德文能源 (DVN) 2003 Q3 法說會逐字稿

Hello and welcome to the Devon Energy's Corporation's Third Quarter 2003 Results Conference Call.

All lines will be in a listen-only mode until the formal question-and-answer session. And at that time, instructions will be given if you have a question.

At the request of Devon Energy, this conference is being recorded for instant replay purposes.

At this time, 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.

Good morning everyone and thanks to you for joining us today to review Devon's third quarter results.

Larry Nichols, our Chairman and CEO will give you his thoughts on the quarter. We'll then turn the call over to our President and COO, Jim Hackett. Jim will provide an operations update. Following Jim's presentation, I'll return to discuss the financial results and then we'll open it up to Q&A.

We're going to cut the call off after about an hour from right now, but we'll continue to be available throughout the day to answer any questions that we don't have the opportunity to cover in the call.

Before I turn the call over to Larry, I have a couple of housekeeping items. First, I want to remind everybody that when we provide forward-looking information as we will in this call, we run the risk that our actual results will differ from our estimates. For a discussion of risk factors that could cause these results to differ, please see our Form 8-K filed with the SEC on May 8th.

We'll also be updating our forward-looking information and our risk factors in our upcoming Form 10-Q. We expect to file that late next week.

Second, in this call, we will refer to certain non-GAAP measures. Current disclosure rules require that we reconcile these measures to the closest GAAP performance measure, as well as explain why the non-GAAP results, non-GAAP measure is useful. That information can be found on today's press release. For anyone that did not receive a copy of today's press release, you may obtain this from our Web site. That address is www.devonenergy.com.

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

Thanks Vince. First, obviously, the third quarter was really an outstanding one for Devon. Our financial results reflects the exceptional earnings and cash generating capacity of the property base that we've built up over the last several years. Both oil, gas, and NGO production reached the highest level of any quarter in the company's history.

We had both a full quarter contribution from the Ocean properties, coupled with strong organic growth from our developmental projects, resulted in total production of 63.4 million equivalent barrels for the quarter. That says we're producing about 689,000 BOE a day. With the benefit of strong commodity prices, revenues and earnings also reached new highs.

Cutting all the way to the bottom line, in the third quarter Devon earned $412 million or $1.71 per diluted share, which is well above the first call consensus estimate of only $1.47. Also third quarter cash flow from operations totaled $1.1 billion, another all-time Devon record.

With that cash flow in the third quarter, we funded a little over $700 million in capital expenditures. We repaid 238 million in debt and we increased our cash on hand by more than 100 million. As a result, Devon's balance sheet continued to strengthen. We ended the quarter with $840 million of cash in bank, and net debt-to-total-cap ratio of about 44%, continuing to bring that ratio down as we told you all year we would.

In addition to repaying that 238 million of debt in the quarter, we trimmed about six million in annual interest costs by issuing 500 million in three-year-senior notes in conjunction with a 500 million interest rate swap. We used the proceeds to repay 500 million of a higher cost, term note.

Third quarter was also very strong operationally. In September we made a deepwater, Gulf of Mexico discovery on our Sturgis prospect in Atwater Block 183 an even more significant well for Devon was started during the third quarter on the St. Malo project. This resulted in a major discovery that Devon and Partners announced just last week. With a 22.5% working interest, St. Malo is a significant discovery for Devon, just on a stand-alone basis. However, the real significance for this company extends far beyond this discovery. Think Malo follows previous discoveries that Devon has been involved with in Trident and in the Cascades. In fact the pay sections in our St. Malo and our Cascade Wells, which are some 50 miles apart are very similar.

That information combined with other inventory discoveries and lower Tertiary age reservoirs, like Great White and Chinook is proving a really growing body of evidence that these are not isolated occurrences. We think they represent a wide-spread depositional trend. This is a trend that the Devon Gulf Explorationists have been working on for some time, and we have put together a really formidable acreage position. We have assembled nearly 600,000 net acres on more than 200 federal lease blocks in Alaminos Canyon and Keathley Canyon and in the Walker Ridge areas.

We have diligently acquired this position through lease sales, strategic joint ventures, industry partnerships and our merger and acquisition transactions.

We believe that Devon has one of the most extensive exposures of any company in this lower Tertiary trend. We have so far identified 20 lower Tertiary drilling opportunities of which we have four-way closure on Devon acreage, with an aggregate net reserve exposure of several billion barrels. These are in various stages of prospect development, and some are drill ready.

The lower Tertiary exploratory project we plan to drill next is Toledo, on Alaminos Canyon 951. This will be the third well in our deepwater joint venture with Chevron Texaco and a rig has just moved on the location.

The fourth well in this joint venture is currently being planned and again, will be a lower Tertiary test.

Appraisal wells for both Cascade and St. Malo discoveries are also planned for early 2004. These discoveries represent the kind of high impact at exploration success that we believe will power Devon's growth in the future and will deliver attractive finding the development costs and reserve replacement rates over the long term.

It's Exactly what we've been building for, for some time.

At this point, I'll turn the call over to Jim Hackett. Jim?

Thanks Larry. Let me begin with a quick activity summary for the period. At quarter close we had 122 rigs running company wide with about two-thirds Devon operated. This compares to the 88 rigs we had running at the end of the second quarter. Most of the increase occurred onshore in the U.S. and Canada where we drilled 536 wells for the company in the quarter, 273 in the U.S., 240 in Canada, and 23 internationally; 491 of these were low-risk development or exploitation wells and 45 were classified as exploration wells. With respective success rates of 98 and 84%.

Turning to our deepwater Gulf of Mexico activities, Larry mentioned the Miocene discoveries at Sturgis and Atwater Valley 183, in which we have a 25% working interest.

This well was the second of a four-well commitment in our joint venture with Chevron Texaco. The Sturgis discovery well was drilled at 25,000 feet and encountered more than 100 net feet of oil pay, which is why we'll be drilling an appraisal well next year here.

Larry also covered St. Malo, as thoroughly as we can today, while expressing our overall excitement with the lower Tertiary play.

In other deepwater Gulf exploration we drilled dry holes at Shiner Deep and Garden Banks, and Tuscany East and Desoto Canyon, at a combined net dry hole cost of $38 million.

At Yorktown we temporarily abandoned the well after the uncased portion of the hole collapsed, due to our being out of the hole so long while waiting on weather. We are evaluating the situation along with our partner. We'll make a decision on how to proceed next year.

Devon's share of the $86 million total well cost was about $60 million. If we decide to pursue this prospect further, we would only be required to pay our proportionate 50% share of capital costs. Importantly, we did not penetrate the main pay objective before we encountered hole integrity problems.

With regard to the current deepwater Gulf of Mexico exploration program, we are drilling ahead at 22,000 feet at York and Green Canyon 435, which is a 30,000 foot Miocene test in which we have a 35% interest.

Also the rig from St. Malo has now moved over onto our deepwater hawks prospect in Mississippi Canyon 508, where we have a 25% working interest. Each of these prospects has gross un-risk potential in excess of 150 million barrels of oil equivalent.

Turning to several deepwater development projects in the Gulf of Mexico, we drilled and completed two successful satellite wells in the Boomvang area. The East Break 688 Number Eight Well tested at a rate of 70 million cubic feet a day from two zones and the second well, East Break 686 Number Two, tested at 52 million cubic feet a day of gas, and 5200 barrels a day of liquids, which was better than expected.

Both wells will be tied into the Boomvang facility with first production occurring in the first quarter of 2004.

Another exploratory satellite well East Break 598 is currently underway.

Within the Nansen Boomvang field complex, we are currently producing over 40,000 barrels equivalent, net to our interest daily.

At our 65% owned Via Project (ph) in Mississippi Canyon, the mechanical issues were resolved in August and the well is currently producing 7,000 barrels of oil equivalent per day.

At Redhawk and Garden Banks 876, the two previously drilled wells have been completed and flowed at combined initial rates approaching 160 million cubic feet a day. These results support our production expectations for the project, and first production is planned for the third quarter of 2004, at 8,000 to 12,000 barrels of oil equivalent per day net to Devon.

At Magnolia (ph) Garden Banks 783, the A2 well was completed and tested at a rate of 9100 barrels of oil equivalent per day. The A5 and A6 development wells were also drilled during the third quarter, but not yet tested. Two more wells remain to be drilled, one development and one step-out.

Construction of the tension-like platform is continuing and we expect first production around year-end 2004 with a peak net rate of 9,000 to 12,000 barrels of oil equivalent per day projected for 2005.

On the Gulf of Mexico shelf a two-well development program was initiated to access additional reserves at Yuginow (ph) and 333, with the first well in the program producing 10 million cubic feet a day and 400 barrels a day of consana (ph) while the second well is currently being completed.

We have 100% working interest in these wells.

On the Grays prospect in Galveston Block 424 we drilled two additional successful wells in the third quarter, following our initial grades discovery in April of this year. We plan it install a production platform in December and estimate first production from the three wells in the first quarter of 2004.

Devon's net volumes are expected to be 30 to 40 million cubic feet per day and we have several analog wells that we'll be drilling next year.

At Hayong (ph) 140 as part of a three-well program initiated this summer, the A9 development well was drilled and logged 70 feet of net gas pay. The second well the A10, is still drilling toward the primary objective, but has already encountered 65 net feet of pay in the secondary objective.

Both wells will be completed and brought on line at a combined estimated net rate of 35 to 40 million a day in the next three months.

Moving to the onshore U.S. and Barnett Shale in North Texas, we have 14 rigs running with half of them drilling horizontal wells. During the third quarter we spud a total of 97 Barnett Shale wells, 81 of which we operated and 19 of which were horizontal.

Our average net production for the quarter was 580 million cubic feet equivalent per day. Compared to the second quarter average, that's up about 12% on volumes.

Regarding our horizontal drilling program, we currently have 40 horizontal wells producing an aggregate of 59 million cubic feet a day. Twenty-eight of these wells are within the core area and 12 are outside the core area. We drilled a total of 18 horizontal wells outside the core, three last year and 15 this year. Six of the wells are currently being completed.

The 12 wells outside of the core that have been completed and tied in are producing a combined 12 million cubic feet a day or about one million cubic feet per day per well. Actual per well rates range from 300 mcf to two million a day.

We're continuing to learn from each well we drill and have captured a lot of data concerning the geological complexities of the areas outside the core, causing us to change some of our drilling and completion practices.

The three most recent completions had an average IP of two million cubic feet a day per well, and are currently producing an average of 1.6 million per day.

Not only are our completions getting better, but our costs are coming down as well. We're currently drilling Barnett horizontals at an average cost of $1.5 million. We plan to drill a total of about 25 horizontal wells outside the core before this year ends, and our confidence in long-term viability of horizontal drilling continues with each successive quarter in this play.

A significant amount of the remaining potential in the Barnett is outside the core area where our strong acreage position stands at approximately 425,000 acres under lease. We estimate 150,000 to 200,000 acres of this position is prospective with today's technology and understanding of the area.

Assuming horizontal well spacing of 160 acres, we have over 1,000 potential horizontal drilling locations here.

Elsewhere onshore in East Texas, we continued a five-rig drilling program and an active recompletion program, drilling 20 new wells and recompleting 12, resulting in a net combined initial rate increase of about 48 million cubic feet a day equivalent.

An example of the kind of success we're having here, we drilled and cracked the Neil B#5 Bosher Well (ph) in [Inaudible] with an IP of 8.6 million cubic feet a day. We have an inventory of more than 350 drilling locations in over 200 recompletion opportunities that will keep us active in this area throughout 2004 and beyond.

Production from our East Texas properties, which includes Carthage, Bethany and Groesbeck (ph) areas, is currently running a little over 200 million cubic feet a day, net to our interest.

In the Rockies, we have six rigs running in the Washakie Basin of Wyoming and are now getting drilling permits issued more expeditiously in this part of the Rockies. This has allowed us to spud 25 wells year to date, and we expect to drill another 14 by year end.

Devon's share of the production in Washakie is now up to 87 million cubic feet a day equivalent and an all-time record for this field.

In the Powder River Basin coalbed methane play, production from our Deep Wide Ack (ph) and Big George developments is continuing to climb. We drilled 27 additional wells in the quarter and completed production enhancement on several existing wells. As a result, Devon's net production of the Powder climbed to about 85 million a day in the third quarter.

In total, U.S. production averaged 440,000 barrels of oil equivalent per day this past quarter.

In Canada we announced in September our decision to proceed with the development of our Jackfish thermal heavy oil project in Northeastern Alberta. As we indicated in our press release, this project will utilize steam-assisted gravity drainage or SAGD technology. As the operator of the longest-running SAGD project in the world, we have strong experience with this technology and expect Jackfish to produce an estimated 300 million barrels of recoverable reserves over the life of the project.

Currently we're in the process of applying for regulatory approval and expect that to take about a year. Capital costs were in the order of $400 million of which 70% will be required in the first couple of years following regulatory approval.

Once fully operational in the 2008 timeframe, the Jackfish project is designed to produce approximately 35,000 barrels a day of crude oil, and should be remain at this level for many years in the future.

In the foothills of Northeastern British Columbia and Western Alberta, two successful wells were tested or brought online during the third quarter at the combined rate of 18 million a day, net to Devon's interest, continuing the successful drilling program in this area.

Devon's net gas production out of the foothills averaged 130 million a day during the third quarter is a little over 136 million cubic feet a day currently.

We have recently stepped up our drilling activity in Western Canada in anticipation of a very active winter program. At the end of September we had 24 operated rigs drilling in Canada compared with only four at this time last year.

Currently, however we are running 36 rigs in Canada and expect to be running 40 to 45 by the end of the quarter.

In total Canadian production averaged 177,000 barrels of oil equivalent per day in the third quarter.

Internationally we reached an important milestone in China with the first production from the Devon-operated Panyu Fields in the Pearl River Mouth Basin in the south China Sea. Less than two years after the Chinese Government approved development plans, we successfully completed construction and installation of two fixed platforms, two platform drilling rigs and a floating production storage and offloading vessel or FPSO.

The first two of 27 development loads were completed and brought online in October, at a combined gross rate of 5500 barrels a day.

We've just finished drilling the first of 12 horizontal wells planned for Panyu. While we're currently running a little behind schedule on our drilling due to four typhoons that moved through the area during the last few months which shut down drilling operations. We are still on track to reach peak production of about 15,000 barrels a day net to our interest in mid-2004.

In West Africa, as we told you last quarter, the new FPSO, Serpentina was put on production in the southern expansion areas of the Zafiro field on July 13th, 50 days ahead of schedule.

Production continues to exceed our expectations in this part of the field where we're currently producing over 90,000 gross barrels a day from only 10 wells. We expect to have a total of 14 wells producing next year from the southern expansion area.

Devon's current share of field-wide production from Zafiro is about 53,000 barrels per day up from 35,000 barrels per day at the beginning of the year.

On the exploration front, we have a 34% working interest in an exploratory well, now drilling a block in Equatorial Guinea. This prospects lies in less than 500 feet of water and is called the N1 Well or Tray Prospect (ph) and has gross un-risk reserve potential of 59 million barrels of oil equivalent. If successful this prospect would set up several follow-on locations in the block.

Offshore Angola, the exploratory Zenza (ph) prospect in Block 16 was spud in early October and is currently drilling. Zenza (ph) is a high-risk, high potential prospect in which we have a 15% working interest.

Finally in Egypt on the Devon operated East A (ph) concession, the C1 development well was drilled and subsequently sidetracked, encountering 230 feet of net oil pay. The well was on production and making about 4500 barrels a day.

Drilling is also underway on the C5 exploration well in this area.

Going north in the Gulf of Suez, we plan an exploration well on the Devon operated 100% working interest Gligelze concession (ph) late in the fourth quarter, with a target gross un-risk reserve potential of 38 million barrels of oil equivalent.

In total, our international production averaged 73,000 barrels of oil equivalent in the third quarter per day.

As you've now heard, we have a lot of exciting things happening operationally within the company, and I'll turn the call back over to Vince for the financial analysis.

Thanks Jim. The Devon Ocean merger closed on April 25th, so the third quarter represents the first full quarter of the combined company, and it's the first quarter that we've had in quite a while that didn't have noise in the financial results.

In other words, for the most part, third quarter revenues, expenses, production, price realizations and so forth are pretty indicative of what we would expect going forward.

I'm going to limit my comments to a few exceptions and I'm going to try to give you some additional color on the reported results and what we expect going forward.

Looking first at production, as Larry mentioned, company-wide third quarter production came in at 63.4 million equivalent barrels, that was outside the top end of the range that we forecasted in the second quarter conference call. Actually all three divisions segments, business segments that is domestic, Canada and international, came in above budget, but the big driver for the production growth for the quarter was the early startup of Serpentina, FPSO and Equatorial Guinea that Jim mentioned.

Third quarter 2003 production reflects a 41% increase over the third quarter of 2002. Most of that increase is of course, attributable to the Ocean merger.

Looking at an apples to apples comparisons, that is by combining Devon and Ocean's reported production in the third quarter of 2002 and backing out production from properties that were subsequently divested, you'll find that production growth in the third quarter of 2003 was up 8.4% or more than 50,000 equivalent barrels a day when compared to the third quarter of the prior year.

For the sequential quarter comparison, same store sales comparison, you have to add the 3.9 million equivalent barrels that Ocean produced for the merger during the second quarter to our reported second quarter production of 56 million barrels. That gives you pro forma second quarter 2003 production of 59.9 million equivalent barrels or 657,000 barrels per day.

Comparing that to our third quarter production of 689,000 equivalent barrels a day, you'll find that we had sequential quarter, organic production growth of 32,000 barrels a day or 5%.

So anyway you cut it, the third quarter was a strong one for production growth.

Looking ahead to the fourth quarter, we expect production volumes to be very similar to the third quarter, that is between 63 and 64 million equivalent barrels in total. This will put us squarely in the range of the full-year forecast that we gave at the time of the merger. That was for reported full-year 2003 production to come in between 224 and 229 million equivalent barrels. This represents a 4-6% same-store sales growth that we have been advertising.

Now moving to oil and gas prices, although they were down from the second quarter levels, prices remained strong during the third quarter. Devon's U.S. floating gas price realizations, I'm referring to the prices that we realized on our unhedged volume, continue to be very strong in the third quarter relative to NYMEX.

They averaged $4.61 per mcf in the U.S. or just 36 cents under the NYMEX average. In Canada our floating gas price realizations continued to improve during the third quarter as well, relative to NYMEX. We realized an average price of 463 per mcf in Canada or just 34 cents under the NYMEX average on our floating gas price, floating Canadian gas price.

While our North American gas price differentials improved during the third quarter, our North American oil price differentials widened. Our third quarter U.S. floating oil price realizations averaged 28.90 per barrel or $1.36 under NYMEX in the U.S. In Canada, our third quarter floating oil price realizations averaged 24.58 or $5.68 less than the third quarter NYMEX average.

The Canadian differential reflects the heavier overall basket of crude that we produce in Canada.

Conversely, international oil price differentials improved during the third quarter. Our third quarter international floating oil price realizations averaged 26.16 per barrel, that's $4.10 under third quarter NYMEX. That happened because most of our international oil is priced based on Brent (ph) and Brent (ph) prices strengthened during the quarter relative to NYMEX; however I point out that that started to widen and we expect it to be back to historical levels in the fourth quarter.

We plan to provide you updated guidance for fourth quarter oil and gas price realizations in the third quarter 10-Q that I mentioned we'd been filing next week.

Moving now to marketing and midstream margins, these continue to outperform our guidance in the third quarter. During the quarter we had marketing and midstream revenues totaling 335 million. When you back out the associated expenses of 268 million, third quarter marketing and midstream margins total 67 million. That's about 16 million or 31% better than we expected for the quarter. The better than expected results are due to higher NGL production volumes than we forecasted, and higher than forecasted gas and NGL prices during the third quarter.

It now looks like our pervious guidance for full-year 2003 marketing and midstream margins was low, probably by about $20 million for the full year. We will also provide updated guidance on this item in the upcoming Form 10-Q.

Moving now to expenses, most were in line with our guidance. I'm going to comment on just a few items that vary from expectations. In the third quarter unit lease operating expenses came in about 4% or 14 cents per barrel equivalent above what we were looking for.

About one-third of the difference resulted from the stronger than expected Canadian dollar, most of the balance was related to higher than expected well work over costs, which help drive the strong production for the quarter.

Third quarter unit DD&A came in about 4% or 32 cents per barrel above our guidance. Most of the difference was due to the allocation of the Ocean purchase price. This was nearly the entire difference. What happened was that more dollars were allocated to Ocean's proved properties in the final allocation than we had originally anticipated. That resulted from higher oil and gas prices raising the expected value of the Ocean assets when we did the final booking of the purchase price.

The next expense area I want to cover is G&A expense, General and Administrative expense that is. The 79 million of G&A expense we reported was a few million below our forecasted range of 82 to 83 million for the quarter. This came in below the forecast in spite of a $3 million charge in the quarter from closing our Woodlands Offices and in spite of the stronger than expected Canadian dollar.

In the fourth quarter we expect G&A to look very similar to the third quarter. For those of you that track our capitalized cost, we capitalized 41 million of G&A in the third quarter of 2003 and that's about the same level we expect to capitalize in the fourth quarter.

As we move into 2004, we should see G&A expense continue to improve as we realize additional synergies from the Ocean merger.

Interest expense came in at 120 million for the third quarter, that's roughly 10 million lower than we expected, and there were two drivers to this. First, at the time of the merger, we underestimated the amount of interest that would qualify for capitalization, so ultimately we capitalized a total of 19 million of interest in the third quarter, which was more than we anticipated. But we also saved some hard dollars in interest expense through swaps and refinancings that we completed during the third quarter. We've reduced our annual interest burden by about 20 million a year based on the current rate environment.

As you look forward assuming no material changes in LIBOR or our debt balances, we would expect reported interest to come in at around 120 million in Q4 as well. Debt balances will stay about the same in the fourth quarter, because we are accumulating our excess cash to prepare for the '04 and '05 debt maturities that we have upcoming.

As Larry mentioned, we had third quarter net income of 412 million or $1.71 per diluted share. The items that are typically excluded by the sell-side analysts in their published earnings estimates are detailed in the press release, but since this quarter they pretty much washed out and had, in aggregate, they had no impact on third quarter earnings per share. So I'm not going to go over them.

Third quarter cash flow before balance sheet changes totaled 1.1 billion. Again, an all-time record.

To summarize, earnings, earnings per share and cash flow all came in well above our expectations during the quarter, was due to better than expected production, better than expected price realizations and better than expected midstream performance. All in all, a very solid third quarter performance.

That ends my prepared remarks. We will now open the call up to your questions. I'll ask each of you to limit your question to one, plus one follow-up to allow more people to have time for questions. Thanks.

Thank you. At this time we will begin our question-and-answer session using our polling feature. If you have a question, please press star-one on your telephone touchpad and should you need to cancel or your question has already been answered, please press star-two.

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Once again if you have a question, please press star-one and star-two, should you need to cancel.

One moment while the questions register.

And our first question comes from Mark Meyer from Simmons and Company.

Good morning. I'll, couple about the Barnett Shale Jim, just to clarify the 300 mcf, to two million a day IPs that you referenced, those are all related to horizontal in the non-core area?

Yes they are Mark.

Thanks. Based upon the, I guess the early performance data that you've collected and we've heard from one of your main competitors earlier this week, have you tightened the EUR (ph) potential, kind of range that you talked about earlier, related to the non-core horizontals, and if so, what is that?

Mark, this is Mike Lacey, let me address that question. The answer is no we have not, we're still looking at the same reserve numbers that we had talked about outside the core area, one-and-a-half to two-and-a-half bcf. That's the, you know, based on the numbers of wells that we've drilled out there, we currently have 12 wells on production, another six wells that are completing. We're still encouraged by what we see. We certainly had some mixed results, but overall, if we look at the program, we're very comfortable with what we're starting to see outside the core area.

Thank you.

Mark, I might add on that, that, this is Larry, that the outside the core area is a very large area and it is by no means one simple, homogeneous area. In our acreage, we have some of the acreage that's not prospective. We think a lot of it is, but it's hard to make sweeping statements about the non-core area as if it's one area. So a very big area, some of which is very good and some of which is not.

I Understand, thank you.

Thank you. And our next question comes from Van Levy from CIBC World Markets.

(indiscernible) Reported have had trouble organically moving their Canadian production, could you give us kind of a review of your Canadian operations and give us a sense of what you see on the production growth side there and the issues that surround that?

John Richels, do you want to answer that?

I will, Larry. Hi Van, it's John Richels, I'm sorry I didn't hear the very beginning part of your question, but I think you're just asking about our production growth in Canada and where the drivers for that might be coming from.

We're, this year, as we said, we spent a lot of time and effort in various areas of the basin here, particularly concentrated on the deep basin where we have a very large interest, in the foothills, northeast British Columbia, which includes a number of gas prone areas.

We're expecting to see very significant growth out of those three areas, particularly out of the deep basin and the foothills. Our foothills production is aided by both some very encouraging and consistent drilling results in the shallower formations, the cretaceous formations that we've been pursuing for some time on the Alberta side of the Alberta British Columbia border in the foothills. And we see that play extending over into the Grizzly Valley area, where you'll remember we had some initial the first Permian discoveries in British Columbia several years ago.

And so we'll continue to pursue that play into British Columbia. We're also aided by the fact that we got our Grizzly production on halfway through the year. That was something that was a long time coming, because of the regulatory hurdles and also the remoteness of the area. But that's on for us now.

And so we'll see some very significant continued growth out of the foothills. Similarly in the deep basin, where we've been drilling, still drilling new prospects for quite some time over the last couple of years. We will continue to do some of that this year and we'll also start some development drilling and down spacing. We really haven't done that. Some of our competitors as you know have done more of that. We were continuing to reach out so we still got that ahead of us, but we'll start to realize some growth, production growth from that down spacing in development as well.

So we've got several areas where there are pretty good production gains coming to us.

And organically year-over-year, where do you think you can take this, three, five, 7%?

We're anticipating that we can grow Canada somewhere around 4-6%.

OK, thank you.

On a going-forward basis Van.

Thank you.

Thank you, and our next question comes from Irene Haas from Sanders, Morris, Harris.

Yes, guys, I just kind of want to maybe hammer on Barnett Shale a little bit. I say, you know, going back to my notes from mid-year, you guys were thinking that the horizontal well can get you maybe 2.5 to four mcf a day, and that's really based on eight well, and I think back then the conversation is that the data points are all over the place. Now that you have quite a better, you know, probably sampling area, can you shed a little more light on you know, which county, you know, are working out better. And you know, what's the trick to it? And are there room, really actually to squeeze the costs down so it be even more economical.

Irene, this is Mike Lacey again. Let me see if I can address it. There were several questions there.

First with respect, let me come back again, with respect to the reserves that we're seeing in the horizontal wells. We have 41 wells on production, they're making almost 60 million a day between those 40 wells; 28 of those are inside the core, 12 are outside the core. And of course, we have a number of other wells that we're in the process of completing.

So, and if you look at that a little bit more than 10% of the field production now is coming from horizontal wells, which I think is remarkable.

Inside the core area, we're still looking at reserves in the order of three bcf per well. That's what we had presented in September. Outside the core area we see a range of about one-and-a-half to two-and-a-half bcf a well.

If you look at the well cost, and you brought that up and I'm glad that you did, we are still driving well costs down. Vertical wells, we've taken that cost from about 750,000 down to the range of 650 to 700 depending on exactly where it might be and what area. The horizontal drilling cost has come down from 1.7 to about $1.5 million. If you just do a little bit of math looking at F&D, with the kind of reserves that we're looking at, you can see that we're looking at very robust economics, both inside and outside the core area.

May I have a follow-up on the same thing? You know, since, you know, Barnett Shale is pretty important to Devon, really, roughly 14% of your current production and that the core areas probably need some rejuvenation I guess the vertical play has, you know, been in place for a while. In your view how does it look '04, '05, would you be able to keep Barnett production flat and perhaps growing with the new horizontal plays and what's the scatter now? You know, do you have, you know, wells in Parker and Johnson County? And that's all I have.

I think you laid out our strategy quite well. We are continuing of course to do things inside the core area. We have drilled a number of infield wells in there. We have a number yet to drill, but as we look forward, the continued growth in the Barnett will have to come from outside the core. We have been doing a lot of work with completion technique. We are looking at, and now we can incorporate seismic into better predicting where to drill as I just mentioned, we've driven well costs down. We're looking field wide at ways to add compression and lower the delivery pressure out there so we can increase gas production.

All of that, all those things that we're doing, both inside and outside the core, I think are going to drive production for a very long time in this field, 2004, 5 and beyond. This is an important part of Devon. It will be so for a long time in the future.

But importantly, Devon has become such a large company with such a large group of assets that the Barnett is not the only thing that drives the company, and I think that's important to remember. We're driven by a lot of large fields that are very, very capable fields of driving this company forward. The Barnett is just one of those.

Thank you very much.

Thank you and once again, that's star-one if you have a question or a comment, and star-two should you need to cancel.

And our next question comes from Ellen Hannan from Bear Stearns.

Thank you. Could you give us an update on the sale or potential sale of your Cherokee Basin assets?

Yes, Helen, this is Brian Jennings.

As you know we announced that we were intending to divest that asset. We have opened the data room and the good news is that we've had quite a bit of interest in the asset. As you know we put together a fairly large acreage position there, an asset that has great potential, but just an asset for Devon given our scale and our scope. We found that to be non-core. It is out intention to complete that divestiture prior to year-end and we are very confident that we will do that.

Thanks, as a follow-up, could you tell us what you've invested there to date?

I guess our, what would answer that Ellen is that we can get more detail to you offline, but we expect to make a profit on the sale of this asset versus what we've invested to date. So, again, it'll be a good transaction for Devon and we think a good transaction for the company that acquires it.

Great, thank you very much.

Thank you, and our next question comes from Ray Deacon, First Albany.

Yes, hi. I guess had a question on the deepwater prospects in the lower Tertiary, how many of those would you expect to drill per year I guess of those 20 prospects you talked about?

I think the best guess on that is probably three to four.

Three to four.

Out of the number that Larry said were totally available.

OK, and how many more you know, until you can determine kind of an EUR (ph) On this, how many more wells do you think you'll need?

You know it really depends as you may know Ray in the deepwater. It depends on the kind of data you get and the continuity it shows. We, as you know, and tried and we took a couple stabs at it. Some take two wells, some take three, so it really depends on the results of this second well in terms of determining the reservoir continuity for sizing purposes as well as the reservoir quality and oil quality.

OK, great. Great, thanks.

Thank you. And our next question comes from Jason Vaas (ph) with Davis Funds (ph) .

Simple question this morning guys. Did you mention what reserves were total for the quarter and if you could give like some sort of same-store number on that, that would be great. Thank you.

Jason (ph), this is Vince. We typically do not update our reserve estimates quarterly. a lot of our reserve data is based on outside engineering, third party work and so we update that once a year.

OK, thanks Vince.

Thank you. And our next question comes from Ken Beer with Johnson Rice.

Morning guys, I don't know if Darryl is there, but I just had a question on the pricing because the narrowing of the differential, obviously provided a great boost to the cash flow for this quarter, was going to get his thoughts or comments on what the fourth quarter was looking like.

Ken, it's Brian and Darryl is here, Ken, you were asking about the differential in the third quarter and what does that mean for the differentials in the fourth quarter?

Correct, what is that looking like kind of as we're halfway into the fourth quarter, have those smaller than expected differentials continued to stay in place so that you all might expect that extra boost in cash flow for fourth quarter.

Yes, Ken, Darryl, in the Rockies business, it's a couple of areas that have had the widest differentials historically over the last say 18 months have been the Rockies and Canada and with the new [Inaudible] coming on in Current River the end of May of this year, we saw the differentials in the Rocky Mountains narrow consistently over the quarter, going down from about $2.50 down in the area of 50 cents to 60 cents. It appears to us, depending on the type of weather you have, because we still have regional dynamics in play here, that we'll see fourth quarter differentials in the Rockies, will still be in that range of 50 to 60 cents.

In Canada the differentials have pretty much tracked the Rockies over the last four or five months in the 50 to 60 cent range and we'd expect that to continue into the fourth quarter also, but that will also be dependent upon cold weather that might hit just the Rockies and Canada.

Got you. Also, as the non-Rockies part of your business continues to grow, specifically the Barnett Shale, does the overall differential also shrink, so that company wide you're getting you know, less of a hit off of NYMEX or Henry Hubb (ph).

Well Barnett Shale specifically what has happened is that you've actually seen in the northern part of Texas and even into the Eastern part of Texas, you've seen differentials that have widened over the year. That's been caused by gas primarily in the Permian Basin and the San Juan basin that typically went west, now being displaced by Rocky Mountain Gas and so that gas is trying to go east, and it's competing with Fort Worth Basin gas and East Texas gas. So that differential has actually widened a little bit as we went through the year and we would expect that trend to continue probably for, you know, another year or so, and as we see additional capacity that comes out of the Rockies, pipeline capacity goes into the mid continent, you'll see some volumes start to push into the mid-continent and that will free up some of the Fort Worth Basin Gas and East Texas Gas and continue to go down to the Gulf Coast and not have to go back to the North or to the Midwest.

Got you. Thank you guys. Great quarter.

Thank you and once again that's star-one if you have a question or comment and star-two should you need to cancel.

And our next question comes from Robert Morris from Bank of New York.

Thanks. Mike, I think somebody there had mentioned that in the Barnett Shale that outside the core area perhaps half or maybe a little bit more of our acreage, you currently don't consider to be in prospective. Can you give us a little idea of why that is or what are the [Inaudible] that are different than what you do in non-perspective, versus what you [Inaudible] prospective for horizontal [Inaudible] outside the core area.

Robert, I don't know that I would go so far as to say it's not prospective. We know that Barnett Shale is underneath it. I think it's a question of how we move our science and technology out into the non-core areas. There's 430,000 acres out there. We're certainly not ready to write any of that off. I think over time we will continue to improve completion technology, our ability to predict sweet spots. We'll drive costs down and I think all of that area is open to exploration and hopefully over time that whole area will be productive. We certainly wouldn't want anybody working their marbles out on that at this point in time, because we are taking some risk out there.

But we haven't seen anything that's caused us to write off any of those areas at this point in time.

OK, I thought I had heard maybe Jim say about 150,000 acres of that was prospective.

Yes, I said that was with current technology, our current understanding. But Mike's comment is actually a fuller explanation of that.

OK, thank you.

We're not saying anything differently now than we've said over the last several quarters. We did see back at the beginning of the year when some people were taking the entire 420,000 acres and immediately assuming it was all prospective and coming up with numbers that may indeed be true some day. We have no idea because we haven't gotten that far. But if that was premature, what we've been saying recently is that we have -- and recently the last three, six months -- I don't recall -- that we have about 1,000 locations that we think are prospective now.

That is not to say there's not more. It depends. We're expanding as we go.

We're simply risking the acreage that we've got.

Thank you, and our next question comes from Steve Zagritz (ph) from Jefferies.

Hi. Can you give us a sense of what gross production in third quarter was from the shale, and where you would expect it to be, kind of in the ballpark, for 12 months out?

I think in the third quarter we averaged about 580, which is about where we are now.

That's a net number.

Net number. And your other question was next year?

Yes, as far -- but can you give me that on a gross basis?

Well, I think that that kind of projection is going to come out later in our guidance for next year, but directionally what we're looking at is that the core area will probably be more or less flat to where we are right now, and I think the jury is still out -- we're still working on what kind of growth we will get out of the non-core area going forward next year.

And this is to close on the other part of the question, Steve. The gross and net are very close to each other.

OK.

For Devon -- slightly higher, but it's not much.

Thanks, Jim.

Thank you. And once again, that's star, one if you have a question, and star, two should you need to cancel.

And our next question comes from Phil Pace from Credit Suisse First Boston.

Good morning guys, how are you?

Great.

You commented that Cascade and St. Malo in a similar pay (ph) section, and I think there's some similarities that extend to Chinook and Great White as well. Could you just comment on the similarities and maybe also what needs to happen at Sturgis to get the 100 feet to something that really sings. And can that happen with the appraisal well?

Yes, Phil, this is John. I think on St. Malo and Cascades and Chinook, what we're talking about is just big sheet sand sort of depositional environment. So you've got a lot more sand at a lower tertiary age deposited out there than any of us were envisioning a couple of years ago as we started drilling out there.

And so you couple that with the fact that every four-way that's been drilled to date has had hydrocarbons on it, and it lets you get pretty excited about what the potential of this thing can be. So that's the number one thing. Trident actually appears the same age rock, but have a different source. So we're trying to put those models together depositionally right now.

Could you comment notionally on [Inaudible] and permeability through those different plays? Is it pretty strong?

Yes, I think you've seen the Unical's comments from operatorship. I mean, we're dealing with basically South Texas Wilcox (ph) type scene. So it's high-teen type velocity, and corresponding permeabilities.

That's great. Thanks, John.

All right.

Thank you. And at this time, we show no further questions. I would like to turn the meeting -- actually, we do have one more question from John Gerdes from Southwest.

I don't want to let the hour go completely here. Guys, you've got three big areas here with the Barnett obviously, with the Nance and Boonvang (ph) complex and then also it with Zephoro (p) . We've beat the heck out of the Barnett today, so let's talk just briefly about the other two areas -- 42,000 barrels equivalent out of your net. Nance and Boonvang (ph) obviously got well over 260,000 I guess gross coming out of Zephoro (ph). How are pressures in well performance holding up in those areas, and I guess the follow on to that, and I'll leave it at this. is What are you thinking about reserve bookings in those specific areas? I mean, those are big tranches of your assets, obviously.

I'll take it. John, Nance and Boonvang (ph), their performance has been right in line with how we've had our reserves booked there, so we've been probably needs to get continued into next year before we start seeing any meaningjul sort of movement, revisions up from production.

Got you.

I think the big issue, there, that we deal with is, as the wells start to decline, how the operators are going to deal with plugging back in the other zones we have. And that's kind of one of our models for next year in terms of overall production. You can let the wells go way down before you change zones or you can take a more commercial view and go back to your 8,000 barrel-a-day plug backs that are in there with your smart completions.

John, to that, though, that you got MMS obviously constraints onto how much of that you can do, correct?

To a certain degree, yes, but remember the type of completions we have in there, it's not like we have to abandon the bottom zone and never going to get back to it. (inaudible) completions, so they're giving you a little bit more flexibility there. We've only done that on one or two wells, and we've been able to do it.

OK, good [Inaudible].

[Inaudible]

Well, just again, you've done a pretty fine job out there. I mean, you've done a pretty good job I think with pressure maintenance. What I'm hopeful for -- just well performance and what you're maybe thinking about in terms of reserve bookings on that big monster over there.

Exactly. In similar store (ph), we've got a lot of production there. We have some disappointment production -- mainly we have disappointment out there it's at the gas cap [Inaudible] and we get higher GOR ratios, which affects our ability to totally load up the facility. So when we get a higher GOR, we need to shut that well in typically right now. We're starting to go to a phase where we start drilling the water wells, injection wells, to help maintain pressure, and again I think you're at the end of next year before you can make any kind of meaningful revisions based on performance of the reservoirs there.

John, what do you think you do with the gas, ultimately? Do you Reinject or -- I guess you're going to have to reinject, huh?

We don't have to there. We're injecting as much as we can right now, and it's an issue we're working, John. I mean, Marathon's talking about their own g planter (ph) , so Exxon, the operator's looking at a lot of different ways to do something.

I will tell you that Larry was over there with us in early October, and of course looking at 150 men a day in flare (ph) going up was [Inaudible] with what we can do about it. So we are ...

Great. Your comments are helpful. Thanks guys.

Thank you, and our next question comes from Van Levy from CIBC World Markets.

Hey Larry, you are wrecking the service industry, by not spending more money, can you kind of lay out what your notion is on going forward, free cash flow, what you think debt to cap could be say at the end of 2004, and maybe comment on your over $800 million cash balance, and why is it so high?

Yes. Next year, we're seeing that the capital budget will be approximately the same it is this year, $2.4 billion for pure E&P and another several hundred million for facilities. So we don't see much different in cap ex this year -- next year versus this year. That could of course change as St. Malo and some of these other properties, discoveries we have -- that may allow for the opportunity to prudently spend more money rather than what we had budgeted. But that will be opportunity-driven, not driven by the cash we happen to have in the bank.

The reason we have accumulated $800 million in cash now is that we don't have debt that we can prudently pre-pay, and we will continue to do that all next year. We have only $337 million of debt that we can repay next year. We will do that with the cash we already have on hand. We'll continue to build cash to pay down debt that we have due in '05, where we have the larger maturities that we can pay. We anticipate -- as we said, debt to cap is already at 44. That's ahead of where some analysts had us at year end. We'll continue to bring that down by year end. And by this time next year, debt is not going to be an issue that anyone's asking about, because we'll be into the 30s. We don't really have a forecast on what it will be at year end '04, but it will be clearly at a level where it's no longer a topic of concern.

OK, thank you.

That's the end of the questions. We thank you for your attention to this call. We think it's been a very good quarter for Devon. All things are working as planned. The debt is coming down as planned. Production is coming up. We think we've got all cylinders working and look forward to doing that next quarter.

Thank you very much for participating in today's conference call. Have a great day and you may now disconnect.