德文能源 (DVN) 2006 Q3 法說會逐字稿

Welcome to the Devon Energy Corporation third-quarter earnings conference call.

[OPERATOR INSTRUCTIONS]

Now I would like to turn the call over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Good morning to everyone, and welcome to Devon's third quarter 2006 conference call and webcast. As usual, I'll cover a few compliance items, and then at that point, I'll turn the call over to our Chairman and CEO, Larry Nichols. Larry will have some opening remarks, and then our President, John Richels, will review the quarter's operating highlights. Brian Jennings, our CFO, will then cover the financial highlights and provide updated guidance for the remainder of the year. Following Brian's comments, we'll open the call to questions.

As is our practice, we will limit this call to about an hour, so if we don't get to your question, please feel free to phone us later in the day. A replay of this call will be available -- we'll post this later today. It'll be available through a link on our home page. And in addition, we're starting a new practice with today's call. We're going to provide replays of our quarterly conference calls on our website that'll be available for download to your iPod or other MP3 player.

In keeping with our practice, we will file a Form 8K later today which will provide the updated 2006 guidance. This update will modify only those few forecasted items that we believe will be out of our previous guidance ranges for the year, and Brian will cover most of these in his section. We will be e-mailing that 8-K to those of you that are on our contact list once the filing is confirmed with the SEC. Our updated guidance will also be posted to our website.

In today's call, we will talk about our plans, forecasts, and estimates of future operating results. These statements are considered forward-looking statements under U.S. securities law, and while we always strive to provide you the very best estimates possible, there are a number of factors that could cause our actual results to differ from the estimates we provide. We encourage you to review the discussion of risk factors that we provide along with our forecast and our SEC filings.

One final compliance item, that is that we will make reference today to certain non-GAAP performance measures. When we use these measures, we're required to provide certain related disclosures, and those disclosures are available on our website currently for your review. At this point, I will turn the call over to Larry.

Thanks, Vince, and good morning, everyone. We will begin with a recap of our third quarter results.

From a reported results perspective, the third quarter was another very solid one for Devon. We grew production on both a year-over-year basis, and on a sequential quarter basis. While we realized lower natural gas prices for the quarter and continued to be faced with upward cost pressures that are typical in the industry at this time, net earnings for the quarter exceeded $700 million and earnings per share were $1.57, or when adjustments for items that are generally excluded from analyst estimates, earnings were $1.66 per share. That is $0.14 per share, or $0.09 above the FirstCall average.

You may recall that last year's third quarter gas prices were boasted by an active hurricane season in the Gulf, so while natural gas prices declined in October of this year, they did not fall as far as one might have anticipated based on storage levels and the lack of weather-related demand. For the November bid [INAUDIBLE], prices have recovered and Henry gas prices are once again above $7 per MCF. Cash flow before balance sheet changes reached 1.5 billion for the third quarter, about 8% above FirstCall.

Along with solid third quarter financial results, we also achieved several important milestones in our Deepwater Gulf of Mexico exploration program. We've announced these earlier. Most notable of the milestones was the successful production test of the Jack 2 well in the lower tertiary trend. The Jack test confirmed the potential for commercial development in Deepwater lower tertiary reservoirs. When the Jack results were announced, much of the world awakened to the exciting potential of the lower tertiary as an important new source of oil for the United States. Pundits talked about the biggest trend discovery since Prudhoe Bay.

Many of you who have followed Devon for some time were likely not surprised. We have expressed cautious optimism about the resource potential for the lower tertiary play since we participated in the gas Cascade discovery back in 2002. Cascade was one of the industry's first lower tertiary discoveries, and as we announced in August, is expected to be one of the first to be commercially developed. Leading up to the Cascade discovery, we had targeted the Deepwater Gulf as a long-term growth area for Devon.

Encouraged by Cascade, we set out to assemble a premier set of Deepwater assets that could position Devon as a leader in the lower tertiary trend. We assembled our position through joint ventures, through acquisitions, and federal lease sales. The efforts led to St. Malo and Jack discoveries in 2003 and 2004. In the third quarter of this year, we announced what we believed to be the largest discovery to date at Kaskida. We currently hold 273 blocks in the lower tertiary, and have identified 19 additional prospects to date. This provides a potential over time to more than double the size of Devon's reservoir base.

I mentioned that natural gas prices were down year-over-year in the third quarter, and fourth quarter gas prices were well below the all-times high we saw last year. The recent relative softness in natural gas prices has generated a lot of questions about what Devon is doing in response. Are we releasing rigs? Are we cutting back on drilling? Et cetera. I will remind you that we make capital spending decisions based on long-term economics, including both expected cost and a long-term view of commodity prices. Our long-term range outlook for oil and gas supply and demand fundamentals remain very positive.

We're currently in the process of planning our 2007 Capital Program, and expect to present the budget to our Board of Directors for approval in early December. While the budget is still very much a work in progress, early indications are that we will reduce activity levels in the conventional gas business in Canada. We have a very large inventory of high quality assets in Canada, and have had good performance in the past. However, we have seen significant upward pressure on costs in Canada, resulting from an overheated regional industry. In addition, continued erosion of U.S. dollar has squeezed margins further. As a result of these factors, western Canada is currently the most expensive basin in which we operate. We will not invest in low margin projects just to chase production volumes. Rather, we'll continue to be focused on returns.

Lower activity levels have resulted in a decline in Canadian production in 2006, and we would expect further declines in 2007. When the Canadian market corrects or the U.S. dollar strengthens, and project economics improve, we will once again begin to ramp up the conventional program back in Canada.

One advantage of our larger diverse property base is our ability to reallocate capital. We are continuing to be active in Canada in both our SAGD heavy oil projects as well as our other oil projects in the Lloydminster area. We believe these projects continue to deliver attractive risk adjusted returns in the present environment.

We also expect to step up our activity levels in several of our U.S. onshore areas in 2007. These include the Barnett Shale, the Woodford Shale, and our tight gas plays in east Texas. John Richels will elaborate on this further. Once we have finalized our 2007 capital budget, we will update our production guidance accordingly. Now I will turn the call over to John Richels. John.

Thanks, Larry, and good morning, everyone. Let's start with a look at our 2006 capital spending. In August, we updated our 2006 full-year forecast of exploration and development capital to an estimated 4.7 to $4.9 billion. During the third quarter, our exploration and development CapEx totaled $1.2 billion, bringing year-to-date E&P capital expenditures to about $3.6 billion. We expect to finish the year within the capital range provided in our August forecast. At the end of the third quarter, we had 127 rigs running Company-wide, with 67 rigs drilling Devon operated wells. We drilled 740 wells Company-wide during the quarter; 36 were exploration wells, of which 89% were successful. The remaining 704 wells were development wells, and about 99% of those wells were successful, giving us an overall success rate for the quarter of roughly 99%.

Moving now to quarterly operations highlights, I'll begin with the offshore Gulf of Mexico. Larry recapped the milestones that we achieved in the Deepwater lower tertiary trend, and I have some additional comments about future plans for those projects. First, at Kaskida, which is the most recent of our four lower tertiary discoveries, we plan to side track the well later this year to obtain additional technical information. Then in 2007, we plan to drill an appraisal well in the second half of the year to better define the size of the reservoir. Kaskida is operated by BP, and is located on Keathley Canyon block 292. I'll remind you, Devon has a 20% working interest in that prospect.

At Cascade, this is the project in the Walker Ridge area where Devon and Petrobras bought out BHP's interests in the third quarter. Our upcoming goal is to secure MMS approval for our Deepwater operating plan. The plan calls for the drilling of two additional wells in 2008 or 2009, a second side track in the #2 well, and a new well into an untested fault block. Our technical teams continue to evaluate the development options, and we hope to sanction the project for development in 2007. First production from two wells at Cascade is anticipated in late 2009. Devon has a 50% working interest in the four-block Cascade unit.

At Jack, also in the Walker Ridge Deepwater lease area, we and our co-owners are evaluating various development options following the successful production test of the Jack 2 well. The next planned activity at Jack is to drill a further delineation well currently scheduled for the second half of 2007. This Jack 3 well could potentially be drilled with the Ocean Endeavor Deepwater rig that Devon has under long-term contract. In addition to the Jack 3 well, the partners may drill a second delineation well at St. Malo in late 2007. Jack and St. Malo could potentially be developed jointly, and the information from the two wells that we are drilling in 2007 could help determine the facility's design. I'll just remind you that Devon has a 25% working interest in Jack, and a 22.5% working interest in St. Malo.

The Ocean Endeavor rig that I just mentioned is scheduled for delivery in the second quarter of next year. We also announced a couple of weeks ago that we had a long-term contract on a second Deepwater rig for the Gulf of Mexico to be delivered in 2008. The second rig is the West Sirius rig being constructed by Seadrill. Seadrill is a Norwegian company with $5.5 billion in assets and a very large offshore fleet. The company's vessels are at work in the North Sea, Australia, Thailand, Malaysia, and West Africa, and they expect to grow their presence in the Gulf of Mexico.

The Ocean Endeavor and the West Sirius rigs are both Generation 5 rigs that can drill in water depths up to 10,000 feet, and are important elements of our capacity to execute our plans in the lower tertiary trend. With the added flexibility of having two Deepwater rigs dedicated to Devon projects, we'll be better equipped to continue the valuation of our large inventory of Miocene and lower tertiary exploratory prospects, and any subsequent appraisal and development. We plan to drill between 6 and 9 deepwater wells each year for the next several years, with the majority operated by Devon. In our Deepwater Miocene program, we're currently drilling below 23,500 feet on the Caterpillar prospect which was spud in late June. Caterpillar is a 28,000 foot subsalt Miocene test on Mississippi Canyon 782. Devon has a 25% working interest in this Chevron-operated prospect.

Also drilling to a Miocene objective is our Mission Deep prospect located on Green Canyon 955. Mission Deep is a 26,500-foot subsalt test in about 6,500 feet of water. The Anadarko-operated well is currently drilling below 19,500 feet. Both Caterpillar and Mission Deep should conclude before year-end, and Devon has a 50% working interest in Mission Deep.

In the eastern Gulf of Mexico in the Atwater Valley area, the two planned producing wells in the Merganser field have been drilled, and installation of subsea equipment will begin this quarter. Construction of the Independence Hub is proceeding on schedule. Installation of the Hub is expected in the first quarter of 2007, with first production mid-2007. Merganser will produce into the Independence Hub at about 50 million cubic feet of natural gas per day net to our 50% working interest.

Turning now to our onshore operations. In the Barnett Shale field in north Texas, we currently have 25 operated rigs running. Eight of these are high-efficiency drilling rigs, and we expect another four to be delivered between now and the end of the year. Twelve of the 25 rigs currently working on the Barnett are working in the core area, and 13 rigs are drilling outside the core, seven of those in Johnson County. We still expect to have 30 Devon operated rigs working in the Barnett by year-end. We continue to aggressively drill 20-acre in-fill wells on our core area acreage, and through the end of the third quarter, we had drilled a total of 72 in-fill wells; 53 of the in-fill wells drilled to-date are horizontals, and 39 of those have now been tied in.

Initial per well production on the 39 producing horizontal wells has averaged 2 million cubic feet per day. These initial production rates are better than the 1.7 million cubic feet per day that we had originally projected when we began the in-fill program back in May of 2005. Outside the core area, we also continue to see very solid results. In the third quarter, we brought 36 new horizontal wells online in Johnson County at an average initial 30-day production rate of 2 million cubic feet per day. While we had some infrastructure delays early in the year, we're steadily reducing well connection backlogs as we build out the gathering systems. Also we've completed Phase I of our west Johnson County gas plant, and it is online. Phase I has a capacity of 30 million cubic feet of natural gas per day, and we expect to have all phases fully operational in the third quarter of next year, with a total throughput capacity of 160 million cubic feet of gas per day.

In Parker County, we have begun development of our 120,000 net acre position. To date, we've drilled 64 Parker County wells, and have brought 45 wells on to production. The initial rate for the wells that we brought on in the third quarter has averaged 1.8 million cubic feet equivalent per day. So overall, we completed a total of 141 Barnett wells in the third quarter, 32 in the core area, and 109 outside the core. At the end of September, we had 56 Barnett Shale wells awaiting connection to the producing grid down from 68 at the end of the second quarter. Devon's net Barnett Shale production averaged a record 647 million cubic feet of gas equivalent per day in the third quarter, with about 20% of that coming from outside the core. We exited September producing about 660 million cubic feet per day in the Barnett net to Devon's interest, and we remain confident that we'll meet our 2006 exit rate goal of roughly 700 million cubic feet equivalent per day net to Devon.

In the Woodford Shale in eastern Oklahoma, we continue to see very encouraging results. We ran an average of three operated rigs throughout the third quarter, and brought a total of six operated wells online, bringing the total Devon operated wells in the Woodford to 19. Initial production rates for the Woodford wells that we have drilled are ranging from 2 million to 4 million cubic feet equivalent per day.

Moving to the Rockies, in the Washakie Basin in Wyoming, we were able to keep two rigs running through the restricted drilling season this year. Once the wildlife restrictions were lifted, we ramped our activity to six rigs at a time and drilled a total of 32 wells during the third quarter. We plan to drill an additional 33 wells by year-end. Several projects throughout the basin are under way to increase the natural gas gathering system capacity, and those projects are expected to be completed in 2007. Devon's net Washakie production is running about 95 million cubic feet of natural gas per day.

Moving now to east Texas where we have 142,000 acres in the Groesbeck area, you may recall from last quarter the success of our horizontal drilling program in the Nan-Su-Gail field. This program continues to deliver impressive results. During the third quarter, we completed our third horizontal well in the play this year. The 100% working interest Crenshaw 14 H well had an initial production rate of 32 million cubic feet per day, and has produced roughly 1.3 Bcf of gas since early August. We're attempting to extend the play concept by drilling one well in each of three neighboring fields. These high-working interest wells are in various stages of drilling and completion, and we expect to have those results for you next quarter.

If we can extend our success of the Nan-Su-Gail field to these nearby fields, we could have as many as 200 additional horizontal locations to drill in the Groesbeck area. Because of our horizontal drilling success at Groesbeck, we elected to test the same concept further to the Northeast at Carthage. During the third quarter, we drilled and completed our first horizontal Cotton Valley well in the south Carthage area. The Haygood 11 H well averaged 9 million cubic feet per day for the first 30 days of production. This is about 5.5 times that of a vertical well, but it was drilled at less than 3 times the cost, providing excellent economics. We plan to drill two additional horizontal wells in the area during the fourth quarter. In all, we could have as many as 65 to 70 additional horizontal locations in south Carthage and surrounding fields.

Also at Carthage, we remain active with our vertical Cotton Valley drilling program where we're currently running six rigs. During the third quarter, we drilled 28 wells including two successful 20-acre in-fill wells. In September, we drilled the 68th well of our 104-well program planned for the year. Third quarter net production from Carthage averaged about 241 million cubic feet of gas equivalent per day, which is up 15% from the third quarter of 2005.

Finally in the U.S., in north Louisiana in our Bossier exploration play, we're still trying to establish commercial success in new prospect areas. In the second quarter, we completed the Warehouser 13-1 well in the East Vernon field, and we recently reached a total depth on our third exploration well in East Vernon, the Norrad 18-1. This well is scheduled for completion and testing about the middle of November. East Vernon is the third north Louisiana Bossier prospect area that we have tested with exploratory wells. In each of these areas, we encountered thick, gas-bearing Bossier sands. We're currently in the process of conducting an evaluation and appraisal of the results in an effort to commercialize these discoveries. Given the size of these prospects, the potential on our 200,000 net acres in the north Louisiana Bossier trend is certainly a target worth pursuing.

Moving now to Canada, in our Lloydminster oil play in Alberta, we drilled 137 Devon-operated wells in the third quarter. Also in the Lloydminster area, we're adding 10,000 barrels per day of processing capacity to our Manatokan plant, with start up expected in March 2007. This incremental capacity will handle our growing oil volumes from the Iron River area. At our Jackfish thermal heavy oil project in eastern Alberta, facilities construction and drilling continue as planned, and within 10% of our original budget. We expect to begin steam injection at Jackfish in the second quarter of 2007, leading the full field production of 35,000 barrels per day in late 2008. Just to remind you that Devon has a 100% working interest in that project. We mentioned in the past the potential for expanding our SAGD position in the Jackfish area. And in that regard, on September 29th, we submitted an application for regulatory approval of Jackfish 2, a project that would add an additional 35,000 barrels per day of production, and about 300 million additional barrels of reserves. Engineering and budgeting work is under way, and we expect to make a decision on whether to proceed with the project in 2007.

Finally, moving beyond North America. In Brazil, our Polvo oil project on offshore block BMC8 is on schedule for first production next year. We expect to begin development drilling off the platform in late February. While we have described Polvo as a 50 million barrel resource, we believe there is considerable additional potential on the block. We expect to begin drilling the first of three exploration wells at BMC8 in November in hopes of expanding the limits of the field.

Moving across the Atlantic to west Africa where the operations offshore Equatorial Guinea, field-wide production at Zafiro is running about 235,000 barrels of oil per day with Devon's net share running about 29,000 barrels per day. Also in Equatorial Guinea, due to rig delays, additional exploratory drilling adjacent to our 2005 Venus discovery on block P has been pushed into the fourth quarter. We now plan to initiate our three-well drilling program in the next few weeks.

In the south China Sea, which is home to our successful Panyu field, we acquired over 350 square miles of 3D seismic on the Devon-operated block 4205. Our lease is adjacent to the Husky block that has generated so much excitement, with the operator having recently announced a 4 to 6 TCF gas discovery. China's burgeoning ecomony is expanding the market for domestic natural gas, so we're quite eager to evaluate this 3D data, with a goal of drilling an exploratory well in late 2007 or early 2008. And finally, in Azerbaijan, where Devon has a 5.6% interest in the ACG oil field, gross field production has climbed to more than 550,000 barrels of oil per day. We expect to reach full payout of our carried interest arrangements before year end. Devon's share of ACG production should average roughly 30,000 barrels per day in 2007.

That concludes our operations update, and I'll now turn the call over to Brian to review our financial results. Brian.

Thanks, John. I will begin today by reviewing our third quarter financial results and, where necessary, update you on our outlook for the fourth quarter. In most areas, you'll find no change in our existing fourth quarter guidance. As Vince mentioned in his opening remarks, we are issuing an 8-K today that will provide detail on our updated forecast. Let's begin with production.

Our third quarter production was in line with our guidance, as we produced 55.4 million barrels of oil equivalent, or approximately 602,000 barrels equivalent per day. That is a 4% increase over the 578,000 barrels per day we reported in the second quarter. When you examine our production performance in greater detail, you will find that we experienced strong sequential quarter growth in most of our producing regions. Specifically, our U.S. on-shore volumes grew by over 15,000 equivalent barrels per day, or 5% when you compared that to our second quarter results. The driver of this 5% quarter-over-quarter increase was split between continued organic growth and production from our newly acquired Chief assets.

In the Gulf of Mexico, production increased by 7% over the second quarter, as we continued to restore natural gas production that was interrupted by last year's hurricanes. Because of the margin compression in Canada that Larry discussed, we had planned for lower 2006 drilling activity in Canada. This reduction in drilling activity led to a sequential quarter decline in Canadian production of about 4,000 equivalent barrels per day.

Looking ahead to the fourth quarter, we expect our production growth to continue. Led by the ramp-up of production in the Barnett Shale, our core U.S. onshore assets will continue to deliver strong growth, and our international performance will benefit from the payout of ACG. In total, as we discussed in our second quarter call, we expect our fourth quarter production to be between 58 and 59 million barrels of oil equivalent. That's about a 6% increase over our third quarter results. Importantly, we remain on track to hit our full year production target of 218 million equivalent barrels.

Shifting to price realizations, in the third quarter, the WTI benchmark oil price averaged $70.62 per barrel. This was 12% higher than the same period a year ago. Realizations in all our producing regions exceeded or were at the top end of our guidance ranges as regional differentials to WTI narrowed significantly. As a result, in the quarter, our Company-wide realized price was a robust 91% of WTI, 1 percentage point greater than last quarter. Due to our unhedged position and the higher price environment, our third quarter realized oil price increased by nearly 50% when compared to the same period last year to $64.17 per barrel.

On the natural gas side, the benchmark Henry Hub Index averaged $6.58 per MCF for the third quarter. This was 23% below the Henry Hub Index price during last year's third quarter. Company-wide price realizations were generally in line with our guidance at approximately 85% of the Henry Hub Index. For the fourth quarter, we now expect our natural gas price realizations to approximate 98% of the Henry Hub Index for the Gulf, 75% of the Index for the U.S. onshore, and 85% of the Index in Canada. In addition to strong upstream performance in the quarter, Devon's marketing and mid-stream operations once again delivered impressive results. Marketing and midstream operating profit for the third quarter totaled $114 million. That's a $5 million improvement over the second quarter, and $3 million better than last year's third quarter. This performance was driven primarily by higher Barnett Shale volumes.

Based upon our performance for the first nine months, and our outlook for the fourth quarter, we are again increasing our 2006 operating profit forecast. We now expect our full year 2006 marketing and mid-stream operating profit to come in between 445 and $465 million. This is a $25 million increase over our previous full year guidance, and applies a fourth quarter operating profit target of between 100 and $120 million.

Turning to expenses, third quarter lease operating expenses were right in line with our guidance, coming in at $382 million or $6.91 per equivalent barrel. Our costs remain on a unit of production basis essentially flat with the first and second quarters of 2006, despite continued cost pressures across the industry. Looking ahead, we expect our full year lease operating expense to come in at the top end of our guidance range of 1.4 to $1.5 billion. Our reported third quarter DD&A expense for oil and gas properties came in at $10.91 per barrel for the quarter. That's about $0.11 per barrel above the high-end of the quarterly guidance we provided in our second quarter conference call. Despite the higher-than-anticipated third quarter rate, we remain comfortable with our full year DD&A guidance of $10.30 to $10.70 per barrel.

G&A expense for the third quarter came in at $104 million. That's about $4 million above our guidance. That expense included approximately $16 million of predominantly non-cash expense related to stock-based compensation. We do continue to see upward pressure on personnel expenses. Looking ahead, we now expect our G&A expense to come in between 110 and $120 million in the fourth quarter.

Interest expense for the third quarter was $112 million. This was approximately $5 million lower than the mid-point of our guidance range. This positive variance is primarily due to lower-than-forecasted interest expense on our floating rate exposure. When you compare this quarter's expense to the second quarter, you will notice that interest expense increased by just over $10 million. This quarter-over-quarter increase results from the commercial paper borrowings that funded a portion of the Chief acquisition. Looking ahead to the fourth quarter, we anticipate interest expense to range between 105 and $115 million.

The next expense item I'll cover is the reduction and carrying value of oil and gas properties. In the third quarter, we recorded a $51 million write down attributable to two of our small international positions. The majority of this non-cash impairment charge was related to unsuccessful exploration activities in Egypt.

Moving to income tax expense. Income tax expense for the quarter came in at 31% of pre-tax income. After backing out the impact of items that are generally excluded from analyst estimates, our adjusted income tax rate would have been between 32 -- would have been 32%, consisting of a 24% current tax rate and an 8% deferred tax rate. In today's earnings release, we have provided a table that reconciles the effects of items that are usually excluded from analyst estimates. Through the first nine months of 2006, our adjusted tax rate is 35%, with 23% current and 12% deferred. This is near the mid-point of our full year guidance.

Looking at the bottom line, net earnings for the quarter totaled $705 million, or $1.57 per diluted share. Adjusting for items that are generally excluded from analyst estimates, diluted earnings were $1.66 per share for the quarter, about $0.14 better than the FirstCall mean.

Before we open up the call to Q&A, I want to conclude with a quick financial -- with a quick review of our financial position. In the third quarter, our cash flow before balance sheet changes totaled 1.5 billion. Looking at the first nine months of the year, cash flow before balance sheet changes rose to 4.6 billion. That's about 600 million greater than the first three quarters of last year.

This strong year-to-date cash flow has enabled us to fund 4.2 billion of Capital Investments, leaving us with 400 million of free cash flow before the Chief acquisition. During the third quarter, we retired $678 million of maturing debt, reducing our September 30th net debt balance to just under 5.2 billion. Our lower net debt balance at the end of the quarter, combined with the impact of our strong third-quarter earnings, drove our net debt to capitalization ratio down to 23% at quarter end.

Looking ahead, we expect this trend to continue in the fourth quarter as we expect our net debt to capitalization to approach 20% by year end. Going forward, we expect to utilize free cash flow to repay short-term borrowings and, when appropriate, resume repurchasing stock. With that, I'm going to turn the call back over to Vince to open it up for Q&A.

Thanks, Brian. Operator, we're ready to take the first question.

[OPERATOR INSTRUCTIONS.] Our first question comes from Tom Gardner of Simmons & Company.

Good morning, guys. Larry, one major oil company who partners with you recently stated they believe the lower tertiary will deliver returns of 25% at $55 oil. Do you agree with them, and what are the potential development risks that might keep you all from realizing this potential?

It is pretty early to start forecasting about what returns are going to be. We got billions of dollars to spend out there. Steve Hadden, do you want to comment on that at all?

Larry, I'll just comment on it. Generally, when we look at the lower tertiary, we are still looking at development options as it relates to Jack. I think that's perhaps what you're referencing. We do think, roughly you can see development costs on a full development basis. It can be in a $3 billion range, but that would include a full field development with wells, and, of course, the number of wells has not been determined because we're still doing a lot of reservoir work to optimized the development.

Also, that beings said, all development options are still being looked at including an FPSO option, or an option with a full field development with a semisubmersible or joint development with Jack and St. Malo. It is a little early to get into those ranges. Our initial estimates showed relatively strong returns, so we're not disappointed by that fact at all.

Thank you. That's helpful. Do you have an update for the development plans that Cascade, particularly with respect to the MMS approval of an FPSO in the Gulf?

Perhaps I'll just tell you that we're moving forward with Petro Brass. They're our 50% partner and the operator. We submitted a Deepwater operating plan to MMS, and expect to hear back from them in the relatively short time frame, hopefully sometimes perhaps this month. And we really don't anticipate any major problems with the approval of that development plan including an FPSO. And we're just looking forward to that approval when it occurs.

Great. Just one question and I will let someone else hop on here. Just could you discuss your Groesbeck area, horizontal Cotton Valley success? Is what you're doing a game changer for the Cotton Valley?

We're very excited about it. We have a great position in Groesbeck. We have multiple fields in the area. And what we're basically looking at are areas of the Bossier, the Cotton Valley Sand, the Cotton Valley line, in those areas. We have drilled a couple of horizontal wells with some very, very strong rates. You've seen the one we talked about in the script was over 30 million a day. This is delivering great returns relative to the investment that we put in, and really generate a lot of excitement for us internally.

We have an additional three wells that are currently inline to go through fracture, and we'll fracture those wells relatively early in this quarter. And those wells cover different fields including not just Nan-Su-Gail where we had the first well that we talked about this past quarter, but also up in Due and Personville and I think there's another one in the Oakfield. But we're testing that horizontal results in a broad area in the Groesbeck area, and I think as we mentioned in the call, we think we have at least 200 potential locations if this success continues. And so we're very excited about these results. These are horizontal wells with a completion technique that involves multiple fracs of five or six different stages, and we're getting very good results from those and a great economic return.

Thank you, gentlemen.

Our next question comes from Arjun Murti from Goldman Sachs.

Thank you. My apologies if I missed it in John Richels' remarks, but you alluded to Mission Deep and Caterpillar's drilling, and I believe you gave the appraisal plans for the various lower tertiary wells. Do you expect to spud any new exploration wells beyond Mission Deep and Caterpillar before year-end, or are we looking more at an '07 program?

No, in the Gulf of Mexico, I don't think we anticipate any additional spuds on exploratory wells in the fourth quarter.

1Q you think then, or are we looking at sometime mid-year before you start cranking up the exploration program?

We're still looking at our budget. I think you'll see us maybe, perhaps sometime in the first quarter, certainly by the second quarter you'll see a spud another exploration well in the Gulf.

Okay. And just wanted to follow up on I think Larry's comments regarding the preliminary view of capital spending. Clear that Canadian drilling is coming down. Just wanted to confirm that's gas drilling as opposed to the Iron River area, and then I think you also alluded to some of the onshore results doing better. I presume with the reduction in Canadian drilling, we could get some commenserate increase in U.S. onshore activity?

Arjun, this is Vince. We're not going to prejudge the budgeting and and portfolio managing process. The one early indication we have is that we will continue suppressed level of spending in Canada and that production will be down. We'll have to complete the process and get a budget approved before we speak to the overall forecast and whether that will be up or down going forward.

Okay. Just a final related point. Obviously depends on commodity prices, but to the extent you have free cash flow, how much are you thinking about stock buyback for next year?

Arjun, this is Brian. Right now, we've got some CP, commercial paper borrowings outstanding, and as we discussed publicly, our intention to take our free cash flow and reduce our leverage. I think it's obviously good for our business, good for our shareholders. It provides us with a lot of flexibility.

Beyond that, we'd have to look at just the amount of cash flow balanced against our capital budgets, which you had just discussed some of the deepwater drilling activities we have going forward, expanded onshore operations. So we always like to put money into our business first and foremost. Then we look at debt retirement and and then, obviously, repurchases are still on the horizon as are dividends, too. That's generally the order which we approach the spending of those free cash flows.

That's great. Thank you.

I would just like to add in Canada it is entirely driven by the cost structure, the quality of oil and gas prospects themselves have done quite as well. It is just the cost structure and the U.S. dollar/Canadian dollar exchange rate. And I think as we and other companies respond to that, those costs will come down, and we'll return to Canada.

Our next question comes from Brian Tusma of J.P. Morgan.

Good morning, guys. My questions were on the lower tertiary play, your wells at Jack and St. Malo. Are they looking primarily to kind of diliniate the structure there, or are you looking more about the continuing of the reservoir properties? Or what's the point of these wells?

That is actually a good question. We have a couple of wells both on St. Malo and on Jack that we could anticipate drilling next year. Relative to Jack specifically, we gathered a lot of information over this year, and we're working through that with our partners on our project teams and trying to work through where we are relative to commercial determination. You heard us talk a little bit earlier about the producing configurations we may use there.

We're working through a lot of reservoir data to look at some optimum designs. There may be a need to go in and drill just an additional appraisal well simply to confirm the aerial extent of the reservoir, and of course, we'll get a look at reservoir quality even out in those other extents. We haven't come to a final decision to absolutely need to drill the appraisal well. But we're working through the options now with the partnership.

Okay. Are you guys, or are you guys personally,or are you guys aware of anyone else may being doing any flow tests, additional flow tests in the lower tertiary play.

I don't know of any personally.

Okay. And then on these east Texas horizontals, which formation exactly are these horizontals? And Nan-Su-Gail going into?

Nan-Su-Gail it's the Bossier. It's the Bossier formation. We also see the potential and we're going to test the possession as you come up a bit in the geologic column in the Cotton Valley. But specifically the wells we reported onto date I believe have all been in the Bossier.

Are these going to add new reserves, or just a mor efficient way to recover? Existing reserve?

The answer is they're going to add new reserves in a way that's much more efficient because of the ratio between the investment cost versus the multiples in production and reserves we're getting are very favorable from an economic return standpoint. So we're going to get new reserves, but we're going to get them in a much more efficient way, economically efficient way.

Were the previous vertical wells, we they going down to the Bossier?

Yeah, we produced the Bossier before in those fields.

Okay. Finally, my last question was in west Africa can you go through real quick again what your drilling plans are there, like over the next six months, and what you are looking for out of your Venus delineation wells?

If we look at the drilling plans we have on the slate, we have a plan to drill block P, and that rig will be there this month, and we'll begin with a series of three wells. What we are looking at is we had a discovery there on block P that was about 115 feet of pay. It is channelized complex, so we're looking at an appraisal well for the first well to confirm the extent of that channelized area.

We also have another follow-on well, as a matter of fact, two follow-on wells that are a bit more risky but would expand the development area on that block, would expand the potential on that block. We'll start drilling those wells in this quarter, and finish that drilling in the first quarter of next year and look forward to those results.

We also have later in 2007, in the late first/early second quarter, we have a couple of slots planned where we will drill wells on our block 256 and on block 242. The block 242 will be the first well on that block where we've obtained a 3D seismic on 242. We'll also be drilling a block 256, and that's going to be the third well on that block. Those two blocks are both in Nigeria.

That's great, guys.

Our next question comes from David Heikkinen of Pickering Energy.

Good morning. Just a quick question on the Woodford. Your 2 to 4 million a day wells, are those three frac stages? I've heard of some five frac stage wells delivering much better results. Do you have any comments on that?

No, I don't know the specific number of stages in those fracs. We've been working -- I think as you heard, we've drilled maybe a total of 19 operated wells there, so we feel like we zeroed in on the frac design there.

I don't know the specific number of stages there. We're continuing to work on some of the cost components to continually improve the return there. We're pretty pleased with the results of the last few wells, and we've picked up an additional rig and will continue to accelerate into that development.

Have you seen any of the rates in the 6 and 10 million a day rates that Newfield just talked about, say at Merrill?

I don't know that we've seen any, and we need to be a little bit careful here because when you talk about some of these rates, sometimes we don't get apples-to-apples. When we talk about our IP's, we generally measure those in about a sustained flow period, in some cases as long as about 30 days. And not necessarily in an instantaneous rate. So we haven't seen any 30-day wells to my knowledge that have produced 10 million a day up in that range. We are seeing some that are up in the 4-plus range. Some of the instantaneous rates may get higher than that. But I'd have to go back and look at the different testing methods.

Okay. That's it. Thanks a lot, guys.

Our next question is from Anna Stromberg of Excess Capital Market.

Hi. Can you hear me well?

Yes.

Yes.

Great. I have a quick question. There is at least 25 -- well, the Dominion amounts they have some assets for sale, and also some Anadarko assets 5 billion up for sale. Are you foreseeing yourself being interested in any of the assets available currently on the market? And along with that, how important are your current ratings to you?

There are assets on the market including the Dominion assets. What is our view on M&A, and then, finally, I think, Anna, the question was how important are our ratings.

Correct.

And I assume you mean credit ratings?

Credit ratings to you, and how far are you willing to go to -- how far are you willing to leverage yourself in order to acquire the assets that you think might be useful to you in the future?

I will let Larry talk about the M&A question and our thoughts there, and I will come back on the rating question, Anna.

Your question was a little garbled there at the start. On the M&A, we're aware that Dominion is going to sell some or all of their assets, and our approach to that will be no different than it has been to all other things we've looked at over the last three or four years, really the last three and a half years since Ocean. We're very happy with the asset package that we have now.

As you can see from the results of this quarter, it is delivering good production growth across the board. We're very happy with the results. If we happen to see anything like we did earlier this year with the chief assets where we can add something incrementally to an area that we're already in, and can do it in attractive rate, we will. If we don't, we won't.

We don't really see, as I said, any particular -- we're pleased with the balance between exploration and exploitation drilling, the balance between oil and gas, the ability to shift capital dollars between projects that are temporarily not working, like in Canada, because of cost structures to others that are working, like the Barnett Shale in east Texas. We don't really any see compelling need to change our portfolio. Brian, do you want to handle the rating?

On the rating front, we're obviously a triple B, BWA 2 rated credit with positive outlook there. That provides us with a great deal of flexibility to be at that credit rating. As I look back over the past several years, when we have done large transactions and have used a lot of cash, we maintained that rating, worked very hard to maintain that rating. And I think going forward, it certainly provides us with flexibility, and we're pleased with it.

Thank you. Just to follow-up quick questions. Currently, both agencies have you on positive outlook. How interested would you be to improve your rating to be one notch higher or two notches higher? Are you totally comfortable with the current rating and intending on maintaining it.

The decision to upgrade us is really to the rating agency. Maybe it would be better directed to them. We obviously take our credit rating and our credit market standing very seriously. It's evidenced in the decisions we make to retire debt which we've done very aggressively over the past three or four years, and I don't see any change in that.

But I guess my question was more how comfortably are you with your current rating, or are you looking to improve it?

We're very comfortable, Anna, and we're going to stay vestor grade, and at this point, that's about all we can add to that.

Our next question comes from David Tameron of Wachovia Securities.

Good morning. Most of my questions have been answered. Larry, wanted to drill down on Canada a little more. From an M&A standpoint, obviously some of your peers have exited Canada. Do you guys look at that as we're going to wait it out and reallocate resources come '07 and as some prices come in, currency works in your favor, trust slow down, et cetera, or have you looked at seriously divesting that asset?

We've not looked at divesting that asset at all. We're not aware of any peers that had any kind of comparable position to ours who have exited Canada. There are companies that have small positions that are exiting theirs because they're no longer material to that company, as we have in some of our past asset sales in the past, but no, we're not giving any consideration to that.

Okay. I probably know the answer, but I will ask the question anyway. That being the case, seems like it would be a good opportunity or good time anyway to step in and purchase assets that are being divested from either the majors, Dominion, whoever. Do you care to comment on that?

Not any more than I did in the past. We'll look at them. If we can acquire them in an attractive package, we will. But as I said, we're pretty happy with the asset package that we have.

Okay. And one more question back to the --

It took us 18 years, 20 years to get here.

I hear you. One more question on the Woodford, did you say that -- the rumor has it that Newfield did a frac every 500 feet. Obviously everybody is trying different things to try to exploited the play. Have you guys done any fracing that extensive on the lateral?

Yeah, you know, generally we do do staged fracs, specific -- I don't have specifics at hand as it relates to the Woodford for our completion. Again, I will tell you that we've continually optimized that completion, and we're pretty comfortable where we are right now. We'll continue to go work on the cost side a bit, but we think those are going to come down, and we're seeing the production rates come up relative to the well performance.

I would add -- this is Vince. I would add to that that the optimum completion technique takes into account both of the costs and the flow rates. You aren't just looking to achieve maximum flow. You want the best rate of return on the project, and obviously, our guys know a lot about fracing tight reservoirs.

I agree. That's why I asked the question. Okay. Thanks.

Our last question comes from Richard Moorman from Capital One South Coast.

Good morning, gentlemen. Congratulations on a good quarter. Looking forward to a lot of the news. As a former employee of Devon's in Canada working for John, actually, a few years back before I got into analysis, it is great to see the progress. I have a couple questions around the Cotton Valley. I guess first of all on the Carthage side of the play, how would you describe the frac job you're doing there in comparison to the Barnett? Is this something materially different?

It's a little bit different. I would describe it as being a little bit different in terms of both a little on the completion side and then probably a little bit as you look at some of the frac chemistry, but in concept, it is still a multiple stages along a long lateral section where we're providing that frac. Of course, some of the technology and thinking transfers, and others of it you have to really customize it to fit the Cotton Valley there in Carthage.

Okay. And just a little more detail and you may not be able to talk about this, but I notice a couple of the recent permits have been for the Travis Peak formation in that area as well. Can you give us any color on what you're trying to do there?

We have quite a bit of acreage there. We do think we have good horizontal potential in the Travis Peak, and we plan on exploiting that potential.

Great. Thank you very much, and congratulaitions again on the quarter.

That takes care of all the questions in the queues. Do you have any closing remarks, Larry?

Sure. 2006 is obviously shaping up to be another very solid year for Devon, both from a financial aspect and an operational perspective. First three quarters we generated 2.3 billion in net earnings, 4.6 billion in cash flow, very strong numbers, oil and gas production as you heard, third quarter was up over second quarter, fourth quarter will be up again.

Our onshore properties led by the Barnett Shale performing extremely well, large scale development projects that we've been working on long in the lower tertiary in the Gulf of Mexico, and heavy oils in Canada, Povlo, and Brazil, all scheduled to come onstream next year and produce production next year. And following the successful test of our Jack 2 well, and our largest discovery, the Kaskida, out position in the lower tertiary is poised to delilver production reserve growth for a long time to come. Thank you very much for your interest in our company.

This concludes today's conference.