of drilling appraisals on two of the wells. We've already drilled a second appraisal well on the third and in the planning stages for further appraisal and development on that one. These are very high-impact opportunities that we think will bring significant -- have the potential to bring significant reserve and volumes to Devon at relatively competitive costs. We not only participate in these three, but we've leveraged that knowledge and understanding to build an inventory of at least 23 other prospects in the play in the lower tertiary, so we feel like we're well positioned in the play. When you look at the results as it relates to Jack, again, we -- we're continuing to be encouraged by the results. We will be moving towards a production test on both Jack and Cascade in sometime early in 2006 and we think that's a big step towards going towards sanctioning and ultimately the commercial development of those -- of those high-impact prospects. So, we're -- we're very pleased with the lower tertiary results that we're seeing to date and look forward to -- to continued news to move towards this commercial development.

That's great. And -- and just one question on -- on Jackfish. How do you think the economics of Jackfish will compare to the -- the three existing oil sands projects and any preliminary thoughts on the expansion, whether the economics there will be comparable to what we have in the first phase?

Yes, we -- we think the economics at Jackfish will be very competitive. Remember, it's a -- it's a -- it's a long-term project that'll deliver 300 million barrels. we'll produce our first production will start at about 2007, move into 2008 and we'll be producing about 35,000 barrels of oil a day for a very, very long time. 25 years or more. As it relates to the project itself, when we look at the reservoir information in the quality of the reservoir and the characteristics that allow us to apply the SAGD technology, as we look at the other reservoirs that -- that are in the area in the Athabasca area that can utilize the SAGD technology, we see that ours is in the top quartile as far as reservoir characteristics, which we think will translate to top quartile technical performance as it relates to SAGD. So, we -- we think it's going to be a good project. As we look at the expansion, we think we're -- we'll see probably similar reservoir characteristics. As John mentioned, we've done the strat well work. Some of the strat well work to date we're encouraged by those results. We'll continue to drill these stratographic wells and further define additional opportunities in the area. But -- but, overall, we're very -- very pleased with what we've seen. We think we'll have some solid economics relative to the other projects in the area.

And, Ray, it's John. The -- the -- the other thing, in addition to what Steve said about the technical side of it, you might remember, that -- that we -- we got very clean sands here that don't have much depositional shale or any of those negative characteristics and a real important part is where it's located and the access pipeline that we're building which is really going to help in -- in -- in terms of not only deliverability of -- [INAUDIBLE] deliverability the blended product. So, it -- it's located in a good part of the province just from a geographical point of view and can be very competitive from that point of view as well.

Great. That's helpful. Thanks.

Our next question comes from Joe Allman of RBC Capital Markets.

Hey, good morning, everybody.

Morning, Joe.

Could you, I don't think you addressed Nigeria -- offshore Nigeria. Could you talk about what you guys have going in Nigeria and what Shell's results in their Aton (ph) discovery mean for you? And then also, while sticking to West Africa for a second, these two discoveries in EG, could you comment, I know you don't want to comment too much on it, but have they met your expectations? Is there a positive surprise? Can you comment on that as well?

Sure, let me take the last piece first again. Esmerelda and Block D we're both excited about those opportunities. You know, we have expectations of our exploration portfolio overall that it's going to continue over the longer-term to deliver some good high-impact results and some commercial economic projects that'll drive our reserves and our production and Esmerelda fits in that profile. We're continuing -- we got a lot of technical work to do and some work to do to drive it towards commerciality and work with our partnerships and -- and with EG. But again, we're -- we're encouraged by the results.

Block P looks very promising to us. We think it has a lot of upside and a lot of potential. And we're very excited about that opportunity. We have plans to drill two to three follow-up wells in 2006 on Block D and further -- further define that opportunity. And, again, we -- we look forward to some pretty strong results on Block P. We were encouraged with Block P. If you shift to Nigeria, in Nigeria, as you know we have Block 256 and Block 242 that we're focusing on. Block 256, we're continuing to move forward with our plans to drill our second exploratory well. On block 256, our current schedule with a -- with a rig looks like we'll be drilling it very early in 2006 and we look forward to that test. The Incom (ph) discovery to the north that's on the northern edge of our block, obviously we're encouraged with the petroleum system, that indicating the petroleum system is working and so we look forward to -- to the test that we have planned for 256. In addition to the well we'll drill in early January, we also have additional prospects on that block. If you move to 242, we still have plans to -- we're in the process of acquiring and processing our 3D seismic and still have plans to drill that well later in 2006 and -- and things are continuing to progress forward and we're pleased with -- with the way things are going in Nigeria.

Got you. And then in Eastern Oklahoma, these three horizontal wells, did you have better success with the Woodford versus the Kaney or can you comment on that?

Can't comment in too much detail but we had a good success -- good success looking at the -- at the Woodford and when we look at these, these are three wells that are averaging about 2.1 million a day. We have about 70,000 acres in the -- in the play and we think we're able to translate some of the outstanding competencies we have in the Barnett Shales to this opportunity. While it's still relatively early in the play, we're encouraged with -- with the results that we've seen. So, I -- I don't want to comment too much farther beyond that . But -- but the wells look very good and with the economic model we've developed based on those wells, we think we've got a play that can deliver some significant reserves.

And then you start off in your press release, your operation comments with south Texas. Do you folks plan on increasing activity in the acres there or are you pretty happy with what you've got right now? South Texas, Texas Gulf Coast.

Yes to all three. We are -- we are very pleased, obviously, with the Otis Ayers results and the 22 million a day, 100% -- 100% well. That's really high-impact from our focussed onshore exploration. We also have multiple follow-up wells in the area where we have already acquired acreage and continue to look at the area and -- and move forward with our -- our exploration in the tertiary, within that -- within Matagorda.

And lastly, I'd love to get either Larry's comment or John's comments or anybody's comments about what you think's going to be happening going forward with industry consolidation based on what we've seen recently in -- and not necessarily Devon but in the scene general?

Well, that one's fairly simple. The industry been -- has been consolidating for the last 15, 20 years and there's no reason to think that won't continue to happen. When we went public in 1988, we had 400 publicly-traded companies. We're down to a little over 100 now. I don't see any reason that that won't continue.

Excellent. Thanks, everybody.

(Operator Instructions) Our next question comes from Jeff Hayden of Pickering.

Hey, guys, just wonder if you could do a quick run-through of some of the exploration wells we should be watching out for in the deepwater Gulf of Mexico. You mentioned Caterpillar. What else should we be watching for over the next few quarters?

Jeff really over the next couple of quarters, the real deepwater, we -- we've talked about Caterpillar and then the -- the biggest issues coming up for us in the deepwater in -- in 2006 in the first half is going to be the -- the Jack and Cascade and the follow-up testing to those -- to those structures.

Okay. Thanks a lot. Anymore of a focus on exploration in the second half of the year or pretty much '06 just the development focus?

Currently with our -- with our current plans and we're still in the process of finalizing our 2006 plans and budgets and that's why we don't have a lot of information to share with you on it, but we do have another opportunity, our North Sturgess well, which I think we've talked about before, where we're in partnership with -- with Chevron. And it's another myocene test, a deepwater test that we'll see happening in -- in 2006 at least with our current view.

Okay, thanks, guys.

Our next question comes from Dennis Coleman of Goldman Sachs.

Yes. Good morning. A quick question on the -- the debt reduction. Obviously you've done a great job over the last several years of -- of paying down debt. One of the things that you've done is -- is hold cash versus paying down debt. And I'm wondering whether some of that was you wanted to avoid paying a premium and -- and how that might change as we're seeing short interest rates rise and -- and maybe some of these premiums disappearing on some of your short bonds? May you go ahead and -- and call some of these bonds out.

Your, I mean you're right with -- with your comment or your thought on how we approached it. We certainly do look at the -- at the premium and, again, this is Brian Jennings. As we look, really out the next 24 months, we have another, almost billion dollars of debt that will mature. We've got 660 -- 660 million that matures next year and another 400 million that matures in '07. So, right now, I -- again, consistent with what we said before, be out intention to retire those as they mature. Obviously, we're always looking at -- at opportunities in the open market to -- to re -- retire debt. But, you know, we found that the -- that the premiums on the bonds have -- have -- have been not MPV positive transaction trusts to look at.

Okay. Thanks very much.

Our last question comes from Jeff Davies Of Wachovia Securities.

Yes, I was curious what you could share with us on the -- I think you mentioned the Cadillac prospect was unsuccessful, I know aren't -- aren't operator there, but just kind of what total depth got to, whether it was dry or just uncommercial? Obviously high heat pressure down there, if there's anything other than that, kind of lessons learned from -- from that drilling?

You know, as this -- this is Vince. On these high-profile wells, the -- the protocol is generally for the -- the operator to leave the disclosure on that, and I think we ought to -- we ought to leave that disclo -- to -- to the operator. I wouldn't remind you to that we -- we had a 10% interest in that well, so it was kind of a science experiment for us.

Fair enough. Let me ask you -- heard a couple of operators talking about acquiring some lease hold in Permian Basin with the Barnett Shale being extended into there, is that an area that you're taking a look at?

Yes, absolutely. We're continuing to look across our business for opportunities and looking at acreage positions in shale plays and in other -- in other repeatable plays that we may see across the -- across the business. I will tell you that year-to-date, we've acquired about 250,000 acres of acreage across the -- across our asset base principally in -- in North America on shore. In that light, so we're continuing to be active looking at those opportunities and -- and acquiring positions and -- and then we go in and apply our -- our technology and -- and test the opportunity as we have in the Arkoma.

Yes. One last one if I could. Just the -- it was non-cash charge, obviously, but with the exchangeable convert Chevron shares, if there's any motivation, did it all to kind of clean that up off the balance sheet?

Not at the present time. We get a lot of questions about that security. It matures in 2008, and I imagine we'll look at it at that point in time.

Thank you.

I've got straight up 12:00 eastern. So we're go -- going to -- to cut off the Q&A at this point. Larry, do you have closing remarks?

Sure, just to recraft the -- the third quarter, Devon reported record earnings and cash flow. We continued our long-term strategy to optimize per-share of growth by deploying excess cash flow to high-return capital projects, debt repayments, stock repurchases, increasing dividends and capital reinvestment. We demonstrated success with our long-term so -- exploration programs including successful delineation of wells of our high-impact Cascade and Jack oil discovery, oil tertiary discoveries, as well as the discoveries in block P and B and Equatorial Guinea. We're continuing to build our inventory with -- of shorter cycle-time gas-related growth projects in North America. We're drilling in noth -- north Louisiana Bossier and Woodford Cheney shelf play in Oklahoma and finally in the Barnett Shale the success of our horizontal infield program is beginning another phase of drilling and production growth for this world-class asset. In summary, we're very pleased with the quarter and we think we're very well positioned for the remainder of the year. Thanks for joining us and this concludes our call.