德文能源 (DVN) 2002 Q1 法說會逐字稿

Ladies and gentlemen thank you for standing by. Welcome to the Devon Energy's first quarter 2002 results conference call. We will conduct a Q&A session later. At that time, if you have a question, you will need to press the 1 followed by the 4. As a reminder this conference is being recorded Thursday, May 2, 2002. A replay of this conference call will be available 11am Mountain Time on May 5th through 3pm Mountain Time May 9th. To access dial 1-800-633-8284. Reservation number 20496921. Before I turn the call over to Larry Nichols, Chairman, President and Chief Executive Officer with Devon, I will read the Safe Harbor. On behalf of Devon's management I will remind you any statements that the company makes today that are not based on historical fact are forward-looking statements. Actual results may differ materially. Devon's form 10K for the year ended December 31, 2001 includes the company's estimates for the year 2002. In addition includes a discussion of factors that could cause Devon's actual results to differ from the company's estimates. Devon's management encourages you to review form 10K. Please go ahead sir.

Good morning. Thank you for joining us. The purpose of this call is to discuss Devon's first quarter 2002 results. I will make a few general remarks about the quarter and turn the call over to Vince White. After that you will have the opportunity to ask questions. And has been our practice for the time we will have all key managers and officers here for your questions. The first quarter was a very active and successful one for Devon. First we substantially completed the integration of Anderson the acquisition we closed in October of last year. Then beginning this quarter in January, we closed our acquisition to Mitchell. Later in the quarter on March 25, we completed a $1 billion debt offering. And as you have seen from our various announcements we made signature progress on our $1 billion plus divestiture plus. We have announced $1.2 billion sales to date. Inspite of that flurry of activity, we had an excellent quarter with the drill bit. In the United States we drilled 424 oil and gas wells with a 99 percent success rate. In Canada we had our most successful winter drilling program ever. We drilled 276 wells during the first quarter with a 88 percent overall success rate. That adds up to 700 wells that we have drilled this quarter in North America, the highest drilling rate and the highest success rate we have ever had. The drilling success and the acquisitions of Mitchell and Anderson drove oil and gas production to the highest levels of any quarter in this company's history. Despite the fact that we had sharply lower commodity prices, this company generated $75 million in net earnings, excluding special items available for the common shareholders. Very pleased with those results. The 1 billion in [INAUDIBLE] we issued in March completes the debt restructuring we undertook following the acquisition of Mitchell and Anderson. $8.2 billion in debt at the end of the first quarter. We are on track to meet or beat our original goal in [INAUDIBLE] As you know these properties that we are selling out of our portfolio clean up the portfolio by getting rid of the higher cost, lower profit wells. At the end of the first quarter we already received about $225 million in sale proceeds. As we closed the remaining sales during the next few months, we will apply those proceeds to debt reduction as was the plan announced last year. Our weighted average interest rate for all debt is currently running a little over six percent pre-tax and under three percent after tax. Remarkably cheap debt. The amortization schedule for all debt is structured favorably. After applying the proceeds from the property sales, we will not have any required principle payments until 2004. More than half of our debt matures at dates beyond 2010. We also have working capital and amounts available under existing credit agreements of almost $1 billion. Furthermore we expect to fund our 2002 capital spending entirely with cash flow from operations. So we remain very liquid, with lots of financial flexibility. With that I will turn it over to Vince.

Thanks, Larry. Before we get into the financial discussion for the quarter, I want to remind everyone that's on the call by telephone they should have received a fax or e-mail copy of this morning's press release. The total release is eight pages. Anyone that did not receive the release or received an incomplete copy may obtain the press release from the website. Www.Devonenergy.Com. One other item before we get to the financial results of the quarter. During the call I will refer to our estimates for 2002 production price realizations and expenses. These estimates were included in our form 10K filed with the SEC for the year ended December 31, 2001. Now that we have a couple of months of history with the Mitchell assets and we know the closing dates for most of our asset divestitures, we will be revising our 2002 guidance. I don't expect any big surprises in the revisions. We will mainly tweak the expected price realizations, expenses and quantify the production and expenses to the assets we are divesting. These will be published in our first quarter form 10Q. That [INAUDIBLE] will be filed in the next couple weeks. Those of you that maintain earnings models on Devon will want to keep an eye out for the filing. If you would like to receive automatic e-mail notification of the filing as well as for other Devon news items you can sign up for the service on our website. Now, turning to the quarter. We had first quarter earnings before special items, that is the earnings number that is comparable to the analysts consensus estimates were 75 million. That is 48 cents per diluted common share or 25 cents over the first call consensus estimate. The positive surprise there really relates primarily to lower than expected operating expenses and income taxes. That level of earnings translates to cash flow per common share of 2.84 for the quarter or 2.75 per share diluted. That compares to the consensus cash flow estimate on first call of $2.37 per share. I want to remind you that we completed our Mitchell acquisition in late January. So Mitchell's operations are included from the last week in January forward in the first quarter. As a result, our first quarter 2002 results only include the contribution of the Mitchell properties for a little over two-thirds of the quarter. Our full year 2002 results will reflect a little over 11 months of operations from the Mitchell assets. Moving now to the details of the quarterly results. Looking first at oil, gas and NGL production. Company-wide production was 51 million equivalent barrels for the first quarter. That is a 66 percent increase or 20 million barrels over the first quarter of 2001. In the fourth quarter of 2001 we reported 44 million equivalent barrels of total production. On a sequential quarter basis production increased 16 percent in the first quarter of 2002. In the first 24 days of January, that's prior to closing the Mitchell acquisition, the Mitchell properties produced 2.4 million equivalent barrels. Had we closed the Mitchell transaction on the first day of the year and owned the assets for the first quarter we would have reported 53 million barrels of oil equivalent production. That compares to Devon, Mitchell and Anderson combined for the first quarter of 2001 of 50 million equivalent barrels. First quarter 2002 versus first quarter 2001 Pro Forma combined basis, this is really the same store sales number, production was up about six percent in the first quarter of 2002. In light of the fact that we were in the process of bringing these companies together, we are very happy with these results. I'm going to move now to product prices. No one will be surprised that oil, gas and NGL's prices were all lower during the first quarter of 2002. Our price realizations were down across the board. Oil prices were down 23 percent from year ago levels. Gas prices down 63 percent. So, inspite of the record high oil and gas production total revenues declined. Our price realizations versus the benchmark prices were pretty much in line with the guidance that we gave at the beginning of the year for most areas. I want to touch on a couple of exceptions. First our floating oil price realization in the U.S. of $18.39 a barrel was almost a dollar under our forecasted range. We forecasted that U.S. oil price realizations would come in between $1.35 and $2.35 below NIMEX. In Canada, however our floating oil price realizations came in about $1 better than expectations at $17.59 per barrel. They are still within the forecasted range, but they are about a dollar over the mid-point of that range. These variances pretty much offset each other. To provide you with the best possible guidance, we will review our full year. On the natural gas side, our first quarter U.S. floating gas price realizations came in at 2.05 per NCF. That's 29 cents under NIMEX, and right in line with the guidance. In Canada the floating gas prices came in surprisingly strong at 2.28 per NCF. Six cents under NIMEX and 19 sent above the top end of our forecasted rate for the year. This happened because we sold a lot of our Canadian gas on a daily basis or fixed term short-term contracts based -- it turned out that this had a very favorable impact on our Canadian gas price realizations during the months of February and March. Going forward, we think our beginning of the year guidance which was for Canadian gas realizations to be 25 to 50 cents below NIMEX, we still think that's good guidance for future periods. I will move to other income. It totalled 14.7 million in the first quarter. This was $10 million over our expectations. About 7 million of that is from items that are nonrecurring. The biggest nonrecurring item was a $3 million gain we recognized in the first quarter on the settlement of Canadian contracts with Enron. Even after you back out the 7 million of nonrecurring items, other income expenses exceeded our expectations by about 3 million. It looks like our previously provided guidance is probably light. We will revise this in our upcoming form 10Q. I'll remind you that with the close of the Mitchell acquisition in late January, we became a big player in the mid-stream. That is in gas processing and pipeline operations. Marketing and midstream revenues were 160 million in the first quarter of 2002. That is in line with our expectations at roughly 2/11ths of our full year forecast. The associated cost and expenses those are shown in the line item entitled marketing midstream expenses those totalled 125 million for the quarter. We had about 35 million of net revenue. That's in line with our expectations. We expect our mid-stream margins to climb going forward, as we own the operations for the full quarters and also as production grows in the Barnett Shale. I do want to caution you that while mid-stream margins are pretty predictable over the long run, there can be a lot of quarter-to-quarter volatility. This occurs because of the changes in spreads between gas prices and natural gas liquids prices. Our mid-stream margins will also vary with changes in through-put caused by increases or decreases in production volumes. Moving now to the expense section of the income statement. Most of the line items were in line with our guidance. I will only touch on a few items that variated from our expectations or that had nonrecurring components or unusual variances during the first quarter. The first expense is 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, these expenses came in about $22 million under our expectations for the first quarter. LOE came in at 170 million which is about 11 -- between 11 and 12 million under our expectations. The big drivers were the weakening Canadian dollar. In U.S. dollars expenses are lower. And also lower than forecasted work over expenses in the first quarter. In the future, our total lease operating expenses will increase as we own Mitchell for the entire periods. On a BOE basis, our first quarter lease operating expense was only 336 per barrel. That's down almost 50 cents from the fourth quarter of 2001. This really reflects the high quality of the assets purchased in the Mitchell and Anderson acquisitions. In any case, as we look forward and we continue to high grade our property base by selling noncore properties and by growing our core areas, we expect Devon's production and operating expenses to be very competitive. Production taxes came in at 22.3 million for the quarter. That's 10 million less than our guidance. Our beginning of the year guidance was that production taxes would run 4.2 percent of oil and gas sales. The first quarter actual came in at 2.9 percent of oil and gas sales. One big driver here was the benefit we received from our hedging activity. Our hedging revenues, while they are reported as oil and gas sales, they are not subject to production taxes. We had about 66 million of hedging benefit recorded as oil and gas sales in the first quarter. When you back out the effect of the hedges, it looks like our beginning of the year guidance for production taxes was too high. We will be providing a new estimate for production taxes when we revise our guidance in form 10Q. Next item I want to cover is general administrative expenses. They were 49 million for the first quarter. That was between 2 and 3 million higher than we expected. The biggest contributor was a nonrecurring item 2.9 million in severance cost. We still think our full year G&A expense will be within the range of our previous guidance. I want to point out on a unit of production basis general and administrative expenses came in at 96 cents per barrel for the first quarter of 2002. That compares to 85 cents per barrel in the fourth quarter of 2001. The big driver for this is the impact of our mid-stream operations. So bear in mind while our mid-stream is expected to contribute around 200 million of operating margin, we will not record any production volumes as a result of those mid-stream activities. While the G&A on a BOE basis is relative to our historic norms our operating margin is also expected to increase. That should be up almost $1. In any case, when you compare Devon's G&A per barrel of production to our historical numbers, or to our pierce that don't have significant mid-stream operations you are making an apples to oranges comparison. Last expense item I want to cover is income taxes. The first quarter they totalled 22 million. That's about 26 percent of pre-tax earnings and 21 million of the 22 million in income taxes were deferred or noncash. That leaves the current income tax piece of 1 million. That's only a little over one percent of our pre-tax earnings. I want to caution you that is not indicative of our expectations for the full year. Due to the gains that we expect to recognize on the property dispositions that we have coming up, we expect to have a significant current tax liability later in the year. In any case, we are going to review our guidance before we file our form 10Q. Before we move to operational highlights, I want to mention a couple of special items. These are unusual or difficult to forecast items that the Wall Street analysts usually exclude from their published earnings estimates. In the first quarter these special items had a negative impact on net earnings of 21 million before income taxes. Or 13 million after tax. The after tax impact translates to a decrease of about 8 cents per diluted share. The biggest item here was the application of FAS-133. That accounted for 17 of the 21 million pre-tax. That's in the line item described as change in fair value of derivative instruments. I will now turn my attention to first quarter operating highlights. Capital expenditures for exploration and development projects during the first quarter totalled about 450 million. You may notice that is well in excess of one-fourth of our full year of exploration and development budgets. I want to point out this occurred because our Canadian budget is front-end loaded. That's by design because many of the areas in Canada that we drill in can only be accessed in the winter. We tend to spend a large portion of our Canadian budget in the first quarter. At the end of the first quarter we had 56 rigs running company-wide. 43 of these were on Devon operated wells. During the quarter we drilled 718 wells. 189 of these were classified as exploratory. That leaves 529 wells classified as exploitation and development wells. Of the 189 wells classified as exploration wells, 62 were Cherokee coal bed methane wells. If you exclude those, all of those were successful, by the way, our exploratory drilling success rate was 79 percent for the quarter. On the 529 exploration and development wells, our success rate was 95 percent for the quarter. Looking area by area first at the [INAUDIBLE] continent we finished the quarter with 25 rigs running in the [INAUDIBLE] continuant. We continued our string of successful wells. We own 100 percent working interest here. The Lancaster well that was -- Lancaster number one well that was tested when we last reported, that well has been successfully completed. We also completed the Lancaster number 2 and Jackson number 1 wells in this field during the first quarter. Combined oil production from our six new operated Wolf Camp formation wells in the Anton Irish field is running a little over 16 his barrels a day currently. We are also drilling an offset well. A well in an offsetting fault block. If that test is successful, it will set up several additional locations in that field. We are having a lot of success there. In the Fort Worth basin, we initiated the drilling of 103 Barnett Shale wells in the first quarter. 96 were brought onto production. At the ends of the quarter 57 wells were waiting completion or tie-in to the gas transmix system. In the first quarter we refractured 19 previously completed Barnett Shale wells with good results. At the end of the quarter we had 14 rigs running in the Barnett play. To give you an idea of the growth we are experiencing. In December of 2001 Mitchell's net Barnett production averaged 346 cubic feet per day that compares the month of March the end of the first quarter 2002 net Barnett was 373 million cubic feet per day. We had about a seven percent growth rate over the quarter. In our Cherokee coal bed methane project this is the newest coal bed methane project we have in Southeast Kansas and Northeast Oklahoma, we drilled 62 wells in the first quarter. That brings our total wells drilled here to 194 wells. You may recall we began drilling operations here in the middle of last year. We have now tied in 44 wells to the transmission system. First gas sales on the Kansas side of the play began in November. And as you might expect, with a coal bed methane project production volumes will not reach a significant level until we have completed a dewatering phase. We are continuing to build out the gas transmission system for the Cherokee area as well. In the Permian mid-continent, we are planning to launch a coal bed methane pilot project on Devon acreage in North Louisiana. Key element of our growth strategy is to look for new opportunities to apply skills and technologies we have developed elsewhere and this is an attempt to do that. We think coal bed methane opportunities are present throughout North America and our history of success with coal bed methane gives us a distinct advantage in uncovering new plays. Moving to the Rocky Mountains, we had 12 rigs running for most of the quarter. 7 on coal bed methane wells in the Powder River basin and five working conventional areas. We drilled 50 new Powder River methane wells in the quarter. That brings the total too date that Devon has drilled from the Powder River coal bed methane plate to 1423. Our Powder River basin coal bed methane production averaged 95 million cubic feet per day in the first quarter. That was from 1,118 producing wells, as you can see we have a number of wells we are in the process of tying in. Near the ends of the quarter drilling activity was focused on the pilot projects we have in the deeper Big George coals. We are continuing to look hard at the Big George. In the Ratone basin coal bed methane play we have drilled 80 new wells. This is over half of the year's planned drilling activity. Production climbed to about 12 million cubic feet per day net to Devon's interest. Moving now to the Gulf of Mexico. In the offshore Gulf of Mexico and the onshore Gulf Coast, we had 16 rigs running at the ends of the first quarter. Over the first quarter we averaged about 12 rigs running. The results of this drilling were very positive. Starting with the Gulf Coast in Goliad County, Texas we had a discovery at the Hunter number 1. This was mentioned in the year-end call. This was followed up by another successful well in the first quarter the Tailor number 1. We expect to have both these wells on stream later this month. And we expect production of these two wells combined to be five to six million cubic feet per day. We have a 63 bears working interest after payout in those bells. We are evaluating an additional drilling location there as well. In Zapata County in South Texas or the Zapata area in South Texas we completed 11 successful wells in the first quarter. Production is currently running net to Devon's interest at 11 million cubic feet per day. In South Louisiana, the Pew number one was brought on line in March. We have a 50 percent working interest in the well. Once permanent production facilities are operational, we expect somewhere around June for that to happen, our gross production is expected to be between 10 and [INAUDIBLE]. Offshore on the shelf, the West Cameron 536A-11 well encountered 107 feet of net pay. We began producing the well in February at 17 million cubic feet per day. This is a 100 percent Devon well. Also in the West Cameron area we logged 130 feet of pay at West Cam 534A-9. We have 100 percent interest there. We logged 96 feet of pay at West Cam 532A-8. We have two-thirds of working interest. These wells are currently being completed. We think that each of them is capable of produce -- growing production of about 15 million cubic feet per day. Also on the shelf, we had good results at Eugene Island block 330. Two successful wells were completed in the quarterly. These came on production in April at 1200 barrels of oil per day. A third well is currently drilling. We hold a 24 percent working interest in this block. We have a three-well program under way at South Marsh Island 128. We expect to complete the wells and begin production in July. Gross production is expected to start at about 5,000 barrels of oil equivalent per day. We have a 17 percent working interest in South Marsh Island 128. In the deep water Gulf of Mexico, we completed the drilling of the second well at our Shell operated Manatee project. The well came in as expected, encountered the reservoir sands we expected. Construction of the sub-sea facilities are under way. And well completion should start later in this quarter. We expect to have our first production by mid-summer. We expect the rate from this project to be about 10,000 barrels per day net to Devon's interest. Also in the deep water Gulf the Cascade exploratory well on Walker Ridge block 206 is currently drilling. This well was spudded on January 30th. It lies in 8300 feet of water. Total depth for this well is a little over 26,000 feet. We have a 25 percent working interest and we should have results for you on this well in the second quarter. Later in the second quarter we expect to begin drilling on our Cortez prospect. That is on Port Idobel block 175. It lies in 3300 feet of water. Has a proposed total depth of 18,000 feet. This well is operated by ChevronTexaco. Devon owns a 25 percent working interest. We are excited about this well because it will test a 20,000 acre four-way closure and has gross unrisked potential of more than a trillion feet of natural gas. Wrapping up the Gulf. We recently participated in Federal lease sale 182 Devon was the high bidder on four blocks on the shelf. If all of those blocks are awarded. Net cost to Devon will be 2.4 million. I will move to Canada. As Larry mentioned we had an active and successful program in Canada. This program included a lot of activity on the assets we recently acquired in the Anderson acquisition. At the peak of the winter drilling season in January, we had 60 rigs working in Canada. By the end of the quarter, as the winter drilling season was winding down, we were down to 19 rigs running in Canada. During the first quarter, we drilled 276 wells in the winter drilling program. The results were immediately reflected in the 2.5 percent sequential quarter production increase. That's comparing end of quarter exit rates. That is year-end exit rate and first quarter exit rate. The results of this program, we talked about in a news release we made earlier this week. If you haven't seen the release, it's available on our website. I will quickly cover some of the highlights. In the foothills of Northeastern British Columbia, in the Grizzly Valley area, we tested the OJ A-3 well in the first quarter tested at about 9 million cubic feet of gas per day. Based on the test data this well is really only modestly successful. Another well in this area the exploratory tests of the Murray complex. We mentioned this well on the previous call. It was abandoned due to a tight formation. We have 49 percent working interest in each of those wells. In the Hamburg Lady Fern area of Northwestern Alberta we drilled 7 slave point Pinnacle wells in the quarter. Four of the wells were successful. They have combined deliver built of 17.5 million cubic feet of gas per day. Three will be tied in this year and one will be tied in during next winter's drilling season. In the deep basin of North Western Alberta, this is an area where we have been trying to get a foot hold for a number of years. It's difficult to obtain acreage. One of the attractive aspects of the Anderson transaction was we got a very large land base in the deep basin from Anderson. In the first quarter we had a very successful drilling program here. We participated in 33 wells with a 91 percent success rate. Through the winter drilling program we increased gas production by 10 million cubic feet per day. We expect to add another 17.5 million cubic feet net to Devon when our Elmore gas project is completed. We expect that sometime in the month of May. Reserve additions for the deep basin also came in above expectations. I don't have an exact number. We were pleasantly surprised. We expect this area to be a source of continued growth for Devon in the future. Finally in Canada, I want to mention the success. Well we drilled this winter in the McKenzie Delta. The TUC-M18 well encountered 200 BCF of gas. This is a Devon operated well and we have a 50 percent working interest. I want to point out this is the first successful well drilled in the onshore McKenzie Delta since 1975. This places Devon among a small group of producers who own gas reserves in this area. You may have heard us say before we have the largest acreage in this area in the industry player. On the international front we have largely completed our goal of pairing back our operations to a few select areas. I will update you on those areas. First in China, in the Pearl River Mouth basin, we are continuing to construct facilities at our offshore Panu development project. First oil from this two-field development is expected in late 2003. We expect our net share of the production to peak at about 15,000 barrels of oil per day some time during 2004. In West Africa, we are waiting on a rig to drill the test well on our Rita prospect. This is offshore Congo. It lies in about 4300 feet of water. The unrisked growth reserve target for this prospect is over 250 million barrels. Devon has a 42 percent working interest here. We hope to begin drilling sometime in May. And I just want to remind you that under the terms of our joint venture agreement, our partner picks up almost all of the capital cost of this well. In Arjugagon this is the ACG field in the Caspian Sea where Devon has a a.6 percent interest in a super giant oil field. Production is currently running 120,000 barrels per day from 13 wells. Full field development has begun. Production from Phase One of this development is expected to add up to an additional 400,000 barrels per day of gross production in 2005. Phase Two of full field development will be sanctioned later this year and production is expected to plateau at a rate of over one million barrels per day beginning in 2010. A detailed engineering study on the main oil export line is nearing completion. And project sanction is scheduled for June of this year. Our 5.6 percent interest is a carried interest. That is we are carried on all capital cost until project pay-out. We will not receive significant production from this field until we reach pay-out. However, beyond that point this field holds a great deal of potential for Devon. Quickly, before we open up the call to your questions, I want to give an update on our mid-stream activities. As I mentioned, our gas processing and pipeline operations increased [INAUDIBLE] in size and scope as a result of the Mitchell acquisition. Our mid-stream group recently began constructing a 200 million cubic feet per day plant expansion at our Bridgeport plant in North Texas. This Bridgeport facility that's owned by Devon is one of the country's largest MGL plants. It processes a good deal of the gas that flows from the Barnett Shale play in the Fort Worth basin. Production from this play continues to ramp-up rapidly. The gas through-put in our North Texas pipeline systems increased from 526 million btu per day in January to 563 million BTU in March. That's growing as well. Incidentally the newer East Barnett Shale field is now the largest gas producing field in the state of Texas. Devon has the dominant position in that field. That ends my prepared remarks. At this point we would like to open up the call to your questions.

Ladies and gentlemen we will now begin the Q&A session. If you have a question, you will need to press the one followed by the four on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered and you would like to withdraw your polling request you may do so by pressing the one followed by the three. If you are using a speaker phone, please lift your hand set before entering your request. One moment please for the first question. [PAUSE] Ellen Hammond with Bear Stearns, please go ahead.

Good morning. Just a couple questions. One is on the Cherokee coal bed methane play. Could you give us some idea what your current production is now and what you are looking for for production in the area? The second question in the Powder River, if you could comment on the recent regulatory issues that have come up out there?

This is Rick Clark. Let me speak to the Cherokee issue. We are, as noted in our press release, continuing to expand our infrastructure, continuing to drill. As you know, or noted, the Cherokee basin, particularly in the Kansas side is going through the dewatering phase. Our production there is just exceeds about a million -- excuse me a million per day currently. Our Oklahoma production continues to maintain about a six to seven million cubic feet per day. Again we are working through the issues of infrastructure and continuing to grow it. Our expectations continue to be, as we move towards the end of the year in or around near the 20 million volumes combined between Kansas and Oklahoma. In that GSH -- again that is still dependent upon the dewatering infrastructure we are beginning to work with.

This is Don DeHarlo, in regard to your question regarding the Powder River basin. There have been a few events in recent weeks. One is the current environmental impact study there occurring on Federal lands. It's currently in the public comment phase. The EPA has questioned some of the -- there are some concerns there in regards to the water use and some of the air issues out there. We are following that very closely. We expect that hopefully that will get resolved within the next 30 days or so. If we can get EPA's concerns mitigated hopefully the EIS will move forward. The plan is EIS should be completed stimulate in '02 possibly could slip to early '03. As we get additional information we will pass that on. In addition I think you are probably referring to a recent Interior Department Board of Land Appeals ruled that three leases from one of the operators out there were ruled as being invalid. As a result of some concerns that when those leases were issued, that complete environmental analysis was not done in all the, you know, current environmental techniques were not utilized. That's a very recent ruling. I'm in Denver today meeting with an industry group to discuss the ruling and make sure that industry's voice is clearly understood in regards to that. We certainly don't think there was anything done wrong there, and we will be following that issue very closely, also.

Great. Thank you very much.

Irene Hawes with Sanders, Morris, Harris. Please go ahead.

My question has to do with slave point -- firstly, a great quarter and really encouraging. Sounds like you guys are firing on all cylinders. Regarding the Lady Fern slave point project I understand you have full discovery of seven. Just kind of curious as to why the other three didn't work? They show up well on seismic and what were the surprises once you drilled?

Don, are you on the line to address that question?

I am. Hi, Irene, it's don Rochelles. What we are pursuing in that area is Pinnacle Reef plays. Those slave point Pinnacle Reefs are hard to see on seismic. We have been very successful over the years not with standing the difficulty reading that seismic. Generally in the area success rates would be in the one and three or one and four. Even with a four out of severn we are happy with that kind of a success rate. We, as you know we shot a large 3D seismic program over that area this year. And we are kind of testing the limits of that 3D. But, as I said, we are quite happy with that.

Just can you expand on, is it because you can't locate the Reef? Or is it once you locate it, once you get in the porosity didn't work out? I just want a little color. I would degree four out of seven is good.

The guys are puzzled over one of them. They are still looking at the seismic to determine exactly what we have. We saw the same kind of seismic signature we've seen in previous drilling, and it was actually the first well where we missed the structure. We actually hit an abayment there. That was an unusual thing for us to do. In other cases we have hit the structure and it's been tight or wet.

Kenneth Bear with Johnson and Company, please go ahead with your question.

Hi, guys. I actually had a couple of operational questions or guidance questions. Vince you mentioned the LOE came in better than we were working for. Part of that might be you didn't have very many workovers in the first quarter. Do you see that picking up and therefore LOE going up or because of the sale of the higher cost properties, that would have the effect of pushing LOE down so the first quarter is a pretty good number to go off of?

Certainly, Ken, the properties that we are selling have higher average LOE costs than our core properties. That would tend to have -- to push unit costs that is LOE per unit of production down. Countervailing forces could be strengthening of the Canadian dollar, increased workovers of activity, and as we drive production higher, continue to drill new wells overall lease operating expenses will go up. We are currently in the process of evaluating our full year budget looking at the impact of the properties we are selling. And we should have a little better guidance for you when we file our form 10Q in the next couple weeks.

Okay. Just a couple more quick ones. On the tax side, I know this is a moving target, but you said that obviously when you sell properties, you will have some current taxes going out the door. If you exclude the tax effect of selling properties and just come back to just the operating properties that you have going forward, will you still have -- what will the tax effect be on just the Pro Forma, ongoing properties? Will there still be a higher than expected cash tax being paid on the Pro Forma remaining properties? Or is that all tied to the sale of properties?

Um -- Ken, that is tied to the sale of properties. But, as you'll notice in our tax guidance, our current and deferred, and overall rates are highly variable with our level of earnings. So, you know, you can't just make a blanket assumption without a price deck. And an earnings level in mind. But you will see us take a look at that guidance, although I don't really expect our tax guidance for 2002 to change.

Okay. Then on the DD&A I don't think you mentioned anything on DD&A, but I think it was lower than guidance. When you sell some of these properties, will DD&A rates possibly go up? Down? What's your thoughts there, kind of looking forward?

Well, first, Ken, let me point out that DD&A came under our guidance because of our better than expected drilling results in the first quarter. Especially in Canada. As far as going forward the variables that impact DD&A expense asset sales, that's true. We have gotten some pretty good prices for the assets we have sold. So I don't expect them to have a big impact on DD&A. Other variables will be continued drilling success. So if we continue to have a kind of year that we have had so far, we can see some downward pressure on DD&A going forward.

Right. Last one, then I'll stop. You said first quarter to first quarter you went from 50 million to 53 million. Just out of curiosity, did you do the same exercise looking at fourth quarter to first quarter? Was that flat or was that also up? Or did you not look at that?

We have looked at that, Ken. And actually, fourth quarter to first quarter Pro Forma combined Devon, Anderson and Mitchell, production was just about flat on a daily rate basis. There were fewer days in the first quarter than there were in the fourth quarter. However, I want to point out what the big driver was there. It came from the timing of liftings from our Indonesian oil sales. That is unlike for domestic properties, under the accounting rules we can only recognize foreign oil sales when the oil is actually taken out of the tanks and loaded onto the tankers. That tends to be big chunks, if you will, of oil production that come in periodically. So we had a fairly significant decrease in Indonesian oil production, obviously since we have sold those assets, that won't be a factor going forward. Does that answer your question?

That does. Just to understand, the first quarter, the loadings were lower, or the fourth quarter they were lower?

They were lower in the first quarter of 2002. What we call liftings. Which is where you take it out of the tanks and put it onto the tankers. That's the point which we recognize oil production internationally.

If you exclude that your first quarter was up very slightly from the fourth quarter?

I would say flat.

Thank you, guys.

Shawn Reynolds, please go ahead with your question.

I want to circle back to the Powder a little bit. On the MRO ruling, I'm wondering if you are thinking that that has a very company specific ruling, or is this something that could expand to cover all the operators in the Powder?

Let's let Bryan Jennings, our Senior Vice President of Corporate Development, address that.

As Don pointed out, we are obviously following the recent ruling from the Interior Department Land Appeal Board. Obviously Marathon is in a much better position to comment on the Pentico leases. We don't see this impacting Devon. Of course in all instances, you know, we follow the procedures and policies set forth by the various government agencies that regulate us. Including the Interior Department and the EPA. That's the way we have always done business. That's the way we will continue to do business.

At least in the press releases that we are seeing, it seems like there is some very specific actions or lack of actions associated with Marathon. Is that true? Or is -- were their practices considered industry standards?

As Don pointed out, the issue related to the BLM's action prior to the lease sale, I think Marathon is in a much better position to comment on those specific leases. I want to remind you this is driven to those specific leases.

Right. Okay. That's what I really wanted to know. Just with regards to the Ratone, what are the long-term plans there? It seems like we have been there for awhile. Seems like we drill alot of wells, but net production is, you know, fairly meager. What's the longer term outlook for the Ratone?

This is Don. In regards to the Ratone, we believe ultimately there's probably potentially to drill anywhere from 600 to over 1,000 wells in that play. We have currently drilled roughly 300. This year's program, I think Vince alluded to how many wells we have drilled. Vast majority of the wells have not been put on production. Of the 70 or 80-some odd wells we drilled we have only put about 20 on. Gross production in that field has gone from 22 to 23 million a day up over 32 million a day currently. Production is walking up. As we put these new wells on, and as the older wells continue to dewater and hopefully production walk-up, we would expect, throughout the year for production to ramp-up slowly. So over time, as we develop the thing fully, we would expect we are going to continue to drill in the range of 100 to maybe even as many as 150 wells a year. So we expect to slow, long-term ramp-up in production over the next two to four years out here.

Okay. Great. And then, Larry, is it too early to start talking about, you know, '03 and looking at the cash flow and -- free cash flow situation, and what you might want to do with that?

I think the answer is yes, it is too early.

Okay. Thanks a lot.

Robert Morris of Salomon Smith Barney, please go ahead with your question.

Good morning, gentlemen.

Good morning.

I had a couple questions. One, on the Barnett Shale you said you were running 14 rigs. That's fewer than last quarter. Is that because you are seeing better production or production overall? Or if you could give us a little color there on why that has come down.

This is Rick Clark. As you recall late 2001, we had as many as 18 rigs at one time. We are currently at 14. The key driver there is the efficiency on the equipment specifically. In reducing to that rig number, we are currently have improved our efficiency per well, and I'll use this factor from late last year, mid last year of 1.6 to 1.7 wells per rig per month drilled. That has improved to about 2.3 wells per rig per month. So the efficiency has greatly improved. And -- so we are drilling roughly the same number of wells as we did under a 18-well drilling program.

Obviously at a lot lower cost, then, too?

In addition to that as well.

Thanks. Second question I had was on the Big George coals you tell us you are continuing with focus there in the Powder River basin. I know you said last quarter you had two of the pilots producing gas to sales. I was wondering what the volumes are running currently, and on the two additional pilots you were begun to begin this year, what stage those are at?

As far as the pilots, we have during the quarter, just got those things hooked up in a large way. We were actually venting some gas out there for a period of time until we got the infrastructure in. Currently producing one million a day from one of the pilot productions. Drilled a substantial amount of wells around both areas that we will be hooking up during the course of the year. The other pilot which is a combination Big George wide back deeper coal project down to House Creek is producing in the range of three million a day. I think earlier in the year we were at a million a day. It's walking up slowly. The other two pilots we are still working through some regulatory issues there. Haven't put it back on production yet. The fourth pilot would be our Juniper Draw pilot. We are seeing some good news last week. We received our water discharge permit and anticipate putting that project on line, probably around the middle of the year. Late June, early July timeframe. Some of you may recall this is a pilot where we actually encountered up to 150 to 200 feet of continuous coals of some of these wells. It's deeper in the basin, very, very thick coals. It will require dewatering phase but we are very, very encouraged about the potential at Juniper Draw.

Thank you.

John Herland with Merrill Lynch, please go ahead with your question.

Most of my questions have been answered. I was wondering if you could address what kind of volumes you will be losing in the sales going forward? Just a rough estimate.

John, this is Vince. The way we are planning to address that, of course we have given our beginning of the year estimates for all properties identified for sale when we presented in New York on December 12th or 13th. I know you have those numbers available, John. As far as actually quantifying the quarterly impact of the property sales, we are working up those numbers now, not just production, but operating cost and impact on DD&A. We will Pro that data in our form 10Q in the next couple weeks. It's not that I don't want to give it to you, we are still compiling that data. Bear in mind this covers a large number of minor interests in addition to the big sales like Indonesia. It's taking us some time to compile the data.

Thank you.

Ray Deacon please go ahead.

Vince, what do you we with activity levels throughout the remainder of the year and CAP-X by quarter if you have that?

Yeah, we have not forecasted CAP-X by quarter. I would think our capital spending, other than in Canada, would be relatively equally apportioned between the remaining quarters. Canada, of course we broke out our capital budget by country. In Canada, we spent a little over half of our planned capital in the first quarter. So that should give you some sense. For the rest of the year we ought to see the budget pretty evenly spaced.

Okay. What do you see for, you know, Barnett Shale production through year-end? Do you still have significant capacity there with the plants that are coming on line? I just looking for order of magnitude and order of growth production between now and earned?

This is Darrell Smidian. I will address the plant issues. As Vince indicated in his presentation we are currently installing an additional train in the Barnett Shale area. That has capacity of 200 million a day. The target date to bring that on stream is October 1. Rick is here and he can talk about the ramp up in volumes out there.

Again, this is Rick. We are continuing to match the plant's expansion. As you noted with our increase in volumes over the quarter-to-quarter quarters, you saw 2+ percent increase per month. We really planned to continue that through the rest of the year.

Okay. And where is production now? Net production?

The net production, net drive was 300 -- excuse me I'll get the exact numbers. 373.

Thank you. Just one more quick question on the Big George. You know, some other operators seem extremely bullish about the potential for the Big George. You know, what's your feeling ultimately in terms of reserves net to you guys that you may be able to adhere? How much, if anything, do you have booked for the Big George?

On the booking side, at this point in time, we don't -- I don't believe we have any reserves -- approved reserves booked there at all just because it's very, very early in the phase. Those numbers could vary wildly. I hate to speculate on that. There's certainly a strong believe the Big George have higher gas don't the coals are thicker. The expectation is on per well basis we are hopefully looking at something in the range of double what we would see in a Wyadac well. It's very very early in the Big George to speculate on reserves.

Thank you.

Michael Young with Gerard, Klauer, Madison and Company. Please go ahead.

Good morning. Vince, could you summarize, not the production volumes, but the actual reserves that have officially been agreed to sell at this point? Can you break that out by region? Canada, U.S. and Indonesia. If possible can you disclose the aggregate sale price for each of those three regions?

You know, Michael, we estimated in total the reserves by geographic area associated with the properties that we plan to sell. We have not varied, in a big way, from those original estimates. However, for both the protection of the buyers and to allow us to be accurate with our disclosures, we have not broken down the sales the way that you are asking us to. And we don't plan to. We will tell you what we sold in aggregate by country when we complete it. And, in fact, the press releases that have gone out have aggregated the reserves we sold. I don't have those in front of me.

Okay.

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