德文能源 (DVN) 2004 Q1 法說會逐字稿

Hello, and welcome to Devon Energy Corporation's first quarter earnings conference call. At the request of Devon Energy, this conference is being recorded for instant replay purposes. At this time, I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Welcome to everyone, and thank you for joining us today for Devon's first quarter 2004 conference call. I'm going to give a few introductory remarks and then Larry Nichols, our Chairman and CEO will review the highlights of the quarter. Following that, our President, John Richels, will cover the operations for the quarter, and at that point, our CFO, Brian Jennings will review first quarter financial results, and then we will wrap up with Q&A. As usual, we will limit the call to one hour. But we will be around for the rest of the day for any follow-up questions that you might have.

Before we get started I have a couple of compliance items to cover. First, I want to remind everyone that when we provide forward-looking information as we will in this call, we run the risk, if not the likelihood, that our actual results will differ from our estimates. For a discussion of risk factors that could cause actual results to differ from these forward-looking estimates please see our form 8-K that we filed on February 5, that included our full year 2004 forecast. We will be updating some of this guidance in the call today. And we will document the updated guidance in a form 8-K that we will put together and get filed in the next couple of weeks.

The other compliance item that I have concerns non-GAAP performance measures. We will utilize non-GAAP measures in this call. And disclosure rules require that we reconcile those measures to the closest GAAP performance measure, and explain why the non-GAAP measure is useful. That information is available on our web site, that address is www.devonenergy.com. With those items out of the way I will turn the call over to Larry.

Thanks, Vince. The first quarter of 2004 was really an excellent one for Devon. Setting a variety of records. Total production averaged more than 700,000 equivalent barrels per day, the highest of any quarter in Devon's history. Average daily production rates were up on a year over year basis both as reported and pro forma for ocean. They were also up on a sequential quarter basis. Higher production, strong oil and gas prices drove total first quarter revenues to a record 2.2 billion. Net earnings rose 13% over the first quarter of 2003 to a record 494 million for the quarter. Cash flow before balance sheet changes also hit a new record, 1.2 billion. While not a record, we generated earnings per share of $2 per share, beating the first call mean of $1.84 per share.

The pace at which we can continue to generate excess cash flow is allowing us to rapidly approach an important financial objective. That is accomplishing cash on hand, accumulating cash on hand, to cover all of our debt and maturities for 2004, 2005, and 2006. Cash paid for capital expenditures in the first quarter was 890 million. Leaving us with about $300 million in free cash flow during the first quarter. That obviously says we're averaging about $100 million per month of excess cash flow. This allowed us to repay $211 million of debt in February, and to increase cash on hand to $1.5 billion at the end of March 31. In April, following the close of the quarter, we put in place a five-year $1.5 billion revolving credit facility. We have nothing borrowed against this facility today, and have no current plans to draw against this facility at all. However, the facility did allow us to repay $635 million of 2006 maturities, without sacrificing any liquidity. This was all done after the end of the first quarter. Through today, we have repaid $846 million of debt this year, and still have approximately $1.1 billion of cash on hand earmarked for debt retirement. When we are comfortable that we have all of our debt maturities through 2006 covered, we will at that time consider additional dividend increases, and/or a share repurchase program. In view of the relatively high commodity prices we are currently experiencing, and in view of Devon's low relatively -- relative equity valuation, we believe that buying back our own stock is a very attractive alternative.

Before I turn the call over to John and Brian, I want to make a few comments about finding and development costs. For the full year 2003, Devon's drill bit only for just that year, our F & D was $15.01 per barrel. Significantly higher than that of most of our large cap peers. We are becoming increasingly confident that we will lower F & D significantly this year. Although we're only four months into 2004, we are one-third of our way through this year's capital program, and are very encouraged by the results of our capital investments to date. John will talk more about the successes we've already achieved with the drill bit. We also expect to invest about 60% less capital this year on developing already proved reserves. We can do this because last year we spent about $1 billion on developing the PUD and that $1 billion significantly reduced the percentage of PUD reserves in relationship to total reserves. Developing PUDs adds cost without adding new barrels. So allocating fewer dollars here will also lower F & D. As I said, we're increasingly confident that Devon will show a significant improvement in F & D costs in 2004.

Before I turn the call over to John, I want to acknowledge some Devon employees at our Worland plant in Wyoming. The Worland plant has operated 39 years without a single lost time accident. That is really an amazing achievement and we're very proud of them for doing that. Now I will turn the call over to John Richels. John?

Thanks, Larry. We had a very active first quarter in the field with 102 rigs running company wide at the end of March. Of the 102 rigs, 62 were Devon operated. Our first quarter rig count peaked at about 140 when the Canadian winter drilling program was in full swing. Capital expenditures for exploration and development in the first quarter totaled $664 million. And we drilled 623 wells during the quarter. 107 of these wells are classified as exploration wells, of which 85% were successful. The remaining 516 wells were classified as development wells, and 95% of those were successful. So in every respect, we had a very active and productive quarter with the drill bit.

More than half of the wells that we drilled during the first quarter were in Canada. Where drilling activity is concentrated in the winter months when the frozen ground allows us access to areas that are wet and inaccessible at other times of the year. We typically spend about half of our Canadian capital budget in the first quarter, and this year was no exception. With about $350 million invested in the first quarter. We got an early start to this winter's program due to an early freeze up, and most of the completed wells were tied into production on schedule. Although, we did experience fierce competition for service providers. Our overall success at getting new production on line quickly is reflected in our first quarter Canadian production. Normally, we expect to see Canadian production decline from the fourth quarter to the first quarter, and then pick back up in the second quarter, as wells drilled during the first quarter are brought onstream. However, this winter, despite very high industry activity levels, and related delays encountered in securing some services we were able to offset the normal sequential quarterly decline and keep our first quarter production from declining.

Also on a year over year basis, first quarter Canadian production increased by 6,000 barrels equivalent per day, or about 4%. We drilled a total of 323 wells in Canada during the first quarter. With an overall success rate of 90%. Our most active areas were in northeast British Columbia, the Deep Basin, and the Northern Plains. In aggregate, we drilled about 70% of our first quarter Canadian wells in these three areas. I will cover a few of the more notable successes. In the first quarter, we continued our development in the Grizzly Valley, which you will recall is in British Columbia, where we tied in two wells at OJ that added 13 million cubic feet per day of gas net to Devon. We continued to generate growth in the Deep Basin, at Leland and at Bilbo. We placed four wells on production at Leland adding 19 million cubic feet of gas per day. A 24 million cubic foot per day plant expansion at Leland made that possible. We see further opportunities to extend this Leland play to the west. Also in the deep basin in the Bilbo area, our relatively new infill program is having very good results. Three new wells added 8.6 million cubic feet per day. We are also evaluating several additional infill programs for the Bilbo area.

You may recall that we sanctioned 100% Devon-owned SAG D which stands for steam assisted gravity drainage, heavy oil project last fall. We call that product Jack Fish. The project is proceeding as scheduled through the regulatory process. And we anticipate receiving approval in late 2004 or early 2005. Front end engineering work is about 70% complete at this time, and we drilled an additional 8 appraisal wells in the first quarter. We have confirmed our water supply source for steam production in that area and we also identified a suitable water disposal zone so it appears that everything on the Jack Fish project is moving along well.

Onshore U.S. beginning with our largest field, the Barnett Shale Field in north Texas we continue to be very active in that area. Currently we have 13 rigs running in the Barnett Shale, 3 drilling vertical wells and 10 drilling horizontal wells, we tied in 43 new wells during the first quarter. And average production from the Barnett during the quarter held flat to the fourth quarter at about 575 million cubic feet equivalent per day. This was above 15% ahead of our first quarter 2003 production, of just over 500 million cubic feet equivalent per day. We are anticipating some production decline in the next couple of quarters. However, based on the success we've had with horizontal drilling both inside and outside the core area, we are becoming increasingly confident that we can reverse this decline down the road.

The Barnett is clearly heating up from a competitive perspective and you heard a lot about that recently. If our competitors’ economics are good in the Barnett, then ours should be even better. Our average acreage cost in our 90,000 net acres in Johnson County for instance is about $25 an acre. So Devon clearly has the first mover advantage. Several of our peer companies are just now gathering acreage and attempting to establish a meaningful presence here. However, to keep it in perspective, remember that Devon is producing about twice as much gas as the other 30 companies in the play combined. We drilled more than 1700 wells in the play, we drilled the first horizontal well in the play, and we've now drilled and completed 76 horizontal wells. By far more Barnett horizontals than any other company. We have 510,000 net acres in the Barnett, including 390,000 net acres outside the core area. This includes 90,000 net acres in Johnson County, and 50,000 acres in Parker County, to the south of the core area. It includes 178,000 acres in Wise County to the west of the core area, and 36,000 acres in Denton County to the east of the core area. We have 160,000 acres of 3D seismic data inhouse, and we are acquiring 3D data on another 140,000 acres this year.

In one way, the flurry of new participants is helping Devon. These wells are being drilled -- these wells being drilled by our competitors are increasing publicly available data on noncore Barnett acreage. Since we have by far the largest acreage position in the play, the new participants are essentially helping us to evaluate our acreage with every new well they drill. At the same time, we are drilling, gathering seismic information, and experimenting with various drilling and completion technologies. As a result, we are assembling a very large body of information that will continue to help us to move towards optimization of our massive acreage position.

The progress we're making is beginning to show up in the numbers. Our 76 horizontals are currently producing almost 100 million cubic feet of natural gas equivalent per day or more than 15% of our field wide Barnett production. Of the 76 producing horizontals, 28 are outside the core. Initial production rates from the last three horizontal wells that we completed outside the core averaged 3 million cubic feet per day. We've had good drilling results to the east of the core area in Denton county, to the west of the core area in Wise county and to the south of the core area in Johnson and Parker Counties. Based on the success we're having outside the core, we're allocating an additional 68 million dollars of our existing 2004 capital budget to the Barnett Shales.

Moving now to the Rockies and the Washakie Basin of Wyoming, we had, as many as six rigs running during the first quarter. We put 14 new wells on production in the quarter. With three more being completed at the end of March. We're currently producing about 87 million cubic feet of gas per day [inaudible] Devon from the Washakie. In the Powder River Basin, we drilled 45 coal bed natural gas wells in the first quarter. This compares to just 10 wells drilled in the first quarter 2003. 27 of the 45 wells drilled in the first quarter were deep Wyodak or Big George wells and our primary drilling focus this year will continue to be on these deeper coals. Our net production from these deeper horizons is currently running about 34 million cubic feet per day, or about 50% of the 77 million a day we're making in the Powder.

We had a very good start to the year in our southeast New Mexico gas play, in the Permian Basin. We drilled six Devon operated wells in this play in the first quarter with average initial production rates of about 4 million cubic feet per day, including an offset to our 2003 Devonian discovery the Rio Blanco 33 1, which is producing 10 million cubic feet of natural gas per day. We have about a 40 --sorry about a 50% working interest in these wells and plan to drill a total of 20-30 of those wells this year.

In the Patterson fields in south Louisiana, we had a notable success with the [Zenar] A 16 well. This well was already producing 10 million cubic feet of gas per day but looked to have some additional potential. In the first quarter we added perforations, exposed new reservoir and more than doubled production to 24 million cubic feet of gas per day. We have a 50% interest in that well. We also plan to drill at least one exploratory well here this year.

Offshore, on the Gulf of Mexico shelf, we initiated production from our Grades field located on Galveston 424. We drilled the initial Grades discovery well in April, 2003. Followed by two additional successful wells later in the year. All three wells were brought online in February. While this was behind schedule, due to weather delays and getting the pipeline completed, the three Grades wells came on as a combined rate of 37 million cubic feet per day of gas and 60 barrels per day of condensate, net to Devon's interest. We also had two exploratory successes on the shelf during the quarter. First, the deep shelf [Dekalb] prospect on Eugene Island 142 was drilled and logged 110 feet of net pay. The bottom interval of the well was completed and tested at a rate of 1200 barrels of oil per day and 2 million cubic feet of gas per day. The well is expected to be online early in the third quarter, after the facility and pipeline installation is completed. Devon has 30% interest in this well.

The second well, the East Cameron 335 D 11 well, on a prospect named Red Hot, tested a Pleistocene sand section and found 41 feet of net pay. The well was brought online in late March and is currently producing 12 million cubic feet of gas per day. Devon has a 40% interest in this well. Also at east Cameron, the 335 A 10 well, called Red Wolf, is now drilling and we own 100% of it.

In the deep water Gulf of Mexico, we tied two more satellite wells, at the [Nansen and Boomvang] complex. However, these wells are not performing as well as we had hoped. The east Boomvang, 688, number 8, is shut in, due to an equipment malfunction, but we hope to have it back on by the end of the second quarter. The east Boomvang 686 number 2 was brought online in February as planned, but watered out in April. We were expecting about 3800 barrels per day, net from the two wells combined. Combined production from the Nansen Boomvang complex averaged 40,000 equivalent barrels per day net to our interest during the first quarter.

At Red Hawk, on Garden Bank 877, the south spar has made into the topside and the assembly is on location, first production is expected on or ahead of schedule sometime in the third quarter of this year at about 60 million cubic feet per day of gas net to our interest. Also at Magnolia which is located on Garden Bank 783, construction of the tension lake platform continues. The 10,000 ton hull assembly completed its voyage from the fabrication yard in Korea to the Texas coast and toe out is planned for early July. First production is expected around the end of the year with an expected peak rate of 2005 of 9-12,000 barrels equivalent per day net to Devon.

Turning to our deep water Gulf of Mexico exploration program, the fourth well in our joint venture with Chevron Texaco was spud in mid March. The Jack prospect as is called is located on Walker Ridge 759, and it is a lower tertiary, four-way sub salt test that is on trend with our previous discovery at St. Malo. The well has a proposed target depth of 31,000 feet, should reach the objective in early July. Following the drilling of this fourth and final commitment well in the Chevron Texaco joint venture, we will have earned 25% of Chevron Texaco's interest in 71 deep water blocks. The rig is on location to drill our first -- to drill the first appraisal of our lower tertiary discovery at St. Malo. Which you heard a lot about at the end of last year. And that's located on Walker Ridge 678. This is actually going to be a reentry and deepening of an existing well bore called Data Point which is located on the east plank of the St. Malo structure. Assuming positive results from the appraisal, we will begin firming up a development plan. And just as a reminder, Devon has a 22.5% working interest in St. Malo. We don't yet have firm timing for an appraisal of our other lower tertiary discovery at Cascade, however we do expect to drill a well before year end to delineate our 2003 Miocene discovery on the Sturgis prospect. Also during the quarter, Devon participated in the central Gulf of Mexico lease sale, which is held in mid March, and Devon and its partners were high bidder on nine shallow water and five deep water blocks.

Internationally, we had nine rigs running at the end of the first quarter and during the quarter drilled a total of 17 international wells. Most of these wells were development well and our success rate was 94%. In China, the Devon operated Panyu project in the South China Sea is exceeding expectations. Gross oil production from the twin Panyu offshore platforms has surpassed 70,000 barrels per day, for 14 wells, with 12 phase one wells remaining to be drilled. During the first quarter, Devon's net production share averaged 18,500 barrels per day. This stronger-than-anticipated production performance, coupled with higher-than-anticipated oil prices, will result in reaching the exploration cost pool payout this month which is earlier than originally anticipated. Despite an earlier payout, our share of Panyu production should average 16,000 barrels per day for the full year. In Equatorial Guinea, offshore West Africa, the Zafiro field also continues to exceed expectations with current gross field production of more than 275,000 barrels per day. Devon's net share averaged about 57,000 barrels per day in the first quarter. However, we reached cost pool play at the beginning of April, so our share of production will be reduced going forward. Obviously, as is the case with Panyu, this is good news and bad news, since it means that those projects have been extremely profitable, but payout and of course finding production volume decrease were reached earlier than originally forecast. In that regard we estimate that the reduction, our reported production at Zafiro will be about 7,000 barrels per day.

In Egypt, our production averaged about 9500 barrels per day in the first quarter. The C 5 well at El-Zeit came on production in February and is currently producing about 4,000 barrels per day. Also in Egypt, the Gebel El-Zeit 1 A side track well that we were drilling in the first quarter was plugged and abandoned. We have no further drilling commitments on that block.

And finally, offshore Brazil, our exploratory well in block BMC 8 is scheduled to spud in early June. Devon will be drilling that well with a 60% working interest. This prospect has a net rift target size of about 40 million barrels. So that concludes my remarks and I will pass the call to Brian to review the quarterly financial results.

Thank you, John. First, as a reminder, for those comparing our first quarter 2004 results to our first quarter 2003 results, since the Ocean merger closed in April of 2003, first quarter 2003 results do not reflect any impact from the Ocean merger, while our first quarter 2004 results reflect a full quarter of the combined companies' operations. As you would expect, just about every category of revenue and expense is up in 2004, reflecting the impact of the merger.

First, looking at production, our first quarter 2004 production of oil, gas, and NGLs came in at 64 million barrels of oil equivalent or 703,000 equivalent barrels per day. This represents a 43% increase over the 492,000 barrels per day that we reported in the first quarter of 2003. With most of the increase due to the Ocean merger. Adding the 166,000 barrels a day that Ocean produced during the first quarter of 2003, to our reported results, gives you total pro forma first quarter production for Devon and Ocean combined of 658,000 barrels per day. So on a same store sales basis we increased first quarter production 45,000 barrels a day, or 7%. On a sequential quarter basis, production increased by 7,000 equivalent barrels per day, right at a 1% increase over our fourth quarter rate.

Looking forward, several developments that John and Larry mentioned have reduced our expectations for full-year 2004 production. The most significant is the shift in our expectations for the Gulf. In particular, our forecast for Nansen Boomvang has come down due to the production issues that John mentioned. In addition production from some of our Gulf onshore and shallow water shelf properties failed to meet our expectations. Finally, the earlier-than-expected payout of Zafiro year and Panyu that John discussed, and resulting from higher-than-anticipated oil prices, will reduce Devon's reported share of production from these projects by about 1.1 million barrels for the year. This happened in spite of the fact that these projects are outperforming our expectations, on a gross production basis. We now expect full-year 2004 production to come in between 251 and 256 million barrels equivalent. This represents a 2% reduction from our previous guidance. We now see second quarter production coming in between 62 and 63 million equivalent barrels. In the second half of the year we now expect production to total between 125 and 129 million equivalent barrels.

Moving now to natural gas price realizations, first quarter 2004 Henry Hub gas prices were 89 cents lower than in 2003. In spite of the lower benchmark prices, Devon's first quarter 2004 gas price realization increased 21 cents to $5.05 per NCF. There are several drivers for this $1.10 per NCF improvement in realized prices. First, hedge is negatively impacted our first quarter 2003 realization by about 60 cents in MCFE. In addition the Ocean merger increased the percentage of gas we produced in the gulf where we get our highest price realizations. And finally, Rocky Mountain gas price realizations improved significantly. While Rocky price realizations were about $2.38 below Henry Hub in the first quarter of 2003, the differential closed to about 86 cents below Henry Hub in the most recent quarter.

Devon's first quarter 2004 floating oil and gas price realization, that's the price we receive for our production that is not subject to collars, swaps, or fixed price sale agreements, was in line with our guidance with just a couple of exceptions that I will briefly cover. Our floating oil price in the gulf came in at $34.33 a barrel, or just 79 cents under NYMEX WTI. This compares to a forecasted price of $2.50 to $4.50 under NYMEX. Please note in the quarter a an accrual adjustment from a prior period increased our realizations by $1.52 a barrel. Without this adjustment our floating price realizations in the Gulf would have been $2.31 under NYMEX WTI.

Floating gas price realizations for the Gulf also came in better than expected. Our realized Gulf price was $6.03 per MCF was a 34 cent premium to Henry Hub. This compares to a previous guidance of a nickel to a quarter under Henry Hub. The better-than-expected realizations in the gulf resulted from the higher BTU content of our gas production. We are currently reviewing our expected Gulf production mix going forward to determine whether or not we will need to revise our full-year differential guidance.

Moving now to marketing and midstream in the first quarter marketing and midstream revenues were 417 million, and associated operating expenses were 332 million. This generated a marketing and midstream margin of 85 million, exceeding the midpoint of our forecast by 55%. Based on this performance, and our outlook for the remainder of the year, we are raising our 2004 guidance for full-year marketing and midstream margins to between 250 and 270 million for the year. That's an increase of 40 million over our previous estimate.

Moving now to expenses, on a unit of production basis, most first quarter expenses came in well below our forecast. Per unit lease operating expense, transportation expense, depreciation, depletion, and amortization expense, and G&A expenses, all came in below the bottom of our forecasted full-year range. We are pleased with this trend and hopeful that we can sustain this performance in coming quarters. We will wait, however, to see at least one more quarter's actual results before we consider modifying our per-unit forecast for any of these expense categories. We do expect second quarter G&A to reflect a one-time $6 million charge for abandoning office space in Calgary, as we consolidate our office locations.

Moving now to interest expense, it came in at 118 million for the first quarter. This is about 10 million below our guidance. Based upon our current analysis, we expect full-year interest to be in the 475 to 485 million dollar range. Or some 40 million below our previous guidance. There are a couple of drivers. First, in April, we prepaid 635 million of debt. And thereby eliminated the interest expense on that obligation. Second, we now estimate that 65-75 million of our 2004 interest will be capitalized. As opposed to the 25-30 million we originally forecasted. The 65-75 million is consistent with the interest capitalized during 2003. These savings will be partially offset by a one-time noncash write-off in the second quarter, of 16 million of unamortized loan costs, associated with the prepayment of our term loan. When you put this all together, we expect to report net interest expense of about 130 million in the second quarter and 115 million in both the third and fourth quarters.

The final expense item I want to cover is income taxes. Our first quarter 2004 income taxes were 282 million, or 36% of our pretax income. 72% of our total income taxes were current, the remainder deferred. This is in line with our previous guidance, and it is indicative of what we expect for the full year.

Cuting to the bottom line, we've reported net earnings for the first quarter of 494 million, or $2 per diluted share. The noncash items that are typically excluded by securities analysts in their published earnings estimates are detailed in our press release. In aggregate, these items decreased our first quarter diluted earnings per share by one cent. Adjusting for these items we had earnings of $2.01 per diluted share, or 17 cents better than the First Call mean. That level of earnings translates in a cash flow before balance sheet changes of approximately $1.2 billion for the quarter. In summary, we had a quarter of strong production growth, record revenues, earnings and cash flow, and lower than expected expenses across most categories. With that I'll turn the call back over to Vince, who will open it up for q-and-a.

Operator, we got the first caller on?

Thank you. We will now begin the question-and-answer session. If you would like to ask a question, please press star one. You will be prompted to record your name. To withdraw your request press star two. One moment please for the first question. Mark Meyer of Simmons and Company, you may ask your question.

Good morning. First question is for John Richels. John, the 28 noncore horizontals that you cited, could you give us a little more detail as to kind of the county by county distribution, and whether that 3 million a day that you cited is biased to one particular area?

I would be happy to do that, Mark but I'm going to turn it over to Brad Foster who is in charge of that area. Brad?

Mark, just to give you a little more detail on that, of the 28 wells outside the core we have 8 in [Wise] County, and the average IP in [Wise] County has been about 2 million a day, we're currently making about 7 million a day with a little bit of oil in that area. In Denton County, we have ten horizontals, and the average IP out there has been for us about 2.1 million, and we're making about 8.9 million and a little bit of oil out there. And Parker and [Tarrant] County, I kind of put those two together because it is a project we have down there that have wells in the same area and we're averaging about 1.8 million a day in that area, and we're making about 2.4 million. And then in Johnson County we actually -- it has a 331 we were making about 2.5, but right now, we have four horizontals down there, and we're making about 4.3 million. And that is down there -- it has been about 1.4, the last well we brought on has IP'd at about 2. So we think we're improving down there, also. As you can see, most of the areas we've been about -- IP in at about 2.0 million a day.

Okay. What are the --

Bear in mind -- this is Vince -- bear in mind that when it gives you the average rates a lot of those wells have been producing for over a year. So you know, they're 50, 60% off their initial production rates.

Right. What are those wells costing you? The latest ones?

Pardon?

The well costs on the latest horizontals?

The well costs? They average all over the place. Let me just kind of give you -- let me give you a couple of instances. A typical Barnett well, like down in Parker County, we drilled the wells in about 10 days. When you get up into the northern area of the Barnett, where it is a little harder rock, more calcareous, it is a little tougher drilling and those take about 30 days, so our drilling costs, if you look on average and look at it from the whole play, when you're down in the south where it is a little easier drilling, it is probably about 1.5 million, and when you get up into the area into the north, it is about 2 million.

Thanks. One quick other one. The drop in U.S. gas production from Q4 to Q1, was any of that related to processing losses?

Yeah, this is Darryl Smette. And the loss there is about 800,000 -- or about 800 barrels a day.

800 barrels a day. Thanks.

Our next question comes from Shawn Reynolds of Petrie Parkman. Sir, you may ask your question.

Good morning, guys. Is there any royalty relief issues on Boomvang Nansen that may be impacting your volumes as well?

Let's turn that question over to our General Manager of the Gulf Division, Bill VanWe. Bill, are you there?

Hello? Yes, my phone just clicked on. Yeah, Shawn, there are some issues, as you know, the -- there is the price thresholds in quite a few of these deep water leaseholds that was put on by the MMS and basically we're currently -- we are currently accruing volumes and capital on those -- those leases relative to royalty relief, because the -- your bill for that, for that royalty isn't announced -- the threshold really isn't declared valid until the -- well into the following year. So there's -- you know, you have to look at the differentials there, in terms of accruing volumes and revenues for those leases.

Right. But I guess, my -- more directly, my question is, you know, some of the volumes that are coming out of -- out of Boomvang, you alluded to, you know, well watering out a mechanical issue, I think Brian, you said something like 3 1/2 thousand barrels a day, impact that would equate to a little over a million barrels.

Yeah, think there is some -- there is some -- certainly some optimism about getting the well that has mechanically gone off back on, but it is going to take a work-over on the sub sea completion to do that.

Okay. Great. That's all I had. Thanks.

You know, to put that into context, for people that might not be as close to the issue, I think Shawn was asking if we're getting royalty relief on Nansen Boomvang and the answer is that it takes time to know whether it actually qualifies, but Devon is accruing the volumes as if we will not get royalty relief, so that in case it is not granted, we have taken the conservative position.

Ellen Hannan of Bear Stearns. You may ask your question.

Good morning. Thank you. Just a follow-up to the deep water activity. The appraisal activity that you plan this year, Larry, I think you said that you -- do you plan to appraise St. Malo and Sturgis but you don't currently have a firm plan to continue the appraisal of St. Malo? Is that correct?

That's correct. On Cascade, there is not an exact rig or timing identified for that yet.

Yeah, we actually -- this is Brian. We actually are moving a rig on to Dana Point which we will use that well bore to test St. Malo.

Cascade is what I was looking. Do you think you will have enough information to book reserves on these two by year end?

That's a good question. I wish I knew.

I presume that's what's leading you to your confidence though that you will have lower F & D costs this year?

Not really. The confidence on F & D really is looking at the broad drilling that we're doing in Canada, the Powder River Basin, you know, the Permian Basin, the drilling we're doing in the Barnett Shale, it is really based on all of the drilling we're doing now. We're really not anticipating that we are going to book any reserves -- or our confidence, at this moment, is not based upon any expectation we're going to book any reserves in the deep water prospects of St. Malo or Cascade or Sturgis, although we might.

Very good. Thank you.

Bill Pace of Credit Suisse First Boston. You may ask your question.

Good morning, guys.

Good morning.

I'm assuming, just judging by the IP's and the well costs, that all of that looks pretty economic. Could you confirm that? And second, could you comment on what the resource potential looks like now at Washakie and it looks like that has been a good program, and how much running room you have in that play?

Don Don DeCarlo, you want to do Washakie?

Yeah in regards to Washakie, we're moving well up the happy curve, if you will, we're going to drill probably 50 to 55 wells this year, which will be the most wells that we've drilled in the history of the play. And would expect that we will continue that going forward. We see potential for additional down spacing in the main fairway of the field, the standard draw bar, getting improved later on this summer, so -- and we're seeing slight increases in costs here, but the economics of the play are outstanding, and I think you will see us drilling 40 to 60 wells in the Washakie on a year in, year out basis for several years.

Brad Foster, you want to take the Barnett economics question?

Yeah, Bill. So as far as the economics go I think when you're looking outside the core, I think it is the oil -- if the gas prices stay in, the you know, 3.50 and up range, I think all of the stuff outside the core from our standpoint looks very economic at this time.

I will make that bet. Thanks, guys.

Andrew Lees of RBC, you may ask your question.

Good morning, guys. Can you tell me how many prospects you've got in total outside the core area for horizontal drilling? And whether or not you've booked any reserves there at year-end '03?

I guess when you mean prospects, Andrew, you're talking about the number of wells?

Well locations, yeah? How many horizontals do you think you can drill?

If you sit there and look and I am going to sit there and I'm going to give you a risk number here, but if you look, if we have 390,000 acres and if you assume somewhere between a third to a half is drillable, that gives you somewhere between 800 to 1200 locations, and assuming a B and a half, that gets to you 1.2, 1.8 B's, I'm sorry 1.2 to 1.8 T's, if you sit there and you end up doing a little better and you get about two BCF per well then you're up into the 2.4 T type range. So that is -- that is the kind of the number of wells that we have. And I'm sorry, I don't remember the second part of your question.

Had you booked any reserves in the noncore in '03?

We booked -- we booked a very few. I think there's -- you know, in the whole scheme of things, it is very, very small. We had -- I don't know, probably in the neighborhood of 17 wells last year, so maybe we -- maybe we booked about 20, 30 PUDs, but that was about it.

And Andrew, this is Larry. Remember our objective last year was to bring our percentage of PUDs down so we were not aggressive at all in Barnett or other areas in booking PUDs because we wanted to come into a mid-20s of PUDs as a percent of overall reserves, just as a matter of broad corporate philosophy, so we have not booked nearly the reserves out there that we could have if we wanted to really increase our PUD percentage.

While we're on the topic of PUDs we said we would reduce our capital devoted PUDs by 60% this year, that was a mistake. We meant 30%.

Yeah, Vince is being nice when he says we. It was me.

Thanks, guys.

Next question?

David Heikkinen you may ask your question.

Good morning, John, just had a question for you on Jack Fish. The timing of the approval of the project, late '04, early '05, does that impact reserve booking there, do you need to have the project approved before you book reserves?

Yes, David, we do have to have the project approved, and sanctioned, obviously sanctioning since it is our own project is assumed, but we do have to have the approval of the regulator, before we book anything. So when -- you know, we're not anticipating booking any results in 2004, or sorry, any reserves in 2004, and our getting back to that question, on our confidence with regard to our finding and development costs for 2004, it is really based on the one-third of the year drilling that we've seen, some very good results at that time, and knowing what we have on the books for the rest of the year, it doesn't anticipate any bookings at Jack Fish in 2004. Once we get that approval, and you know, if we -- if we were to assume that our -- the regulatory approval would come in about on schedule with other SAG D heavy oil projects, and frankly, these ought to be pretty routine by now, because it is not new technology, and then not a new concept at this time. We would still hope to see that late this year, in 2004.

And then not to put words in your mouth, but with the appraisals and the deep water Gulf of Mexico, and then Jack Fish in '05, would you think that you would have a decline in finding costs potentially in '05 again versus the improvement that you're expecting in '04?

You know, I hate to forecast 2004 let alone 2005, but we have -- you know, we have been spending, as we talked about in the past, we have been spending a lot of time, effort and money over several years bringing on these large high impact projects and certainly if we start to book some significant reserves in the deep water Gulf of Mexico next year, and we start to bring on some of our reserves at -- from some of our other projects, like Jack Fish, it -- all of those point in a positive direction for F & D cost, certainly.

For 2005.

For 2005 and other years, subsequent years. We got a lot of confidence in those years because of the -- the pipeline -- or these projects that are coming out of the other end of the pipeline that we've been working on over all these years.

You know, to summarize that, you know, as we've been saying for the last several year, we've been spending a lot of money in '02 and '03, in building up this portfolio of projects, and we think they're all proceeding as planned and we will bring F & D costs down in '04 and even more in '05.

It would be good to get the trend going in that direction. Good job, guys.

Thanks, David.

John Hurland of Merrill Lynch. You may ask your question.

Yeah, thank you. In the Gulf of Mexico, you discussed several issues between, you know, deep water and shelf. You went nonconsent on Yorktown if I'm not mistaken. Are you going to be reducing your risk profile here or are you going to maintain about the same exposure? And also, with the shelf, are you going to back way, with your activity there?

Speaking to our overall risk profile, John, I think that just by definition, the fact that so much of our drilling is in the deep water is delineation of previous discoveries, he we do have a lower risk profile. However, we continue to participate in three to six deep water wild cats a year going forward, to reload the pipeline. As far as our investment on the shelf, we see the shelf over time becoming a smaller percentage of our total Gulf production. And the deep water becoming a larger percentage. The shelf is clearly a mature area. And we will continue to spend dollars there, but we think it has got an attractive rate of return but we are not going to try to -- try to hold the shelf flat over time.

Thanks.

Mark [Pible] of Barclays, you may ask your question.

Yes, good afternoon -- good morning, actually. I was wondering how you were looking at reducing debt if you had no further bank facilities outstanding, outstanding on the bank facility?

Brian?

Yeah, we've talked very publicly about our desire to build up a cash position in the bank that would allow us to be in a position to repay the '04, remaining '04 maturities which we have a small maturity in June, and then our '05 and '06 maturities. I think we're rapidly approaching that point. And we will obviously provide an update at the end of the June quarter. Beyond that, as we generate cash flow in excess of our budgets, and that immediate maturities, as Larry discussed, we will look at our dividend again and we'll look at our stock and whether we should consider repurchasing our stock. We obviously have a great deal of confidence in our reserves, and our reserve report and thus when we look at barrels in the market we like our own barrels, a lot more than many other barrels. So you know, we have a great deal of flexibility. We obviously could go out in the open market and buy bonds in the open market but that would require in general paying a premium and we're not prepared to do that. We think it is more prudent to wait until they mature and retire them as they come due.

So your intent is to have cash on the balance sheet of a billion dollars through the end of the year basically?

I would propose to you that we will have at least -- as Larry mentioned, we're over a billion right now having paid off over 850 million in maturities so far, so given where we are today, given where prices are today, I think we will have well in excess of that at year-end.

Thank you.

Once again, to ask a question, press star one on your touch-tone phone. Our next question comes from Mark Sonnenblick of Citigroup. You may ask your question.

Actually, it has been asked already. Thank you.

[John Varinger] of Loomis, you may ask your question.

A quick question for Brian. Do you have a number for the quarter for capitalized G&A and capitalized --

This is Vince. I will answer that. That is actually in the tables provided with the press release.

Oh, sorry. I will look for it and find it.

Capitalized G&A expenses were 42 million, and capitalized interest costs were 17 million.

Okay. Thanks for the help.

This is a Devon first. We've finished the call and run out of questions before the hour is up. There is no one else in the queue. Any closing remark, Larry?

If there are no other questions, we are -- obviously it was a very successful quarter. No quarter is ever perfect. But clearly, we have the direction headed in the right way. We're delighted with all the various records we've set. We're very happy with the direction that F & D is going. Our debt is obviously coming down like a rock, as we planned. So we're back to work on making the second quarter even more successful. Thank you all very much for your attention.

This concludes today's conference. You may disconnect at this time.