德文能源 (DVN) 2002 Q2 法說會逐字稿

Good morning. My name is Tamia and I will be your conference facilitator today. At this time, I would like to welcome everyone to the Devon Energy second quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks there will be a question-and-answer period. If you would like to ask a question, during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press star and the number two on your telephone keypad. This call will be available for replay beginning at 12:30 p.m. eastern standard time today, through 11:59 p.m. eastern standard time on August 8th, 2002. The conference I.D. number is 4927184. The number to dial for the replay is 1-800-642-1687, or 706-645-9291.

On behalf of Devon's management, I will 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 10-Q for the quarter ended March 31st, 2002, includes the Company's estimates for the year 2002. In addition, it includes a discussion of [INAUDIBLE] that could cause Devon's actual results to differ from the Company estimates. Devon's management encourages you to review form 10-Q. I would like to turn it over to your host, Larry Nichols, Chairman and Chief Executive Officer. Please go ahead, sir.

Thank you. Good morning. Thanks for joining us. The purpose of today's call is to spend an hour or so discussing Devon's second quarter 2002 results. As usual I will make a few general remarks about the quarter and then turn the call over to Vince White. After that you will have the opportunity to ask questions and has been our past practice, we have many of the key managers and officers of Devon here available to answer any questions. Let me first begin by saying that we're very pleased with Devon's progress during the second quarter. Among the successes we had this quarter six things really stand out. First, both oil and gas production and total revenues reached the highest levels of any quarter in the Company's history.

Second, total production of oil, gas and NGL's for the quarter were right in line with our expectations. So we're on track for real core property production growth in 2002. Our target remains about 5%. Third, we completed $982 million of property sales during the quarter and we used the proceeds to reduce indebtedness. This brings our total divestitures closed to date to $1.2 billion. We expect to complete the balance of our previously announced sales during the third quarter.

Fourth, we paid down debt during the quarter by approximately $1 billion. As of June 30, long-term debt, net of the Chevron exchangeables and the cash in the bank was approximately $7 billion. As of today, that is down another $100 million to $6.9 billion. Fifth, we generated $124 million in free cash flow this quarter. Over and above all of our expenditures, including all of our capital expenditures.

Finally, we had another very good quarter with the drill bit. We invested $308 million in exploration and development capital. With that we drilled 351 oil and gas wells, and had a 96% success rate. The successful wells included what looks like to be a very significant deepwater discovery on our Cascade prospect. There was on the other side of the ledger, one notable disappointment in the quarter, unusually low Canadian gas prices on June 30 resulted in a full cost ceiling test adjustment. This mechanical test caused us to report a net loss for the quarter. To summarize, the second quarter was a very good one for Devon. Another successful quarter of executing the plan that we laid out for the investors at the beginning of the year. With that I will turn the call over to Vince for the details of the quarter.

Thank you, Larry. Before we get to the financial discussion of the quarter I want to remind everyone that we issued a press release on the second quarter results. The total release is ten pages. Anyone that did not receive that news release, or that received an incomplete copy, may get that on our website, that address is www.devonenergy.com. Moving now to the quarterly results. Looking first at production. I want to point out that our reported production excludes 229,000 barrels that we produced in Indonesia prior to selling those operations during the second quarter. The reported results exclude those Indonesian volumes because they have been reclassified as discontinued operations. We have given you a detail of discontinued operations in the back of the press release.

Excluding those volumes, we reported second quarter, 2002 production of oil, gas, and NGL's that was right in line with our expectations, 50.3 million equivalent barrels. That's a 75% increase or a 22 million equivalent barrel increase over the second quarter of last year. When you back out the production from the properties that we have sold or have identified for sale, we had second quarter 2002 production from our core properties of 45.3 million equivalent barrels. If you compare that to the second quarter of 2001, for Devon, Mitchell and Anderson combined adjusted for the sold properties, production was 44.1 million equivalent barrels. So on a year-over-year, combined Company basis, production from the core properties grew about 3%.

Looking now to sequential quarter comparison. Production in the first quarter of this year adjusted for property sales was 45.1 million equivalent barrels. That is also adjusted for the days of Mitchell that we did not, prior to the close of that transaction. When you do the math you will find that we had sequential core property production up about 200,000 barrels, essentially flat first quarter to second quarter. For the first half of 2002, the year-over-year combined Company production from core properties is up about 3.2 million equivalent barrels. That is over the first half of 2001, and that is just under 4% growth. We expect our core property production growth to accelerate in the second half of the year so we are on track with our beginning of the year production estimates.

Moving now to production, to product prices. First, second quarter, as you probably know, second quarter oil, gas and NGL prices were all down from the previous year. Oil prices were down 3% from year-ago levels, gas and NGL prices were both down 31% from year-ago levels. Our oil price realizations versus the benchmark was -- were pretty much in line, or our overall price realizations versus benchmark prices were pretty much in line with our guidance we gave in our form 10-Q. There are a couple of exceptions I will cover now for those of you who maintain models on Devon. For volumes subject to floating prices, I'm referring to those volumes that were not impacted by hedges, fixed priced sales, swaps or collars, Devon received $23.99 per barrel in the U.S. during the second quarter. That is for oil. This was about 40 cents better than the price implied by the midpoint of our forecasted differential range.

Our Canadian floating oil price realizations were also strong. They were $22.92 per barrel, or $1.18 better than the price implied by the midpoint of our forecasted differential range. The reason for the improved realizations in crude prices is that sour and heavy crudes have been -- had relatively strong prices this year. That is really resulted from OPEC production cuts that have reduced the worldwide supply of heavy and sour crudes. On the natural gas side, our second quarter U.S. floating gas price realizations came in at $2.92 per MCF. That is 46 cents less than Nimex. That compares to the midpoint of our forecast differential range of 20 cents under Nimex. So our U.S. gas price realizations came in under expectations during the second quarter. There has been very weak demand for natural gas in the western U.S., and that has led to relatively low gas price realizations in the basins that supply the western U.S., that is the Permian, the San Juan and the Rockies.

In Canada, floating gas price realizations came in at $2.77 per MCF for the second quarter and that is within the range of our forecasted guidance. I do want to point out, though, that the weak demand in the west has also had a big impact on Canadian prices, late in the second quarter and continuing into the third quarter. So we expect to see downward pressure or our Canadian gas price realizations during the third quarter.

Moving now to natural gas liquids, price realizations for the quarter came in at $13.61 per barrel, company-wide. That compares to -- that is about 52% of the Nimex WT oil price for the second quarter. That compares to first quarter of -- no, excuse me, second quarter of 2001 average price of $19.63 per barrel. At $19.63 per barrel in the second quarter of last year was about 70% of Nimex WTI. So as a percentage of the WTI price, year-over-year, second quarter we dropped to 52% versus 70% last year. And that was really the result of weaker overall NGL prices in North America. Devon's NGL prices are also impacted by the nature of the NGL's we produce. Almost half of our NGL stream is ethane. And that is the is the lowest value product of the various natural gas liquids. That compares to an industry wide ethane content of about 35% for North America. The higher ethane content causes us to get lower price realizations on our NGL's. Marketing and midstream revenues in the second quarter were $267 million. The associated costs and expenses were $222 million, so we had $45 million of contribution margin from the marketing and midstream, right in line with our expectations.

I am going to move now to expenses. Most expense items for the quarter were in line with our guidance. I do want to comment on a few items that varied from our expectations or that had nonrecurring components or unusual variances during the second quarter. First expense that I will cover is operating expenses, production and operating expenses. We break this out into three line items on our financial statements, lease operating expense, transportation expense, and production taxes. In total, production and operating expenses came in right in line with our expectations, $239 million for the second quarter. The controllable portion of that, lease operating expenses and transportation expenses, that is excluding production taxes came in at $204 million for the second quarter. That translates to $4.06 per equivalent barrel of production. I feel -- if you compare that to the second quarter of last year you will see that we are down $4.38 per barrel in 2001. The improvement in these unit operating costs really reflects the quality of the Mitchell and Anderson properties that we've added. Our recent dispositions of non-core properties are also contributing to lower unit lease operating expenses and so we should get some help there going forward.

Next I want to cover general and administrative expenses. G&A was $54 million for the second quarter. This was about 3 or $4 million higher than our guidance, roughly $1 million of the excess was due to a spike in professional fees, and that is expected to be nonrecurring. The remaining amount in excess of the forecast was due to higher than anticipated office rent, pension costs and health insurance cost. And those expenses will most likely continue at the higher levels in the future. So we will be updating our budget and reviewing our full-year guidance for G&A and it's likely we will have a slight upward adjustment for that in our upcoming form 10-Q.

I want to talk now about the full cost ceiling test adjustment we took during the second quarter. This adjustment resulted from Canadian gas prices falling to very low levels in late June. And before we cover the details of the adjustment, I want to talk about the drivers that caused the price weakness in Canada. First, eastbound capacity on one of the major gas transportation systems out of Canada, that is the TransCanada pipeline, was reduced. And the reason that that was down was planned routine maintenance on that system. There were also mechanical breakdowns that aggravated that situation. At the same time, that eastbound transportation was restricted out of Canada, gas demand in the west was extremely low. I mentioned that earlier. The low demand in the west resulted from a combination of low Industrial demand, mild weather, and an unusually high levels of hydroelectric power availability. As a result of all of these stars aligning, Canadian gas prices plummeted. At one point, the Ako hub price fell to well below a dollar U.S. per NCF. At June 30th, when we did the ceiling test, the AKO hub price was $1.43 U.S.

And as a result, we took a full cost ceiling test adjustment of $651 million pre-tax, or $371 million after-tax. For those of you that are not familiar with the full cost ceiling test, I want to spend a couple of minutes on the mechanics of that test. Companies that use the full-cost method of accounting are required to perform this ceiling test at the end of each quarter. The ceiling is the book value of your unproved properties, plus the estimated after-tax future net revenues from your proved oil and gas property. These future net revenues are calculated based on oil and gas prices at the end of the period, without the benefit of hedges that you have in place, and are held flat forever. These theoretical future net revenues are then discounted at 10% per year. The Company then compares the net book value of its oil and gas properties, less related deferred income taxes to the ceiling and any excess must be written off as an expense.

There are a lot of questions about what a ceiling test adjustment does or does not represent. I am going to attempt to answer a few of these. First, since a test is based on oil and natural gas prices at a single point in time and ignores the prices -- the fact that prices are volatile and go up and down over time, it is not a reflection of the fair market value of your oil and gas property. I will just give you an example here, the adjustment that we are taking in Canada, as I said, was based on the Canadian Ako hub price at $1.43 U.S. forever. Where in fact if you look just one week earlier, the price was something like 50 or 60% higher, if we had done the ceiling test at that time we would have had no write-down.

Second, the adjustment does not result from or apply to goodwill. The ceiling test adjustment is an adjustment to the book value of your oil and gas price properties, and that is completely separate from the goodwill account. The impairment test for goodwill is different than the ceiling test in that it is based on the fair value of your oil and gas properties, not this point in time calculation. And so a temporary -- a temporary collapse such as what we had at the end of June in Canada, since that doesn't really impact the fair value of your properties very much, it doesn't expose us to an impairment of goodwill.

Third, the ceiling test adjustment doesn't relate to any specific property or field, and it does not necessarily imply that you have written any oil and gas reserves off, it is merely an accounting adjustment. The adjustment has no impact on cash flow. It reduces net income in the current period and increases net income in future periods, but it is completely cash neutral.

And finally the adjustment has no impact on our credit agreements. Ceiling test adjustments are specifically addressed in our debt covenants and our credit agreements specify the ceiling test write-downs are added back for purposes of the debt to cap test. Our funded debt-to-cap, as calculated in our credit agreements, was 56% at June 30th, following the ceiling test write-down, and the agreements allow for debt-to-cap ratios up to 65%. So we have a lot of room there. That is all I have to say about the ceiling test.

I am going to move now to interest expense. For the second quarter, our interest expense came in at $148 million, $8 million of that was attributable to a premium paid on the early retirement of some bonds that we called during the second quarter. That will be nonrecurring. We also of course will have lower debt levels in the second half of the year, so we expect interest expense to run about $135 million per quarter in the third and fourth quarters of this year.

The last expense item I want to address is income taxes. During the second quarter we recognized a $227 million income tax benefit. And this was made up of current income taxes of $77 million offset by a large deferred tax benefit. There were a lot of moving parts. I want to cover a couple of these. If the property dispositions that we covered during the second quarter, that generated $56 million of current income tax expense, and at the same time, reduced deferred income tax expense by $56 million. The special items that we referred to in our press release such as the foreign exchange effect, the change in fair value of derivative instruments, and the full cost ceiling adjustment, they also impacted deferred taxes. If you back out the impact of the property sales and these special items you will find that we had current tax expense on earnings from operations, or pre-tax earnings of $21 million, that's 12% of these adjusted pre-tax earnings. Deferred taxes, before the impact of the property sales in the special items were $16 million, or 9% of adjusted pre-tax earnings. And that is -- those current deferred items are, deferred taxes are pretty much in line with our guidance.

When you take the revenues back out all the normal expenses, you will find that we had second quarter earnings before the full cost ceiling adjustment in special items of $144 million. This is the number that is comparable to the numbers that most of the analysts forecast and do the consensus estimate. $144 million of earnings translates to 88 cents per diluted common share. That is 3 cents over the first call consensus estimate for the quarter of 85 cents per share. Cash margin for the quarter was $491 million. That is $3.01 per share and compares to the consensus cash flow estimate of $3.07 per share.

I'm going to turn now to Devon's second quarter operating highlights. First let me just mention that capital expenditures for exploration and development projects during the quarter were $308 million. That brings the total for the first six months of 2002 up to $762 million. As you can see, spending was down in the second quarter, that is due to less activity in Canada, and that is really not unusual. The intense first quarter activity that we experienced in Canada on the winter-only access properties that we have there generally gives us a spike in capital spending during the first quarter. Company-wide at the end of the first quarter, we had 65 rigs running, into the second quarter. During the quarter we drilled 351 wells. 34 of these were exploratory wells and 317 were exploitation or development wells. Our exploratory success for the second quarter was 71%, and of the development wells, 99% were successfully completed. I am going to cover briefly some area by area operational highlights now, starting in the Permian Basin.

In the Anton Irish field, this is a field you may recall we made a wildcat discovery here during 2001, this was in the Wolf Camp Formation. During the second quarter of this year we completed our seventh consecutive successful well in this field. Oil production from the seven wells has climbed to 2100 barrels per day. Devon owns 100% working interest in this field. In the Indian Basin, this is another Permian Basin property, we have now drilled six of the nine Cisco Canyon wells that we planned for 2002. Four of these wells have been completed and tied in. These four wells in aggregate are producing a thousand barrels of oil per day and 7 million cubic feet of gas per day. Our working interest in Indian Basin is 94%. In the Powder River Basin in Wyoming, we drilled 62 wells during the first half of 2002, 50 of those were drilled in the first quarter. We only drilled 12 wells in the second quarter. We typically suspend drilling during the second quarter for seasonal reasons. However, we did bring 50 previously drilled wells on to production during the second quarter. Our net production in this play averaged 88 million cubic feet per day during the second quarter. We are currently ramping drilling activity back up here. We expect to drill 90 Powder River wells during the second half of the year.

In the Washake Basin in Wyoming, we started drilling a 22 well package in June, we currently have two rigs running, we plan to increase that to three rigs later this month. The Washake is an area where we have a large undeveloped acreage position. We have about 200,000 net acres. And approximately 400 undrilled locations. The current production here is running 85 million cubic feet per day, and Devon's working interest is -- averages 85% over this acreage. One other property in Wyoming in the Jonah field, this is in the Green River Basin we completed a gas well during the second quarter that came in at better than 6 million cubic feet per day. Devon has a 50% working interest and we just recently got approval to drill two more Jonah wells.

Turning now to the Barnett Shale in the Fort Worth basin. In the second quarter we initiated drilling on 83 wells, we brought 108 wells on to production, and at the end of the second quarter, we had 39 wells that were being completed or waiting on a completion unit. At the end of the quarter we had 14 rigs running drilling Barnett Shale wells. Our current production from the Barnett Shale is 425 million cubic feet of gas equivalent per day. This compares to average net production of 337 million per day last December, and 373 million per day average -- or no, at the end of the first quarter. End of first quarter to end of second quarter production went from 373 million a day to 425 million a day.

In the Carthage Bethany area of east Texas we planned 15 wells for 2002. Nine have been drilled to date, eight of those nine wells were successfully completed. Production from those wells is currently 6 million cubic feet of gas per day and our working interest is about 90%. In the Cherokee Coalbed Methane play, this is our latest coalbed methane play in southeast Kansas and northeast Oklahoma, we drilled 13 wells during the second quarter, we tied 126 wells into the gas transmission system. We had had a large number of wells awaiting completion of the gas transmission system. That brings the total number of wells that we have drilled in the play up to 207, 170 of these wells are now tied into the transmission system in our dewatering, we are starting to see production climb. We are currently producing a little over 14 million cubic feet per day from this play.

Moving now to the Gulf and Gulf Coast region. We had 14 rigs running at the end of June. In south Louisiana onshore, the Pew number one well, we mentioned this well last quarter, that was tied into permanent production facilities in May. It is producing at a rate of 11 million cubic feet of gas per day and a thousand barrels of condensate per day. We have a 50% working interest in that well. In south Texas we have two wells in the Jennings Ranch area that were drilled in the second quarter. Devon has a 50% working interest. One well flowed at 7 million cubic feet per day, the second well is currently being completed and we expect it to produce about 4 or 5 million cubic feet per day.

Moving offshore now, we had several drilling successes during the second quarter. On the shelf at West Cam Blocks 534 and 536, we drilled four exploratory wells, all were successful. We issued a news release on this program on June 17th. What was notable about these four discoveries was that the locations were all selected using the latest four component 3D seismic exploration tools. The initial production from these four wells was 47 million cubic feet a day net to our interest. We have a working interest here that averages 84% in these four wells. We have four -- we have 660 square miles of this four component seismic data that we have licensed in the Gulf. And based on the success we saw with the first four wells we are jazzed about the exploration potential on our acreage.

At Eugene Island Block 305 we have a 100% working interest on this one. We completed a very good well during the second quarter and we have completed another in July. The first well is producing about 20 million cubic feet per day and 300 barrels of condensate. The second well is producing 10 million a day and 500 barrels of condensate a day. We are currently drilling our third well at Eugene Island Block 305. Again, that is a 100% working interest that Devon has. Also on the shelf at Eugene Island Block 330, we completed the third well of a three-well program that I mentioned last quarter. All three wells were successful. Combined production from these wells is currently running 1700 barrels of oil per day. Devon has a 24% working interest in this Block.

In the deepwater Gulf, you may have seen a news release that we issued in June concerning exploration success and Larry referred to it earlier as well. We have a 25% working interest in an apparent discovery on the Cascade prospect, that is at Walker Ridge Block 206. This is in 8,000 feet of water, so needless to say, the target size was large and we think we found it. We expect to spud an appraisal well on this structure during the second half of '02 or early in '03.

Also in the deepwater, we expect -- we saw first production from the Shell-operated Manatee project. Two wells in which we have a 48% working interest have been completed. Neither of these wells is performing up to our expectations so we are working with Shell to determine possible corrective action. It is too early to know what the ultimate outcome on these wells will be. Elsewhere in the deepwater, Chevron-Texas has delayed the spud date of our Cortez prospect until late August, or early September. The delay is related to rig availability. I will just remind you that Cortez is a 30,000 acre closure. [INAUDIBLE] Block 175. It lies in 3300 feet of water, the proposed total depth is 18,000 feet and the prospect has gross unrisk reserve potential of over 1 trillion cubic feet of natural gas. Devon owns a 38% working interest in Cortez.

We recently joined Chevron-Texas on another deepwater prospect, this will test 8,000 acre Subsalt prospect. The prospect is called Sierra. It is in 4100 feet of water, it is on Atwater Valley Block 187. The well has a target depth or will have of 26,000 feet. Devon is participating in this well with a 25% working interest. Obviously high risk exploration of the unrisk gross reserve target is 300 million barrels. We expect to spud a well here in mid-August.

Moving now to Canada, I'll remind you we had a very active and successful first quarter in Canada. As I mentioned earlier, the second quarter is typically a slower period. During the second quarter, we drilled 130 wells with an 80% success rate on our Canadian assets.

During the spring thaw, travel restrictions really slow down field activity until the roads dry in a lot of the basins where we operate in Canada. One area that was not impacted by this is the Lloyd Minister area, this is in east central Alberta, it lies on the Saskatchewan border. The year round access area we have a big inventory of low risk shallow gas and cold flow heavy oil locations. We've ramped up drilling at Lloyd Minister, we planned to increase production here from about 15,000 barrels a day to over 20,000 barrels per day by year end. At the end of the second quarter we had 10 rigs running. We drilled 45 wells in July, and -- no, I am sorry, in the second quarter we drilled 45 wells, in July we drilled another 92 wells, the success rate on these wells has run about 95%. Well expect to drill another 75 wells between now and year end. Our average working interest in Lloyd Minister is 98%.

In the foothills along the British Columbia-Alberta border, in the Grizzly Valley area, we are making progress in getting our gas to market. In July we signed a term sheet with Duke Energy. This will allow us to tie in three Grizzly Valley wells. We expect production to begin in the middle of December, at about 15 million cubic feet per day net to our interest. We have been drilling in Grizzly Valley for several years now in our joint venture with BP. One of our primary targets has been in the Deep Permian. I just want to mention that this is the same area where there has been some recent news about a big discovery in the Monkman area. We believe that our acreage in the area has gross unrisk reserve potential of a TCF or more. If you saw the news about the discovery in Monkman, we have previous discoveries here in the same formation.

Moving to the international areas. In China, facilities construction is moving forward according to plans on the Panyu project. We are building two offshore platforms. They will be installed in the South China Sea, and we have a goal of beginning production here late next year. We expect our net share of the production from these two platforms to peak at about 15,000 barrels of oil per day during 2004. On the exploration front, our team in China is interpreting 2D and 3D seismic. We expect to spud the first of two exploration wells on Blocks 1535 and 1602, we expect to spud the first well there near the end of the year.

In west Africa, the Rita exploratory well on the Marine 9 Block in the Congo was drilled during the second quarter, it was dry and has been P & A'ed. Due to our carry from the operator, Devon had no cost in this well. The next wildcats that we have scheduled for west Africa are for early '03, offshore Gabon and Ghana. During the second quarter, our producing field in Gabon averaged 40,000 barrels of oil per day. Devon has a 19% working interest in that field. In late July, we signed a new contract for the Kada Block in Ghana. This is the first deepwater contract signed in Ghana. It is 3.7 million acres, making it one of the largest drilling concessions in west Africa. We have a 580 mile, 3D seismic survey over the what we think is the most prospective part of the Kada Block. We expect to drill our first deepwater well on the Kada Block in the first half of 2003. Devon is the operator of this Block and we have a 56% working interest.

Moving across the south Atlantic from west Africa to offshore Brazil, we picked up a lease in the June lease sale. The BAR 3 Block covers 539,000 acres. This acreage complements our west African acreage in that same play concepts that we are working offshore west Africa are also present in Brazil. We will be developing leads on this acreage over the next year or two. We have currently have no drilling commitments on the acreage in Brazil.

In the midstream we had another busy quarter in the north Texas area. We connected 138 wells to our transmission system. Pipeline volumes ramped up 9% from 567 million per day in April to 619 million a day in June. Construction of the Plant Six expansion at Bridgeport, those of you that went on our recent field trip in the Barnett Shale may have seen this underway, that is on schedule for completion in early August. The actual plant start-up is expected in September. This expansion will add 200 million cubic feet per day of capacity to our Bridgeport gas processing facility. That will bring the total inlet capacity of that facility up to 650 million cubic feet per day. We also installed about 60 miles of new pipeline in the north Texas region during the second quarter. That ends my prepared remarks, and with that we will open the call to your questions.

At this time, I would like to remind everyone in order to ask a question, please press star, then the number one on your telephone keypad. We will pause for a moment to compile the question and answer roster. Your first question comes from Michael Young of Gerard Klauer.

A couple of questions here. The first would be, can you give us what the short-term debt figure was at June 30?

We -- I didn't quite hear you.

Can you hear me now?

Yes.

Okay. Just a couple of questions, the first being what was the short-term debt figure at June 30?

You know, we do have a commercial paper program. However, because we have a backstop facility, that is shown in long-term debt. So there really was no short-term debt at June 30th.

So the long-term figure is pretty representative of the debt outstanding?

Except for the cash in the bank and the fact that the Chevron exchangeables are offset by the common stock, that's correct.

Understood. On a more strategic level I was going to ask if the Company has considered, or would consider a switch to successful effort accounting, given the sort of repetitive nature that we see of these full-cost ceiling test adjustments.

Yeah, that is an interesting question. You know, full-cost is obviously -- has a crazy aspect to it. The problem we have in doing that, and we're going to study that in the second half of this year, is that to switch we are afraid would take a tremendous amount of time and shareholder money because we would have to go back and find the records of all the companies that we bought. If you just look at Anderson we would have to find NuMack and the several other companies and convert all those Canadian records over to U.S. successful efforts. And do the same thing for every other company that we bought going back and finding the Schneider Company that Santa Fe had bought. It would be a monumental undertaking that would cost we are afraid millions and millions of dollars to do, and obviously there would be no return for that. We'd rather put that money in to drilling oil and gas wells and generating shareholder return rather than just changing from one accounting method to another. But we are going to study that.

But it sounds like theoretically you're certainly not opposed to successful efforts methodology for any particular reason, et cetera?

During the 20 years we were a private company we were a successful efforts company so I spent half my life on one and half my life on the other. You can argue the merits of those up one side and down the other.

Excellent. The last question is perhaps, Vince could give us some production guidance. Maybe just in millions of BOE for the third and fourth quarter?

Yeah, if you -- if you take our beginning of the year guidance and look at the contribution that was assumed from the sale properties and you are left with a little more production for core properties in the second half of the year than the first half. I will -- I don't have a model in front of me, but our guidance really has not changed on the core properties whatsoever. Since our 10-Q filing.

All right, thank you all very much.

Your next question comes from David Cunny of Freedman Billings and Ramsey.

Some questions on the full cost. Vince, you guys used the $1.43 for your measurement. Is that what you said?

$1.43 Ako.

Ako. Right. Now, that prices have rallied up off of that, what -- do you have a cushion now off that, what your full cost ceiling cushion?

We have not calculated a cushion based on the $1.70 U.S. That Ako is currently running. But certainly, after taking the write-down, yes, we have a significant cushion based on current prices.

Okay, good. And I guess there will be a DD&A benefit. Right? From taking this cost write-down?

That's correct. We are modelling that right now for inclusion in the form 10-Q, but you can expect something around 30 or 40 cents a barrel company-wide for the second half of the year of lower DD&A rate. It will lower it about a dollar in Canada and then our property sales moved the U.S. rate up maybe 10 or 15 cents. When you do a weight average it will come in somewhere around 30 or 40 cents lower for a consolidated DD&A rate for the second half of the year.

Great. On the Barnett Shale, you guys were I think on the Barnett Shale school you talked about your six pilot program that was completed. Do you have an update on the status of the infill program?

No, we really don't have any new information on that, David. We are -- I mean, as you know, those wells were to gather information and we are still in that process.

All right, thanks. Good quarter.

Your next question comes from Robert Morris of Salomon Smith Barney.

Good morning.

Good morning.

Vince, I was wondering if you strip away the property sales in Canada, what was the sequential change in production on your core properties in Canada in the second quarter versus the first quarter?

Okay. Canadian production without core properties?

Just on core properties.

Without sale properties, yeah, core properties only. 16 million barrels, 16.073 million barrels equivalent for the -- for q1, 16442 million barrels equivalent for 02 -- those are 01 numbers. 16.7 million barrels for Q1, 16.75 million barrels for Q2. So roughly flat. Let me point out that the increase in gas prices in Canada caused the sliding scale royalties to increase during the second quarter, so our production growth in Canada is really understated by those numbers.

When you look at just the U.S. sequentially your total production was up more than 5%, which I don't think there were properties that you sold that drove that production growth. When you said that on the core properties overall for the Company that production was flat sequentially, what was it that offset the growth in the United States volumes sequentially?

Really domestic properties, you know, I said that it was up slightly, essentially flat, that is true in both the U.S. and Canada, Bob. For core properties.

Ok. So that 5.6% sequential up-tick in the U.S., sequentially was really driven by properties that you are selling?

Oh, in the reported numbers? No, that was driven by the fact that there was not a full quarter of Mitchell included in the first quarter numbers.

Okay. All right, good enough, thank you.

Your next question comes from Shannon Nome of J.P. Morgan Securities.

Thanks, good morning. Vince, as I recall, back at the Barnett Shale analyst session, you all had mentioned the likelihood of a downward impairment based on some performance issues up in the Powder River CDM area, have you had clarity on that? Are we basically just going to see that hit at year end in the reserve report?

At that meeting, you may recall, that we quantified the impairment, or the write-down of reserves that we expected in the Powder River Basin. And that number, 14 -- was that million barrels? Yeah, 14 million barrels equivalent.

What I am asking, is that already embedded in your DD&A rate or will it hit at year end or how is that done?

It is already embedded in our DD&A rate. Known changes in reserves such as discoveries or performance issues such as the Powder River, we take those into our reserve report currently and adjust our DD&A rate.

Okay. Then in Canada, I am making an assumption and correct me if I am wrong, but since there was no -- as I recall -- third quarter '01 impairment back the last time prices got weak, at least not in Canada, as I recall. Is it so that the bulk of the impairment you are taking this quarter would probably relate then to the Anderson properties?

You can't really draw that conclusion, Shannon, because we would have had a write-down at the end of September of last year had prices not recovered before our financial statement date.

That's right, I remember now. So the fact that you didn't take it in the third is related to the recovery in price as it is to the blending in of the Anderson deal?

That's correct. Of course, the more assets you have in Canada, when you get a ridiculously low gas price like we had at the end of the second quarter the bigger the write-down will be. By the way, those numbers were disclosed what they would have been at the end of the third quarter had prices not recovered.

Yeah, I seem to that remember that now.

The write-down would have been.

Finally, just very quickly, I guess asking a question a slightly different way, I know your guidance will be formally updated in a bit here, but can you indicate directionally which way overall North American gas production should be heading in the third quarter and fourth quarter? I am trying to get at are most of the North American sales complete at this point? Or are we still going to see more impact from North American sales in the second half?

Most are complete. There is the potential for some additional impact from asset sales, we do have some North American sales that are minor properties that are currently being negotiated. Directionally, we are seeing a strong growth out of the Barnett Shale, so I think that you can -- certainly our core properties you will see production growth in the second half of the year, and I suspect that on an overall basis you will as well. Do you have a feel for that, Brian?

We've got to wrap up some property divestitures in Canada, what we have considered and called phase two and phase three, we have a few properties in the lower 48 principally on shore to wrap up. We have a few more things to go which we hope to bring to conclusion in North America in the third quarter.

These are relatively minor compared to the properties that we have already sold.

That's correct.

Okay, very good, thank you so much.

Your next question comes from Irene Hawes of Sanders Morris Harris.

Hello, guys. If I may, two questions. The Monkman area you guys mentioned that you guys also have exposure to the Deep Permian play. I wonder how many leads you have with the average size and a little color on the hook-up time infrastructure, how it is set up. Secondarily, a little more color on Jonah. I want to know how much acreage you do have and how many wells you can drill within your holdings. That's all.

John, could you take the question on the Monkman area?

I sure will. Hi, Irene, it is John Richels. The Monkman area is really an extension of what we call Grizzly Valley. It is kind of an area to the northwest of where we have been drilling for a couple of years with BP, and we -- one of the things, in the Monkman area there has been about 20 years of production out of the triassic so there is a developed infrastructure system in that area. And we're just moving that infrastructure system now down through the Grizzly Valley area and across the border into the Narrowway area of Alberta. We have drilled a number of wells, I think we drilled 14 wells in that area over the last few years so we have quite a bit of gas behind pipe awaiting this infrastructure and we would have somewhere around 10 other identified structures in that area to the southeast of Monkman and in terms of size they would probably be in the 40 to a hundred BCF range.

As far as the infrastructure is concerned that has been a slower process than we would have liked to have seen. We have a deal with West Coast or now Duke Energy to build a pipeline first of all from -- on the British Columbia side from our discoveries in the Grizzly Valley area up to their Pine River facility and then out through the West Coast system. And that has been held up a bit longer than we had originally expected through regulatory process in -- and specifically a hearing before the National Energy Board which is the Canadian regulator that has jurisdiction in that area. What we're going to do is, we're going to tie in as Vince said three of the wells through a gathering system that we are putting in later this year. So we expect to see some production come out of that area late this year, and then in 2003, we expect the Duke extension to be finished on the B.C. side. And probably early 2004, although there is an outside chance it could still be in 2003, we would see that go through to the Narrowway facilities as well.

Thanks.

Your next question is from Shawn Reynolds of Petrie Parkman and Company.

Could you hold off on that there? We didn't answer the second part of the first question, which had to do with the Jonah field. Don DeCarlo, our General Manager of the division that has that field can respond to that.

Yeah, I mean, we have a small position inside the existing Jonah pressure cell that is currently being developed out there. We just recently received the first twenty acre downspacing permit about two weeks ago and we will be drilling two wells probably through September, October time frame which will pretty much get us fully developed on our modest acres position at 20-acre development. We also have substantial acres position outside the pressure cell. [INAUDIBLE] We recently completed the 3D and we would expect to be doing some exploratory tests late this year, early next year, on that acreage.

What is your net acreage in that general vicinity?

We have approximately 20,000 acres, both in and outside, the vast majority of our acreage position is outside the existing Jonah field.

Great, thank you.

Your next question comes from Shawn Reynolds of Petrie Parkman and Company.

What are the dollars you expect to realize from closed divestitures in the third quarter?

Shawn, it is Brian. We have about another $300 million to go, maybe a little higher, maybe a little lower. We have initiatives as you know going on, I talked about our initiatives in North America, Canada and the U.S. We've got some wrap-up to do internationally which we are working ahead on. Of course we will pay some taxes out of that. That will reduce it, although our goal is obviously to manage these acquisitions and to maximize the after-tax proceeds. So that is our target right now. We may be more or less, but we are already above the number that we had told people we would accomplish, last fall. We are clearly above that now and we will bring the process to a close in the third quarter.

Am I correct we have already closed a little over a $100 million in divestitures in the third quarter?

Right. We're already at -- on a net proceeds we are already up about a $100 million in the third.

Good. So if you closed the 300, then you have closed a hundred, then you have a total of 400, you would call it 400?

That's our target and we are working hard to get there.

Have you -- do you have an update to your CAPEX target for the rest of the year, or any changes?

Yeah, if you you -- actually, no changes to our CAPEX. We're right on track for our revised budget that was in our first quarter 10-Q. If you take the first quarter, which was -- included the winter drilling program, and then three times the second quarter capital expenditures you will come right in line with our guidance. That is where we expect to be for the full year.

Great, thanks.

Your next question is from Phil Tase of CSFB.

Good morning, how are you doing?

Fine.

A couple of things you spent half a year's worth of capital or so, your DD&A rate is tracking along pretty attractively. Does that imply that you are having a pretty good year from an DD&A perspective? Could you comment on that? And secondly, could you give us color on the number of prospects you might have, or leads associated with your four-component seismic play out in the Gulf?

Speaking -- this is Vince. Speaking first to the DD&A rate reflective of finding costs. We've gone out with target finding costs for the full year from all sources of 690 of BOE and I don't think we have seen any significant deviation in discoveries or development proformance or capital so I think we are still on track for some -- somewhere in that range. Now, what was the second part of your question?

Number of prospects associated with that 4C, seismic plan.

Bill?

Yes, I think that the number there, it ranges somewhere between 6 to 10 in terms of additional leads and prospects that we have got in the west Cameron portion of that effort that we had under four component shooting. The Eugene Island area is another area where we concentrated some investment in 4C. That survey is not developing in terms of the quality of that survey isn't as good as the west Cameron survey right now. So we are in the process of reprocessing that. I don't have any -- there is about two leads in there that are coming out on the Eugene Island area, but nothing has firmed up to date. West Cameron has been more encouraging.

Thank you.

Your next question comes from John Herrlin of Merrill Lynch.

Hi, regarding Canada, what's your transportation costs for the gas to get --

We can't hear you.

We didn't hear any of that.

What's the transportation cost to get the gas to Ako? You said what the --

I believe your question is what is our average transportation cost to get gas to the Ako in Canada?

I wanted to know what your wellhead realization was in terms of the tests?

The average cost to move gas from the wellhead to the Ako hub U.S. is about 13.5 cents. So, you know, to get the net wellhead price depending on your Ako benchmark is that should get you there.

Regarding switching the -- do you have an idea of a ballpark charge you would be facing in terms of any sort of adjustments or how much it would cost?

No, we have no idea. Are you asking the cost to implement that?

Yes.

No.

Okay, thank you.

Your next question comes from Ken Beer of Johnson Rice and Company.

A couple questions with your NGL's. You jumped about a million barrels quarter over quarter, obviously some of that comes from having Mitchell for the full quarter, but can you give me a sense --

We lost you on that. Could you start over. Hello? Hello?

Is that better?

You just came back on.

I am sorry. You jumped about a million barrels in your NGL volumes, obviously part of that is just having Mitchell form the whole quarter. Was there some volumes that just came from stripping out incremental liquid because of a change in gas price versus NGL pricing? Was it that arbitrage or was it all Mitchell volume both the whole quarter and ramping up for the second quarter?

Remember, Ken, there is a lot of variables that impact your NGL volumes other than just natural gas volumes. You pointed out a couple. The relative economics of stripping out NGL's versus leaving them in the gas stream, can impact our volumes. Also, one of our -- probably our fastest single-growing asset, the Barnett Shale, is a lot of that is liquids-rich and we do strip the volumes there. So, you know, it is not a -- there can be variability, the things that you have cited certainly impact it and there are also other variables that impact NGL volumes.

I am trying to get a sense as to whether, in the second quarter, there was more -- it was more attractive for you to pull more NGL's as opposed to leave it in the gas stream?

This is Darryl. We have a number -- the simple answer to that is we extracted 88% of the volumes that go through a processing plant we elected to extract ethane because it was more economically feasible to us. 12% depending on the area and depending on the plant, it was not economical for us so we sold it as gas. But for the second quarter, about 88% of the gas that is processed we did extract natural gas liquids.

How did that relate, I guess, to the first quarter? Was it -- was that 88% higher or lower?

The first quarter would have been a little higher than that. You know, probably in the 95 to 96% range.

Okay. That is great. Thanks again, guys.

Your next question comes from John Wolff of Wachovia Securities.

Good morning. Carrying a goodwill balance of $3.7 billion and given the adoption of SFAS 142, I know unit depletion conceptually, what is the economic test going to look like going forward on that balance sheet item?

Well, from a conceptual perspective, you compare your goodwill balance plus the capitalized costs of your oil and gas properties to the fair value of your oil and gas properties. If in fact the fair value of your properties was less than the capitalized costs, plus goodwill, you would have an impairment.

But the idea that you are not writing it off as you produce the reserves kind of sets you up to have to take some kind of charge at some point, I would think?

Not necessarily. We don't have a goodwill impairment this year, and if the Anderson and Mitchell assets, those acquisitions, generated most of the goodwill that we have on the books, if those assets continue to perform as we hope they will the fair value will go up and not down and we might never experience an impairment of goodwill.

Second question on the balance sheet. It looks like you still have about $3.50 to $4 a barrel of debt which is more than half above the industry average, I am just curious, where do we go from here after the -- these -- these round of asset sales?

We can -- you know, in terms of where we go from here, we're obviously going to bring the divestiture process to a conclusion. At the beginning of the year our debt reduction strategy included investing non-core assets, increasing our hedge position, which we have done that, and I think most of that has been disclosed, to protect the cash flow. Our goal is obviously to protect the cash flow so we can fund our capital budget.

We had also said that we would use cash that we generate in excess of that capital budget to pay down debt and we obviously will intend to do that. As we conclude this year, we expect the debt total at year end to be less than this for a number of reasons. As we move into 2003, and 2004, and we set our budgets and look at prices and continue to protect with hedges, we will again apply cash flow and bring that total down.

One other thing I would point out is debt per BOE is not a good measure for somebody as heavily in the midstream business as Devon is. We have over a billion dollars worth of mid-stream assets which is atypical for an E & P, large cap E & P company. And so, you know, just looking at the reserve units, it is perhaps not the best way to look at it.

Do you have an update of where mid-year reserves are or what the total divestitures are, is it around 300 million barrels still?

The question is, do we have an estimate for what the total reserves associated with divested assets --

Or a midyear reserve number.

In round numbers, we're at about 1.7 billion barrels. Again, a number of those barrels that we divested were -- the majority of barrels will be international barrels. I always caution people to recognize that we go to value and not necessarily to barrels. I believe the majority of the barrels we have divested were in Indonesia. I think we will eventually bring all these divestitures up and tally them for you. But I don't have that figure right now.

Thank you, guys.

Your next question comes from David Temmeren of Stifel Nicholas.

We have run over the hour, we will take the last question from David and we will cut it off.

Thanks for squeezing me in, Vince. A quick question, you guys, you know, disclosed in the earlier press release, we talked about this, Vince, about the Raton Basin. The property sale being swung into the divestiture package, I wanted to know if I could get a little more clarity on that and just your general thoughts about the Powder in general. I know you talked in the past the difficulty of operating from both an environmental and governmental standpoint. I want to know if, you know, -- I don't know if you would tell me if this was the case, but I want to know if you would look at divesting yourself of the wildcat considering the property has been a little bit below expectations? I want to get your thoughts and feeling on that.

Thanks.

Yeah, the -- on the Raton Basin, that was our smallest property, the coal bed methane, it was nonoperated, it was operated by another party, who was not originally on our list of things to sell. They came in with an offer that we found most attractive.

Before Larry says too much, let me insert that we had a right of first refusal issue, actually the purchaser does, on that property and we are not yet in a position to disclose the purchaser nor the price we received. We are happy with the price we received and as soon as that issue is cleared up we will be glad to talk about it. But we are contractually bound to keep that undisclosed at this point in time.

That was my next question.

With regard to the Powder, you know, we can make a lot of money in the Powder River Basin, we have no plans to sell the Powder River Basin at all. It, like all areas in the west, where you are on federal lands, you have environmental perceived problems. There is a group of obstructionists out there that does their best to stop activity anywhere. In fact I was reading an article yesterday about how they were trying to stop a windmill project in Virginia -- or in Pennsylvania. The environmental obstructionists will fight any kind of project anywhere. Including wind turbines. That just goes with our business.

You know, we try and operate in a way that has the least impact on the land to act in an environmentally sound way, and -- but there are people out there that will try to slow you down anywhere. That is part of the inevitable delays you face, whether it comes from pipeline disruption or forest fires or whatever. We grind all that in to our assumptions so when we make our forecast for the year we recognize that not every project will go as planned. There will be other projects that will go better than planned. And while the Powder is being delayed at the moment because of the EIS, there is other projects that are going faster than planned. We balance all that in and the fact that one area is suffering momentary delays, that just goes with the territory.

Okay. Thank you very much.

In balance, let me just thank everyone for your participation in this call. And needless to say if you have any other questions, please call us directly. We will be here all day, and if Vince can't answer it, he will refer your call to whoever can. So thank you very much for your attention. Bye.

Thank you for participating in today's Devon Energy second quarter earnings conference call. This call will be available for replay beginning at 12:30 p.m. Eastern standard time today. Through 11:59 p.m. eastern standard time through 11:59 p.m. on August 8th, 2002. The conference id number for the replay is 4927184. Again, the conference id number for the replay is 4927184. The number to dial for the replay is 1-800-642-1687. Or 706-645-9291. This concludes today's conference call. You may now disconnect.