德文能源 (DVN) 2002 Q3 法說會逐字稿

Good morning. My name is Paul. At this time I would like to welcome everyone to Devon Energies conference call. All lines have been placed on mute. After the remarks, there will be a question and answer period. If you would like to ask a question during this time, press star and the number 1 on your telephone keypad. If you would like to withdraw your question, press star and the number 2.

On behalf of Devon's management, I'll remind you that any statements that the company makes today that are not based on historical facts are forward-looking statements. Actual results may differ materially. Devon's form 10Q for the quarters ended March 31, 2002 and June 30, 2002, include the company's estimates for the year 2002. In addition, these documents include discussions of factors that could cause Devon's actual results to differ from the company's estimates. Devon's management encourages you to review these 10Q documents.

This call will be available for replay beginning at 12:30 p.m. eastern time today through 11:59 p.m. eastern time on Thursday, November 14 November 14th, 2002. The number to dial in for the replay is 1(800) 642-1687, or 1(706) 645-9291. The conference ID number for the replay is 598-7631.

Thank you. I would now like to introduce Mr. Larry Nichols, Chairman, President and CEO of Devon Energy. Mr. Nichols, you may proceed.

Good morning. Thank you for joining us. The purpose of this call today is, of course, to spend an hour with you and discuss our third quarter 2002 results. As is our practice, I'll make a few general comments on the highlights I see for the quarter and then turn the call over to Vince White. After that, you'll have the opportunity to ask questions and we'll have many of our key managers and officers here available to answer any questions you have.

Let me begin by saying that Devon made significant progress on several fronts during the third quarter. First and foremost, we had a very profitable third quarter. We generated 440 million in cash flow before the impact of property sales, and exceeded the consensus estimates on both earnings per share and cash flow per share. Second, we had another quarter that was very successful with the drill bit. We drilled 478 wells with a 96% success rate. That continues the trend we've had for the last several quarters. Third, we continue to have great success with our asset sales. During the third quarter, we completed $239 million of property sales. Last week, we closed our sale of the Argentina assets for $90 million. This brings our total divestitures through today to $1.4 billion.

We estimate we will close another $100 million in asset sales by year-end. This far exceeds the $1 billion that we expected to realize from these divestitures.

By applying the proceeds of these asset sales to debt reduction, we have reduced our debt net of cash on hand to $6.8 billion.

And finally, we are very pleased with gas prices. While there was significant concern earlier this year that full gas storage would result in low gas prices as we headed into the winter, we have instead had gas prices at Henry hub of around -- for the past three weeks. We said at the beginning of the year, actually the end of last year, that we thought productive capacity of North American gas would decline during the year. While that was not widely accepted at the time, it now is a recognized fact. Assuming the normal winter, this should continue to give very good gas support to gas prices this winter. On the other hand, there was one notable disappointment during the quarter due to a variety of issues including the impact of tropical storm Isadora, ethane rejection, voluntary shut-ins of gas in the Rockies. Total production for the third quarter came in slightly below our forecast. Vince will review that in more detail later.

At this point, I'll turn the call over to Vince to give you details of the quarter and the implications for the full year.

Thanks, Larry.

Before we get into the financial and operational discussion of the quarter, I want to remind everyone that's on the call by telephone that they should have received a fax or e-mail copy of our press release this morning. The total release is nine pages. If you did not receive the release or you received an incomplete copy, you may get that from our website. That address is www.devonenergy.com.

I also want to remind everybody that we will be holding our annual executive briefing for the analytical community on Wednesday, December 11th in New York. We have also added a second date on the West Coast this year. We'll be in San Francisco on Thursday, December 12th. If you are an analyst or a portfolio manager and you're interested in attending one of these meetings and have not yet registered, you can contact Gina Sicola (ph) at (888) 783-6468.

Moving now to the quarterly results, looking first at production, I want to remind you that our reported Q3 results exclude about 800,000 barrels that we produced in Argentina prior to the sale of those operations. Generally accepted accounting principles now require us to reclassify those volumes and all the income statement impact as discontinued operations. So that's all collapsed in the one line item, and the 800,000 barrels we produced there in the third quarter is excluded from the production data for the third quarter.

When you back out the volumes from Argentina, our reported third quarter 2002 production was 44.9 million equivalent barrels. That's about a 55% increase over our third quarter 2001 reported production. That's a 16 million barrel increase. However, that was about 700,000 barrels, or 1.5% below our expectations. More than half of that shortfall resulted from several items that really on an individual basis were insignificant, but in aggregate, they added up to almost 450,000 barrels.

First was downtime in the Gulf of Mexico. That's a result of tropical storm Isidora. That reduced our third quarter production by 186,000 barrels equivalent. Also in the Rockies, when gas prices dipped below $1 during the third quarter, we shut in some of the production that we did not have hedged. Fortunately, we had most of our production in the Rockies hedged, but the shut-ins reduced our third quarter gas production by about 106,000 barrels equivalent.

We also made the decision to sell ethane in the gas stream in several instances during the third quarter rather than extract it as NGLs. That reduces our net reported production volumes for the third quarter by about 140,000 barrels equivalent. I want to point out that while it reduces our reported production volumes, it enhances our revenue stream. We got about an extra quarter of a million dollars in sales revenues during the third quarter by choosing to reject that ethane extraction.

On a same-store sale basis, that's when you back out the production from the properties that we've sold or will sell, find that we have third quarter 2002 production from our retained properties of 43.9 million equivalent barrels. That compares to the third quarter of last year for Devon, Mitchell and Anderson combined, adjusted for the property sales of 44 million equivalent barrels. So on a year-over-year, apples to apples basis, production from core properties was down slightly.

In the second quarter of this year, production adjusted for the property sales was 44.6 million, so on a sequential quarter, same-store sales basis, production declined about 700,000 barrels, or 1.5%. That is from the second quarter of 2002 to the third quarter of 2002.

Looking ahead to the fourth quarter, we've had shut-ins related to Hurricane Lilly, and that will reduce our reported fourth quarter volumes by about 500,000 barrels of oil equivalent. We are also continuing to reject ethane where it makes economic sense to do so, and in addition to that, repairs to our Dunn vacant gas plant in Canada will prevent us from extracting ethane throughout the fourth quarter. In total, ethane rejection in the fourth quarter will reduce our net production volumes by at least 150,000 barrels of oil equivalent.

With those facts in mind, we expect to report fourth quarter retained property production of between 44.5 and 45 million equivalent barrels. That will bring our full year reported production from retained properties to 176.1 million barrels equivalent. When you add in the production from the Mitchell properties for the first 24 days of the year, that's prior to the close of the acquisition, you'll find that we have 2002 pro forma production from retained properties of about 178.4 million barrels. That compares to last year, 2001 production of Devon, Mitchell and Anderson combined adjusted for property sales of 174.1 million barrels. When you do the math, you'll find that we're now expecting growth from retained properties of between 2 and 3% in 2002.

Looking ahead to 2003, we're in the process of finalizing our capital budget and reserve report, so we do not have a specific production forecast yet, but we expect to have that data for our executive briefing again on December 11th. I will tell you in general, though, that the 2003 budget will look like -- a lot like our 2002 capital spending and we'd expect that level of spending to generate production growth next year similar to that of 2002.

In addition to that, immediate production growth, both our 2002 and 2003 capital programs include a pretty big investment in projects that provide long-term production and reserve growth opportunities.

I'm going to move the discussion now to product prices. Third quarter oil prices were up 6% over last year. However, gas and NGL prices were both down, similar gas down about 5%, NGL prices down about 10% from year-ago levels. Devon's price realizations versus our benchmark prices were pretty much in line with the guidance that we've provided. There are a couple of exceptions that I'm going to cover now. First, U.S. floating gas prices, that is, for the volumes that we don't have hedged or have fixed price sales, swaps or collars on, we averaged $2.55 per MCF in the third quarter. That is 61 cents less than the NIMEX price, and our forecast called for a range that had a midpoint of 40 cents under NIMEX. So our spreads off of NIMEX were wider in the third quarter than forecasted.

That really resulted from weak demand in the western U.S. Price differentials widened relative to Henry Hub for all the regions that supply the west. That includes the Permian basin, the Rockies, and San Juan basin, and, of course, Devon is a big producer in all those areas.

As we head into the winter, we expect to see demand strengthen and differentials close as a result of more weather-related demand and a decrease in competition from hydroelectric power in the western United States. In Canada, our floating gas price realizations came in at $2.26. Those are U.S. dollars, during the third quarter. That is 90 cents under NIMEX. The widest differential anticipated by our forecasted range was 80 cents under NIMEX. So Canadian gas price realizations came in lower than expected relative to Henry Hub. That probably doesn't surprise anyone. We got a lot of phone calls when Canadian price differentials started to widen out late in the second quarter and that continued throughout most of the third quarter.

The differentials for Canada did narrow late in the third quarter, and so we expect them to continue at more normal levels as we head into the winter months. Marketing and midstream revenues during the third quarter totaled $264 million. When you back out the associated cost and expenses of $211 million, you'll find that we generated marketing and midstream margins of $53 million. That's about $8 million better than we expected. When you look at the first nine months of the year, you'll see that our marketing and midstream operations generated margins of $133 million, so based on that, it appears likely that we will exceed our beginning of the year forecast of $170 million for full-year marketing and midstream margins.

I'm going to move now to the expense discussion. Most of the expense items for the quarter were in line with our guidance. I'm only going to comment on those that had variances from expectations or that had nonrecurring components during the quarter. Starting with lease operating and transportation expenses, adding those together, that came in at 192 million for the third quarter. This is down a little over 8 million from the second quarter of this year. That occurred in spite of an unusually high level of work-over activity the third quarter.

The big driver here is to reduced production expenses is the impact of our property sales. In the fourth quarter, as we have a lower level of work over activity and we also get a full quarter of benefit from the sole properties, we expect lease operating and transportation expenses to decline another 4 or $5 million in aggregate.

Next item I want to cover is G&A expense. General and administrative expenses, that is. That was $47 million in the third quarter. That came in about $3 million lower than we expected. However, going forward, we still think that $50 million a quarter is probably a good average run rate for G&A expense. Assuming that the fourth quarter comes in at that $50 million, our full year 2002 G&A expense will be $202 million. That's very near the low end of our full-year forecast. Both operating expenses and G&A expenses are coming down and that really just reflects the efficiencies we're realizing as we upgrade our asset base.

The last expense item I want to cover is income taxes. In the third quarter, income tax expense totaled $38 million. That's about 25% of our pretax earnings, and $36 million of the $38 million were current taxes, that is, cash taxes. That was really due to our property dispositions that we completed during the third quarter. They generated $35 million of current tax expense, and they reduced our deferred tax expense by an equal amount.

When you back out the impact of the property sales, the foreign exchange effect, the change in fair value, the various special items that the analytical community normally backs out, you'll find that we had third quarter tax expense of $37 million, all of which was deferred.

Looking at the first nine months of the year, which is probably more indicative of what we would expect going forward, excluding the impact of property sales and special items, total income tax expense was about 24% of adjusted pretax earnings with a little over two-thirds of that deferred.

When you take revenues, back out all the normal expenses, you'll see that we had second quarter earnings excluding special items of $108 million. That's the number that is comparable to the consensus analyst estimates. That translates into 67 cents per diluted common share, just over the first call consensus estimate of 66 cents per share. The cash margin from that level of earnings was about 440 million for the quarter, or $2.71 per diluted share. That exceeds the consensus cash flow estimate which was $2.47 per share. I might point out that we beat these consensus estimates in spite of low gas prices in the Rockies, the hurricane impact, and the other production issues I mentioned earlier.

I'm going to move now to our operating highlights. During the third quarter, we invested about $393 million in capital, that is for exploration and development projects. That brings the E&P capital expenditures for the first nine months of the year to 1.15 billion. That compares to our full-year forecast of 1.3 to 1.5 billion of exploration and development expenditures, so it looks like we'll come in at the top of the range. That is, close to 1.5 billion.

At the end of September, that is the end of the third quarter, we had 55 rigs running. We drilled 478 wells during the third quarter, 43 of those were classified as exploratory wells, the other 435 wells were exploitation or development wells. On the exploratory wells, we had a success rate of 77% during the quarter, and on exploitation and development wells, we had a success rate of 98%.

I'm going to briefly give you some area-by-area updates starting with our Barnett Shale field in north Texas. This was the field that was really the crown jewel of Mitchell Energy. It's the largest gas field in Devon's portfolio. It also happens to be the largest gas field in the state of Texas.

Our net production from Barnett Shale is currently running about 450 million cubic feet equivalent per day. We expect that that to climb to 500 million per day by year-end. We are keeping 14 rigs running all the time in the Barnett. Those 14 rigs drill 90 wells and perform refracts on 40 wells during the quarter.

All of the Barnett Shale wells, it's a tight reservoir, and they require a formation fracture when they're first drilled. We found out after declines, the wells can be fractured again and also the refraction wells produce at rates that rival the initial rates when they were first drilled, so that program really helps to stem production decline and add to the growth of this field in total.

In addition to the ongoing development and Re-completion activities on the Barnett, we drilled two exploratory horizontal wells during the third quarter. We don't have definitive results yet from those wells, the initial data is encouraging. We expect to bring both these wells onto production in the fourth quarter. We also plan to continue drilling exploratory wells outside our core area development during the fourth quarter.

We have some 27-acre infill pilots in the Barnett shale as well. These projects are designed to test the economic viability of reducing the spacing of our Barnett wells from the current 55 acres per well down to 27 acres per well. If that program is successful, it would provide us with more than 1,000 additional low-risk drilling locations in the Barnett shale, so we're really paying close attention to that, and the performance that we're seeing from these pilots is starting to look very encouraging.

Our marketing and midstream group was also very active in north Texas. They installed an incremental 32 miles of pipe, connected 90 new gas wells during the third quarter.

Moving now to the Powder River cold bed methane play in Wyoming, we stepped up the pace of activity there in the third quarter. We drilled 38 wells, that brings our total for the year to 100, including wells that were drilled in previous quarters, we brought 110 wells onto production in the powder during the third quarter. Our net coal bed methane production from the Powder River is currently running about 85 million cubic feet per day.

The Big George coals here are expected to hold a lot of the remaining potential in the Powder, and we currently have four Big George pilots underway. Our Pine Tree and House Creek pilots have been producing for some time now. During the third quarter, we saw first gas production from our Juniper Draw pilot, and we are currently waiting on permits that will allow us to begin production at the fourth pilot, which is at Pumpkin Buttes.

The results from the Big George pilots are really preliminary at this point, but we're increasingly encouraged about the potential in the Big George.

In the [Washakie] Field, also in Wyoming, we drilled 15 wells during the third quarter. Well costs are coming down here. We now expect to drill 27 wells this year as opposed to the 22 that we had originally budgeted. These are low risk wells and they come on pretty consistently between 1.5 and 2 million cubic feet of gas per well per day. Our net production in the Washakie right now is up to about 72 million cubic feet per day. This is an area that has provided consistent production growth since we acquired it from Santa Fe in 2000. We have 200,000 net acres in this area. We have hundreds of remaining drilling locations and we operate this property with a pretty high working interest. It averages about 85%.

Moving now to the Cherokee coal bed methane play, this is our latest major coal bed methane project. We have assembled 420,000 net acres in Kansas and Northeast Oklahoma. During the third quarter, we drilled 38 Cherokee wells. That brings the total number of wells that we've drilled to date to 242 wells. That's since we acquired our acreage position last year.

At the end of the third quarter, we had tied in 176 of the 242 wells to the low pressure transmission system. The initial wells are beginning to dewater and we're starting to see gas production ramp up here. Current field production is about 16 million cubic feet per day. We expect this to continue to move up as we tie in additional wells to the transportation system, and as the wells dewater. We have 100% working interest in most of our leases in this area.

In the Indian Basin field, this is in the Permian Basin in Southeast New Mexico, we drilled our final three wells of the nine well drilling program during the third quarter. All nine wells were successful. The combined production rate from these nine wells is about 3,000 barrels of oil per day and 10 million cubic feet of gas per day. The success of the 2002 drilling program also sets up an additional nine-well program for 2003. Our Indian Basin production is now at an all-time high. We're making about 67 million cubic feet of gas per day and 5,000 barrels of oil per day from this field.

In East Texas, we added over 100,000 net acres in the [Grossbeck] area, when we closed the Mitchell acquisition, we added 100,000 acres. This was an area that we were already active in. The area produces about 45 million cubic feet per day net to our interest. This is Cotton Valley lime and Cotton Valley sands production. We think the area holds a lot of promise for new field pays, infill location, up hole relocations. We got experience in this area in the Carthage Bethany field and we are applying it to the assets that we obtained from the Mitchell transaction.

During the quarter, the Wilbur No. 1 well, that's 100% Devon, that was a Cotton Valley Lime and Bosure (ph) play well, we have not yet tied it in. We expect it to produce about 5 million cubic feet per day when we tie it in. We have several offset opportunities and we are putting together a pretty active drilling program for this area for next year.

I'll move now to the Gulf Coast and the Gulf of Mexico. We had 14 rigs working in this area during the third quarter. On-shore in South Texas, we drilled the first three wells of a 10-well program in the ago Agua Dulse Field. These three wells are producing between 4 and 5 million cubic feet of gas per day and about 230 barrels of condensate. We have 100% working interest in Agua Dulse.

We mentioned earlier that tropical storm Isadora hit near the end of the third quarter, and we were fortunate we escaped serious damage to Devon-operated facilities, but we did lose about 186,000 equivalent barrels of production while our operations were shut in.

Also the drilling rig that was working at Eugene Island 305 suffered quite a bit of damage. It had to be taken to the shipyard for repairs, so we have temporarily suspended drilling there.

During the third quarter, the Gulf division brought on the discovery at Osconal (ph) 694. The 694 number 4 well came in at 16 million cubic feet per day plus 200 barrels of condensate per day. Our partners in this lease chose not to participate in the well, so we have 100% working interest in this one now.

It is a sub-sea completion in 570 feet of water, and the production here flows to the production facilities at Main Pass 259. Also at Main Pass 259, we have a two-well drilling program underway. The first well is on stream at 4 million cubic feet per day plus 200 barrels of oil per day. We have a 92% working interest in that well. The second well is testing, and if it's successful, a follow-up re-completion will be added to the program.

In the western Gulf of Mexico, we brought on our Thyrus (ph) platform onto production during Q3. This was on High Island Block 582. This was a discovery that we made in late 2000. Production is now ramping up and we expect it to hit about 45 million cubic feet of gas and 8,300 barrels of oil per day from the four wells that we've drilled there. We have a 37% working interest in this one.

At Eugene Island block 305, this is 100% Devon property. We drilled a third well here during the quarter. The drilling rig working on this property suffered a lot of hurricane damage. The well will be completed and brought on line in the fourth quarter when a replacement rig arrives. Before this drilling program, Eugene island 305 was making only about 1 million cubic feet of gas and 100 barrels of liquids per day. At the end of September, we had production here up to 20 million cubic feet of gas and 300 barrels per day, so that's been a successful project.

In September, we put out a press release on a deepwater exploration joint venture that we've entered into with Chevron Texaco. The basic terms of this is that by participating in four deepwater Gulf of Mexico tests, we will earn a 25% working interest in 71 deep water blocks. We already have 14 identified exploration prospects on the 71 deep water blocks and when you put Chevron and Texaco together, they really had an impressive array of deepwater leases and seismic data. This gives us immediate access to exploration opportunities that in aggregate represent billions of barrels of potential.

We're pretty stoked about this JV, and the depth that it adds to our deepwater inventory. We now have a multi-year deepwater prospect inventory in Devon.

During the third quarter, we initiated the drilling on the first well under this joint venture. This is the Sierra prospect. Sierra lies in 4,000 feet of water, has a target depth of 26,000 feet, and we should have results on this well by year-end. Also during the third quarter, we initiated drilling on another deepwater Gulf exploration well. This one, we've talked about as the Cortez prospect. It's at port Isabella 175, lies in 3300 feet of water. We've reached the TD here of 18,000 feet and are currently evaluating that well. This well has a dry hole cost of about $18 million, and Devon has a 38% working interest in that well.

Moving now to Canada, the most active area during the third quarter in Canada was our Boyd Minster area in East Central Alberta. We produce coal flow, heavy oil, and natural gas from this field. We've now completed our 2002 drilling program. 188 of the 202 wells we drilled were successful. It's a 93% success rate. 117 of those wells were drilled during the third quarter. Currently we have 168 of the wells tied into the production facilities, and it's producing about 3700 barrels of oil and 4 million cubic feet of gas per day.

Oil production is continuing to ramp up here, and including the wells we drilled this year, we expect full-year production to average about 20,000 equivalent barrels of oil per day. We're also planning a very active drilling program for 2003 at Lloyd Minster. In the foothills along the Alberta British Columbia border, we drilled two successful wells on our Finley prospect and two at Big Horn and Moose. In the deep Permian gas play in the Northeast BC foothills, we expect to begin to produce gas through a newly constructed pipeline facility near the end of this month. Initial rates here, -- this is the area we call grizzly valley. Initial rates net to our interest should be about 10 million cubic feet per day. We continue to be optimistic about the expansion of that line in 2003, so we can bring additional volumes on that we've already discovered in this area.

This brings our total foothills gas production up to over 100 million cubic feet per day net to our interest currently. We expect to see this grow by another 50% or more over the next several years. We were also really active in the deep basin. This is in west central Alberta. We put 15 new wells on production during the quarter. Our net production from those wells is 28 million cubic feet of gas per day. We also completed construction of a [sweet] gas plant, a 15 million a day plant in the Deep Basin, and we drilled a successful well that's been tied into that plant. We expect that this new plant -- we expect to fill the remaining capacity of this new plant with several follow-up locations that we have in that area.

Our deep basin net production is now up to about 110 million cubic feet of gas per day and 3,500 barrels of liquid per day, so this continues to be a growth area in Devon.

Moving now briefly to international, our facilities that are under construction at our [Panu] development project in South China Sea continue to move along really on schedule. This project involves setting two off shore platforms that produce into a floating production storage and offloading facility. We expect to see first production of oil here in late 2003. We also expect to spud the first of two exploration wells in the immediate area before the end of this year. That concludes my operational discussion. At this point, we'll open the call up to your questions.

At this time, I would like to remind everyone if you would like to ask a question, press star then the number 1 on your telephone keypads. Again, that's star, then the number 1. One moment, please, for your first question.

Your first question is from Shannon Nome, J.P. Morgan Securities Inc.

Thanks. Good morning. Larry and Vince, I guess Vince's comments earlier imply something in the order of 2 to 3% production growth in the 2003 time frame, and that's obviously a little shy of your stated longer term goals which I believe are closer to 5%, and I'm just wanting to know if you can comment in a very general way how you're feeling about the 5% number. Is that achievable over the longer haul or do you think something closer to industry average levels are in store for the next couple of years?

You know, I think that the answer to that question, Shannon, relies on the long-term success of the portion of the capital budget that we're devoting to high impact projects. We're making a considerable investment in deepwater, not just Gulf of Mexico, but off shore West Africa, and other projects such as the McKenzie delta that our success there over time will have a big impact on our long term growth rate, as well as our finding cost and reserve replacement over time. The portion of the capital budget that's devoted to the lower risk near-term projects is delivering the 2 to 3% that we currently expect to deliver.

Okay. And then also, Vince, I caught the 1.5 billion for full-year Capex but missed what your total was for Q3.

We did not put out a specific number for Q3, Shannon. Was that a trick question?

Actually, no, but it works for me.

We said that we expected -- we don't have a final budget yet, but we expect our 2003 capital budget to look a lot like 2002.

I'm sorry, I meant Q3 of this year. I'm looking to get a Q3 and a Q4 breakout.

Oh. I thought you said 03.

I did catch about 2003 would be comparable.

Okay.

393.

Yeah, E and P capital expenditures, that's drilling and facility, totaled 393 million during the third quarter.

Perfect. Thank you very much.

Thank you.

Your next question is from Shawn Reynolds, Petrie Parkman & Co.

I was wondering if you could talk about the Gulf of Mexico prospects, what's -- and an update on what's going on in West Africa.

Bill, are you on the call in Houston?

Yes.

Why don't you handle that one?

I think this year we'll probably get exposure to three deepwater prospects, two of which are currently drilling. We've previously announced the discovery at our cascade prospect.

Right.

Next year, I'm at least four wells in our inventory, two of them with Chevron, one with EOG and the most recent eastern Gulf lease sale area, that's in about 6,000 feet of water. And one that we intend to cause to be drilled on our inventory. So I would say at least four in 2003. Average working interest in those is probably on the order of 25 to 30%.

So when you say three this year, you're talking about Cortez, Sierra and Cascade?

That's correct.

And then four next year?

Yes.

And you think probably kind of four or five running?

Yeah, our attorney is increasing and -- inventory is increasing and we're currently talking to other parties also, so I would say that that would increase through time on the deep water side.

And Vince, any comments on West Africa?

You know, you faded out your question as I went past the Gulf. Could you repeat the portion on the question --

That was just an update on your activities in West Africa.

Sean, you might remember we have two wells planned next year in West Africa, one in our Ghana block and one in our Gali block.

So those are still on --?

Those are still on track for next year.

Okay. Great. Thanks a lot, guys.

Your next question is from Mr. Kenneth Beer from Johnson Rice & Co. L.L.C.

Hey Vince! Just on the Sierra prospect, you said it's got a TD of 26,000 feet. I was trying to find out what your working interest would be, what your costs would be in that well, kind of the promoted cost that you'd have to bear? And then also, what kind of target are you looking at for -- maybe this is more for Bill, as you look at some of these deepwater prospects, what's the target size, if nothing else specifically for Sierra and Cortez?

I think in general, we like to have those target size exposure in these deepwater projects of a net somewhere between 80 to 100 million barrels net. So we're trying to target some appreciable structures here. I'd rather not get into the complete details of the deal with Chevron, but I think our exposure on the Sierra well will be someplace around $20 million. Cortez is a shallower well. That's TD probably about 18,000 feet, so our exposure there is 37% of probably a $17 million well.

Okay. And with the Sierra prospect, at the end of the day, what's your working interest on Sierra?

25%.

All right.

And that well is currently at below 26,000 feet. We're deepening it to 29,000 feet.

All right. Also, just, Vince, a clarification. You talked about in the deep basin, I got two numbers. One, 28 million cubic feet a day and then the other 110 million and some odd barrels a day in terms of your current production. Help me out on that.

Yeah, I spit that out and realized it wasn't very clear as I did it. I believe the first number was the increment added by the drilling program that I talked about, and the second number, the 100-plus a day was total field production net to Devon's interest.

Okay. And last, this is more general for Larry, but you all have gotten your debt down below where you had projected for the street after the Anderson and Mitchell deals. Are you at a point where you feel like your balance sheet is where you wanted it to be to start looking at additional deals? What's the thought there?

Two different parts of that. No, we want to continue to reduce the debt. As we've said all along, we'd like to get back to a BBB-plus type rating, so while we're not uncomfortable with the debt at the level it is now, we still intend to use surplus cash flow during this winter and going forward to reduce that debt. With regard to acquisitions, obviously the balance sheet is not in a position to do a large cash acquisition, although we could do fairly small ones. That will not preclude one in theory from doing a merger with someone that involved all equity. In fact, you could even conjure up an acquisition that would be de-leveraging acquisition if the other company had less debt than we did. Those are always hard to do, and do we look for them always but I certainly would never predict when or how we might do something like that.

Okay. Fair enough then. Thank you, guys.

Ken, going back to your first question, I've looked that up. In the deep basin, the 15 new wells that we brought on production during the third quarter are producing 28 million cubic feet per day net to our interest, that brings the field wide production, basin-wide production net to Devon's interest to over 110 million cubic feet per day, plus 3500 barrels of liquid per day.

Got it. Thank you.

You bet.

All right, guys.

Your next question is from Mr. Mark Meyer with Goldman, Sachs & Co.

Good morning, Vince. Do you have an approximate oil/gas split on the 500,000 barrels of Lilly related impact for Q4?

We do have that detail.

I'll be seeing if I have that in front of me as we move on to the next question and interject that. If I don't get it in the call, I'll certainly have it for you after the call.

Okay. A question about the horizontals at Barnett. How many including whatever Mitchell had drilled previously have been drilled to date?

How many horizontal wells have we drilled to date in the Barnett Shale?

Yeah, including Mitchell's.

Four.

Looking at your Powder River run rate, under the assumption that you got kind of an equivalent level of spending going into 03, do you anticipate similar levels of powder river basin activity, and does the -- I guess the delay of the EIS to February impact any of your drilling schedule there?

At this point, we anticipate a similar level of spending and activity through year-end and into 2003. At present, with the decreased level of capital spending that we had this year and projected next year, we can basically maneuver around the EIS. The word is still that the EIS should occur, Record of Decision sometime in the first quarter, however, that is not going to materially impact our 03 program at this point in time.

What is your permanent backlog currently?

I don't know that I could answer that question. We have activity expectations next year for somewhere in the range of 100 to maybe 125 wells.

Very good. Thanks.

Your next question is from Ms. Stephanie Joe with Sanders Morris Harris.

Thank you. My question has been answered, but one more thing. Do you have any more color on the EIS? It's just delayed until probably next year, is that correct?

We couldn't hear you.

Could you repeat that, please?

Okay. Sorry. What I was saying, most of my question had been answered, but you don't have any more color regarding the Powder River Basin coal bed methane EIS besides it's being delayed until next year?

Yeah, I mean, that word has been out. We are obviously heavily engaged, but that word's been on the street now for at least a couple of months that it was going to leak into 2003. I think our current date, it's going to go out for public comment late January with an expectation of Record of Decision being released in late February, early March time frame.

Okay. Thank you.

Your next question is from Mr. Andrew Lees with RBC Capital Markets.

Hi, guys. I was wondering if you could let me know what your capitalized interest G&A were in the third quarter, and then also some insight into your capital on your marketing midstream assets for the year?

Let me repeat the question and see if we got this right. You want to know what capitalized G&A and interest expense was during the third quarter, as well as midstream capital expenditures during the third quarter?

Third quarter, fourth quarter, et cetera. What have you spent year-to-date?

Okay. So you want the nine months numbers?

Yes, please.

Okay. We've got that. The year-to-date number for the midstream capital is $60 million.

How much of that was in the third quarter?

Correction, that's $95 million.

The year-to-date capitalized G and A is $75.4 million. That includes $26.8 million of capitalized G&A in the third quarter. We capitalize very little interest. That number is just essentially immaterial.

Are we ready for the next question? Did we answer your question?

What was that third quarter cap G&A number, Vince? 26 what?

$26.8 million.

Great. And last thing. Do you guys have any insight on your drill bit reserve replacement numbers this year, year-to-date?

No, we're in the process of compiling our year-end reserve report, and we -- you know, other than the guidance we gave early in the year, we've got no additional insight. We did add, I guess, in mid year an expected write-down in the powder river basin of about 14 million barrels equivalent. That's the only incremental information we've given on reserve replacement during the year.

Okay. Thanks.

Your next question is from Mr. Bob Christensen with First Albany Corporation.

My name is actually Phil Jestwitz. Related to that 14 million barrel write-down on the Powder River, how are you wide out coals doing there right now?

We are still active in the -- you'll hear more and more as we move forward, but our production has been relatively stable. We've been growing enough to mitigate the natural decline we're seeing in the fields, plus we’ve been stable in the last couple of quarters -- about 85 million today.

Thank you.

Your next question is from Mr. Van Levy with CIBC World Markets.

Morning, gentlemen. Your coal bed methane program production when you add up San Juan, Powder River, [Raton], Cherokee, et cetera, where was it roughly in the third quarter and where do you see the exit rate for the year?

I can tell you in round number, we're producing a little over 150 million a day of coal bed methane company wide net to Devon's interest. And that -- our exit rate won't differ from that materially. We expect to see volumes come up a little in the Cherokee, but the San Juan basin is relatively stable as is the powder.

And in one of your presentations, you had projections out 2002, 2003, 2004, et cetera, somewhere hitting around 300 million a day by 2003. What is your view of that now?

Recognize first of all that one of our largest growth properties in coal bed methane, the Raton basin where we're anticipating a lot of growth was divested earlier this year. So those comparisons are not really valid. As far as future production growth, I think it depends a lot on the Big George and the Powder River Basin and the success of our Cherokee play that we've assembled in Kansas and Oklahoma.

And you gave a good detail of each area, Vince, and including the Bozier play. You didn't comment on the economic viability of the relationship between well head prices and drilling costs, et cetera. Would you care to comment on that?

On a particular play?

Start with the [Bozier] or maybe go through that and a couple of the other coal bed plays, San Juan, Powder River, et cetera.

The Bozier is not a coal bed methane play. I really think that area by area economics would is beyond the scope of this call, Van. I'd be glad to get into that in more detail. Generally I'll tell you we have a highly profitable asset base. We've disposed of properties that are marginal and that certainly under any kind of reasonable gas price scenario, we're going to be an active driller.

Last question, you also talked about expanding the coal bed program into Canada. Could you give us an update on that?

Are you available to give us an update on coal bed methane exploration in Canada?

Yeah, I'd be happy to. Van, we've got several areas in Canada that are perspective for coal bed methane. We've done some testing in a play that's basically in the Plains in a stratographic area, but we've concentrated our efforts over the last year and a bit on a play in the foothills area, and we're proceeding with testing now. We'll certainly know a lot more as we get into 2003.

Okay. Thank you.

You know, just to characterize for those that may not be as familiar, our coal bed methane efforts in Canada have consisted of really regional reconnaissance work where we're just looking into the potential of coal bed methane in several areas.

Ready for the next question.

I would like to remind all participants if you would like to ask a question, press star then the number 1 on your telephone keypad. Your next question is from Mr. Peter Vig with Round Rock Capital.

Couple of questions on the Barnett shale play. I notice you've been running 12 to 14 rigs down from 19 to 20 when you acquired these assets from Mitchell. Could you tell us what that relates to, particularly given where the commodity is?

This is Rick. We have really been running at 14 rigs since the first of the year, and have been consistently at that rig level. We anticipate going forward at that same level for the immediate near term. When we first received the property, we were at close to the 18, 19 rig level for a very short period of time. We have provided ourselves with the ability to stay at a very active rate. Our actual efficiency on rig utilization has been very high this year in comparison to the same rig rate, or the rig number. So the number of wells, the number of reserves that we're touching, if you will, is still the same number. So that is the level that makes sense for us at this point in time.

Okay.

What we did is there were a couple rigs there that were not really very efficient, that do not have good motors and good equipment, and we ran those rigs off, so, you know, the goal is not to have the most number of rigs. It's to drill the most number of wells with the least number of rigs, and we think we'll drill the same number of wells with 14 rigs during the year because we've increased the efficiency of those rigs that are remaining. Once you run a couple rigs off, the world recognizes that you're deadly serious about getting things that are efficient. And that increased the whole efficiency of that operation. So we'll get the same number of wells drilled that Mitchell would have gotten with more rigs.

Okay. Second question, at your Barnett Shale school, you expressed some enthusiasm for the southern extension of the play in Johnson county. Have you drilled any wells there? And what have the results of that been?

We did drill a well there during the third quarter, didn't mention it in the property overview. We are expecting to tie that well in.

This is Rick again. We have drilled a single well. We're preparing to move the rig back to drill a couple additional exploratory wells in the area. We evaluating the data we get, and still we're a far from determining the results. We're encouraged with what we see, but again, it's premature on how we will complete these wells and how we will tie them in.

Third question. Have you drilled any cavitation wells in the play and, if so, what have been the results of those wells?

We have made an effort at cavitating a couple of Barnett Shale wells, and the success were marginal. That's something that we haven't finished doing some additional science on it. We're looking at different opportunities or different ways of handling that. It did not cavitate as well as, for example, the San Juan basin does on coal.

Does that end your question?

It does. Thank you.

Thank you. We've used up the hour, so we're going to cut the call off at this point. We'll be happy to take any follow-up questions anyone might have later in the day.

Thank you for your attention to our company.

Ladies and gentlemen, this concludes today's call. Again, this call will be available for replay beginning at 12:30 p.m. eastern time today through 11:59 p.m. eastern time on Thursday, November 14, 2002. The number to dial in for the replay is 1-800-642-1687 or 1(706) 645-9291. The conference ID number for the replay is 598-7631. Thank you, and have a good day.--- 0