德文能源 (DVN) 2003 Q1 法說會逐字稿

Good morning, ladies and gentlemen.

My name us Paul and I will be your conference facilitator.

At this time I'd like to welcome everyone to Devon Energy's conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. If you would like to ask a question, please star and the number one on your telephone keypad. If you would like to withdraw your question, press star and the number two on your telephone keypad.

This conference is being recorded and will be available for replay beginning today, May 8th, 2003, as 2:30 p.m. eastern time through May 15th, 2003. The replay number is 1-800--642-1678. Or 706-65-9291, with conference ID number 9476302. This information again will be repeated at the conclusion of the call.

I would now like to turn the conference over to Vince White, Vice President of Investor Relations.

You may begin.

Thank you.

Good morning, and thanks everyone for joining us today on the call.

The purpose of today's call is to, of course, spend an hour to discuss Devon's first quarter 2003 results. Larry Nichols, that's Devon's chairman and chief executive officer will first give an overview of the quarter. Larry has also got a couple of significant announcements to make. He will then turn the call over to our new president and chief operating officer Jim Hackett.

Jim will give you an update on our first quarter operations. I will then return to discuss the financial results of the quarter. After that, as is our practice, you'll have an opportunity to ask questions. We've got a lot of key managers and officers here to help with that.

Before I turn over the call to Larry, I have a couple of housekeeping items to cover.

First we filed an 8K with the SEC this morning. This document contains updated guidance for our expected 2003 production, expenses, and product price realizations. During the call we will discuss our expectations for the year. And when we provide this kind of forward-looking information, we, of course, run the risk that our actual results of differ from our expectations.

I would encourage you to see a discussion of risk factors that could cause our actual results to differ from the forecast. Those risk factors are included in the 8K we filed today. Everyone who is on the telephone should have received a copy of the 8-K, as well as a press release. Anyone has not received a copy may obtain the form 8-K that we filed this morning from our website. That address is www.Devon energy.com.

One other housekeeping item, if you have listened to our competitors conference call this quarter, you may be aware there's new rules for the performance of nonGAAP performance measures. These come to us courtesy of the Securities & Exchange Commission as the implement 401 B of the Sarbanes Oxley act.

The new rules require any nonGAAP measures we use, that we provide you with a reconciliation to the closest GAAP measure and we explain why this nonGAAP measure is useful to us and investors and others. The information found by the new rules can be found in today's press release, and that press release is also posted in our website in the news section.

I'll turn the call over to Larry.

Thanks, Vince.

There are a great many things to talk about in Devon's first quarter result, our most important achievement was our merger with oaks energy. On April 25, the shareholders of both companies overwhelmingly approved th merger and the deal was closed. We were delighted to get it done so quickly. Even before we closed the transaction we were well on the way to integrating the two companies.

Jim Hackett and I had selected our team, made personnel decision for key positions throughout the organization. We will finalize all the staffing decisions by the month of June, about 45 to 60 days from now. By July, we will expect to have our downtown Houston offices combined under one roof.

As you can see we're moving rapidly to complete the integration of these two companies just as Devon has done in our past transactions. Our merger with Ocean accomplishes a number of strategic objectives for the shareholders of both companies. The doll inventory company has a position in North American oil and gas production. We're proceeding 2.4 BCF of gas daily, making us one of the largest natural gas producers in North America. In fact, we're currently producing approximately 4% of all the gas produced in North America.

In addition, we're also a significant player in North American oil and gas liquids production. We have an low risk multi-year growth profile. Based primarily on projects that do not require additional exploration success. These are significant development projects that we already have in hand, like the Barnett shale in north Texas, in Gulf of Mexico we have -- in international we have projects like Zafiro and Panyu that will give us multi-year growth. Our low risk growth projects are backed up by a superior portfolio of high impact exploration projects.

As the largest independent holder of deepwater gulf acreage, in a company with a very attractive suite of international exploration possibilities, Devon has multi-inventory of world-class exploration projects. In spite of the flurry generated by the merger, Devon had an excellent quarter with the drill bit. In the United States, Devon stand alone drilled 191 gas wells with 98% success rate. In Canada we had a solid winter drilling program. We drilled 295 wells with a 90% success rate.

In total, Devon drilled 499 wells, spending $435 million of capital in the first quarter with very good success.

Our first quarter financial performance was also remarkably strong. During the quarter we generated cash flow before balance sheet changes of $868 million. Net earnings for the quarter were $436 million or $2.76 per share. This kind of per share performance is exactly what we believe we could achieve when a year and a half ago we decided to make two major gas acquisitions.

Our confidence to move forward with Mitchell and Anderson was based on our belief that natural gas was becoming increasingly scarce in North America and our shareholders would benefit if we owned a lot of it. We were confident if supply and demand lifted prices we could deleverage the balance sheet, the economic benefit would accrue to the Devon share holders. Our plan could not have worked better.

At the end of the first quarter, 2002, a year ago, following the Mitchell acquisition, Devon's net debt to cap was over 63%. One year later, this past quarter Devon's stand alone net debt to cap had declined to 56%. The closing of the Ocean merger took our proforma net to cap down even further to 49%. Last week, a week after the merger, we further reduced the debt by repaying all of Ocean's $210 million credit facility. In the current pricing environment, we're continuing to generate earnings an accumulating cash for further debt reduction. In fact, we expect to repay another $200 million of debt in early July when we redeem Ocean's 8 3/8 senior subordinated notes.

Based on the forward strip and production and expense guidance that we're providing today, we could end 2003 with net debt to cap ratio in the low 40s.

So as Devon happily completes the task of deleveraging, our shareholders are left with the enviable position in North America oil and gas market and an exploration portfolio that is second to none.

The crown jewel of the Mitchell equation was, of course, the position in the Barnett shale. Since we closed the acquisition, the Barnett shale has grown to become Devon' largest property and now accounts for about 13% of our total companywide oil and gas production. And that percentage is continuing to grow. We drilled 82 Barnett wells in the first quarter and all were successful.

During the first quarter for the -- during the first quarter, for the first time in this field's history, we have driven our net production to a little more than 500 million cubic million feet a day, a half a BCF a day. This compares to net production of 375 million a day when we closed the Mitchell acquisition in January 2002. This field is now the largest in the State of Texas, and Devon has the dominant position in the field. In fact, last year we produced more than 10 times the gas of the next largest gas producer in this field.

I'm pleased to announce today, that based on the performance of our horizontal drilling program, we're going to go from a 14 rig program, drilling vertical wells, to a 16 rig program of which six of the wells will be devoted exclusively to drilling horizontal wells. We had previously announced we were going to drill 10 horizontal wells this year but we're now announcing we expect to drill 50 horizontal wells by the end of the year.

Horizontal drilling in the Barnett is of particular interest, because it represents the potential to develop 400,000 acres we have in this play outside the core area. In addition, within the core area, horizontal drilling reduces our already low fining cost. During the first quarter we booked reserves on five horizontal wells in the Denton and Wise counties averaging about 3 BCF per well of reserves. The cost of these horizontal wells is currently running about $1.5 million each. As we standardize the approach to drilling these wells, we expect to bring that cost down some more.

We currently have about seven horizontal wells on production. These wells came on with initial rates of between 2 1/2 and 4 1/2 million cubic feet a day. They have now stabilized and are producing in aggregate 15 million feet a day. In addition we have another 9 horizontal wells we've already drilled that are waiting completion and hookup. With thousands, literally thousands of prospective locations on our existing acreage position, the potential to Devon from this announcement is very significant.

So all in all, we're very pleased with the results of the first quarter and where we have Devon positioned for the future.

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

Thank you, Larry.

I hope everybody can hear me okay.

In covering the operations today, I'm going to refer to the combined operations of Devon and Ocean as if we've been merged from the start of the year. At the end of the first quarter we had 99 rigs running companywide with almost 60% operated by Devon. We had a first quarter peak of 138 rigs running in late January at the highlight of the drilling season in Canada with 2/3 of those wells operated by Devon. First quarter exploration and development capital expenditures for the combined companies were $767 million.

Together the company drilled a total of 559 wells in the quarter, almost 30% of these wells were classified as exploration with remainder obviously classified as development wells. 77% of the exploration wells were success and 90% of development wells were successful. As you can see we had a very active quarter with the drill bit. In Canada our joint activities concentrated in the winter months when the froze ground allows us to access the marsh areas.

We spend about 1/2 of our Canadian budget in the first quarter, this year was no exception. We drilled a total of 295 wells in Canada in the first quarter with an overall success rate of 90%.

Highlights included seven successful slate wells in western Alberta. Three of the wells tested at a combined rate of cubic feet of gas and several thousands barrels of NGA a day. Two other slate wells in the Osprey at cubic feet a day.

In the same region on the BC side we added about 10 cubic feet of productive capacity in the Morgan Tommy area. In the Mack Mackenzie area, our F 29 well found structure but was wet and so unsuccessful. Also in the Mack Mackenzie Delta we began an exploratory. We had not reached TD when ice melted so we suspended operations before.

We do further evaluation of training-aided results and determine the timing of reentering this we will in the future.

Moving to on shore U.S., 63 rigs that worked at the end of the first quarter with over 60% operated by Devon. We drilled 233 wells in the quarter with a 96% success rate. We already covered our largest U.S. on shore development project to Barnett Shale.

One on shore discovery worth noting is an exploration we drilled in Groesbeck. It logged 60 feet of pay in the Travis Peak, 290 in the Cotton Valley, another 9 feet in the [INAUDIBLE]. Three new wells and nine recompletions year to date at Groesbeck for a total gross rate increase. What makes this exciting is we have over 100,000 net acres in the area, which comes from the fact Devon was active historically and augmented its position.

Offshore in the Gulf of Mexico shelf, we had six operated and six outside operated rigs running at the first quarter. Following the end of the quarter in April we made a discover in our grace prospect and Galveston bought 424. The discovery well was drilled to a total depth of 11,005 in 104 feet of water and -- the operator of the block with a 65% working we planned to drill two additional wells in this block later in the year and expect first production in the first quarter of 2004.

This project was recognized through a shoot that Devon later refined with 3 D.

In the deepwater Gulf of Mexico completion moves forward at the Boomvang complex. We average 38,000 barrels of oil per day net to our interest at the first quarter. At Boomvang we successfully reentered one of the we will bores and sidetracked to another full block and that we will is producing 30 million cubic feet a day of gas and 900 barrels of oil.

In Nansen we're in the process of bringing up the rate on six dry creek completion and total production is running 20,000 barrels a day in oil grass and 180 million a day in gas, 20,000 net to Devon's in mid April shut Nansen platform to prepare the facilities for future compression and tie in the remaining Navajo sub sea wells. It's since been tied in and tested at a gross rate of 6,000 per barrels a day of oil and [INAUDIBLE] gas has been accomplished.

The west Navajo well is scheduled for tie in this week. We're also in the process of completing the last three Nansen dry creek completion.

The Zia project in the gulf remains on schedule and we are currently starting completion operations on the first producer after sidetracking into about 100 feet of oil pay. On schedule as well and first production during the summer at 4 to 6,000 barrels a day net to our interest. The red hawk sell spar development in the deepwater Gulf of Mexico continues to move along on schedule, and first production is still estimated to occur midyear 2004 in 9 to 12,000 barrels a day net to net Devon.

Magnolia, reduced total depth on the third development well, will sidetrack and complete the well following delays from an earlier mechanical problem. This extends the proven limits of the field to the west. Production to the telephone LP. is on schedule and first production is still slated for the second half of 2004 at a net rate of 9 to 12,000 barrels a day.

In the near term deepwater exploration front following Yorktown we've set another casing string and are again drilling ahead. Most of the delays following the early mechanical problems were caused by difficult down hole pressure regime. We're down hole first interest, and barring further difficulties to get a look at our first objective in two or three weeks.

Total cost for the well to date is 55 million gross and we expect to spend as much as 55 million getting to TD. Devon's expected net cost for this well is $50 million. The projected reserve as a reminder is over 200 million barrels of oil equivalent.

We also began drilling the Devon prospect deep shiner in our joint venture with Kerr-McGee located in 436 feet of water. Also this summer we plan to drill another deepwater well in the Kerr McGee. We plan the Tuscany prospect in the good enough with a drillship this summer.

In our deepwater joint vents your with Chevron Texaco we began drilling our second JV in the Gulf of Mexico. This will test sub salt Sturgis prospect in about 3600 feet of water.

Internationally we had seven rigs at work at the end of the first quarter, and during the quarter drilled a total of 31 international wells, almost 80% were successful.

In China our two-well exploratory drilling program finished with an unsuccessful test on black 1602. However, in the development front of Panyu project, we have PSO near completion, the first of two platforms in undergoing installation with the second to follow roughly a month later. We expect first production in quarter four of this year with peak rates in early '04 of 15,000 barrels a day oil equivalent net.

In Egypt we have installed the platform jacket and are in the process of installing the top sides. We've contracted a rig to arrive in May to drill the initial development well and expect first production later this summer. At about 5,000 barrels a day gross or 2,500 barrels a day net to our interest. Moving to West Africa there's one in Equatorial Guinea is on track to deliver outstanding performance for the year.

Production for the quarter averaged 35,000 equivalent barrels net per day to the company. The newly constructed is en route to PG and field associated with sub seat and flow lines is also on schedule. We still anticipate first production from the southern expansion area to occur later this summer with seven to nine wells ready to come on production at that time.

We've completed three wells to date and each has shown production capacity of 10,000 barrels of oil per day gross or more. We now have ten development wells drilled and continue to keep two floaters working in the southern expansion area.

Year end production from the Zapiro fields increased significantly over 2002, with exit rate production over 250,000 barrels a day or 50,000 barrels net to Devon's interest. Also in Equatorial Guinea we've been awarded an operating block, which we'll have an 80% working interest and a two-well commitment.

Offshore Ghana, we have a rig in country commenced an exploratory on a high risk high reward catablock this weekend. This is a 13,750 feet test with pre-drilled target of -- it stands in 6300 feet of water.

In [INAUDIBLE] we started interpretation on block ten 3d shoot and initial look are favorable. We anticipate picking up a rig later this year and we use that to drill our initial well on block 10 as well as our last commitment block on 24, both of which will be Devon operated.

Turning finally to mid stream and marketing business, in addition to delivering strong first quarter financial results, the marketing and mid stream group was very active in the field, connecting over 88 wells and installing 23 miles of pipeline in North Texas alone. Combined basis company marketing over 53 BCS a day of gas and 250,000 barrels of liquid. From ownership in both oil and gas production as well as 70 processing plants and thousands of miles of gas transmission lines.

Our sale of the Jameson plant in the first quarter essentially completed our mid stream divestiture program.

Now I'll turn the call over to Vince White for the financial discussion.

Thanks, Jim.

I'm going to start with some production volume comparisons.

First I want to remind everyone since we completed our merger with Ocean following the second quarter our first quarter results do not reflect any production volumes or any impact of the merger.

Looking at Devon's stand alone production, companywide purported production of oil and gas and NGL was 432,000 barrels equivalent per day during the first quarter of 2003. That's down about 9% from the first quarter of last year. And of course the big driver is the divestiture program that we under took last year.

Looking at the sequential quarter comparison, our fourth quarter 2002 production averaged 495,000 barrels a day, that's before adjusting for th divestitures we completed in the fourth quarter. When you back out the production from the sole properties you'll find we had fourth quarter 2002 production that averaged 491,000 barrels equivalent per day during the quarter. That's from retained properties.

So on a sequential quarter, retained property basis, first quarter 2003 production was up about 1,000 barrels a day or essentially flat.

There were several factors that prevented our first quarter production from being higher. First, while choosing to not extract natural gas liquids from our gas stream in the first quarter, increased our revenues by over $4 million, it reduced our production by 4100 barrels equivalent per day.

Although higher oil and gas prices increased sales revenues in Canada during the first quarter, the higher sliding scale royalties reduced or purported production volumes in Canada.

Nevertheless our first quarter companywide reported production came right in line with our budget.

Looking now to Devon and Ocean combined, assuming that we had merged on January 1st, and looking back to the comparative quarter, in the fourth quarter of 2002, proforma production from retained properties for Devon and Ocean combined was 649,000 barrels equivalent per day. When you compare that to Devon's first quarter production for 2003 plus the 1666,000 barrels that Ocean produced during the quarter, you'll find we had proforma production of 658,000 barrels per day. That's a 1.4% increase on a sequential quarter retained properties basis.

Looking forward into the second quarter, I'll remind you that since the Ocean transaction closed on April 25th, we will only report production from the Ocean properties for about two months of the second quarter.

We expect to report total second quarter production, that's two months of Ocean plus three months of Devon between 55 and 56 million equivalent barrels. Had Devon and Ocean been merged for the full three months of the second quarter, these numbers would obviously be higher.

We expect that the second quarter proforma daily production rate to be, for th combined company, be about flat with the first quarter. The growth of the company for the remainder of the year is really back end loaded , the end of the third and fourth quarter we'll be bringing on Panyu in China Zia and Boomvang in the deepwater gulf and the southern expansion area of Zafiro and equatorial Guinea.

In the first full quarter of Devon and Ocean combined we expect total production to come in at 61 and 63 million barrels equivalent.

To get a sense of our expected 2003 combined company production growth from retained properties, start with the full year guidance that we provided in our form 8-K today. That calls for us to report production of between 224 and 229 million equivalent barrels in 2003. Since Ocean produced about 19 million barrels in the first four months of the year prior to the closing, as I said before, these volumes will not be reported in Devon's 2003 results.

So when you add those to the Devon forecast, you'll find that we expect proforma production of 243 to 248 million barrels for '03.

In 2002 they adjusted and produced 243 million barrels. When you do the math you'll find our 2003 expected production growth from retained properties is 4 to 6%. That's right in line from what we told you on the merger road show.

Moving now to product price realizations.

Obviously oil and gas prices were great in the first quarter. Our average realized gas price climbed 101% over the comparative quarter of 2002, averaged $4.84 per MCF. Our average realized oil price increased 51% over the first quarter of 2002, and NGL prices increased 73% over the first quarter of 2002. Looking now to Devon's floating price realizations, that is the prices we realized on volumes that are not impacted by caller, swaps, or fixed price sale agreements. These came pretty much in line with our guidance for most areas but I'm going to [INAUDIBLE] a couple of exceptions.

First our floating gas price realization averaged 552 MCF in the first quarter, that's $1.06 under the mine ex Henry Hub price. Our Canadian averaged 559, that's $1.09 under the mine ex Henry Hub. In both cases that's a wider discount to Henry Hub than we anticipated.

In the fourth quarter we saw most areas did not have direct access to the Henry Hub, Rockies, Permian, Fort Worth and Canada, they continued to trade at wider than normal differentials to Henry Hub. That was especially true in the Rockies and Canada because of the weak weather related demand in the western United States. I will point out that the warm, dry weather season at the western U.S. ha experienced points to a rather anemic hydropower season on the West Coast, which ought to help the situation.

Assuming we have normal weather going forward we expect rocky mountain and Canada gas prices to improve relative to Henry Hub. Also the recent completion of the current river expansion which adds about 900 million a day of westbound capacity out of the Rockies has clearly improved Rockies' gas access to the West Coast. In any case, we've revised our guidance for gas price differentials for both of these areas, that is Canada and the U.S., and the revision to the guidance really reflects the lighter than expected differentials we experienced during the first four months of the year, not what we expect in the balance of the year.

Before I move to expenses, I want to point out that our marketing and mid stream group made a big contribution in the quarter. We had first quarter marketing and mid stream revenues of 434 million. When you back out the associated cost and expenses of 356 million, you'll see that we had first quarter margins of 78 million from marketing and mid stream. That's about 23 million better than our guidance for the quarter, and that's due largely to higher NGL prices.

For the full year 2003, we're revising our guidance for marketing and mid stream margins up to a range of 190 to 270 million. The midpoint of that is 230, and that represents a $37 million increase from th midpoint of our previous guidance.

I'm going to move now to a couple of expense items. Most expense items were in line with our guidance, I'm going to talk about a couple that varied from our expectations.

The first one I want to touch on is lease operating and transportation expenses.

In aggregate, these expenses total $206 million in the first quarter of '03 and that's 465 on a per barrel basis. This compares to our expectations when we laid out or guidance of the beginning of the year of 425 per barrel.

The big drivers to higher first quarter LOE and transportation expenses were higher than expected fuel and electricity cost, higher than expected well workover expenses, and also pretty significant impact from the adverse affect of the strengthening Canadian dollar. That is, when we translate that into U.S. dollar, a stronger Canadian dollar makes our LOE go up.

Looking forward based on the midpoint of our up updated guidance, our lease operating and transportation expenses will average $4.52 per barrel for the full year.

Moving now to general and administrative expenses, it was about 5 million lower then we expected. The big driver or biggest driver was lower than expected employee cost. The next item I want to cover is a new item on our income statement.

The line item referred to as accretion of asset retirement obligation. This results from our January 1 adoption of FAS 143. This pronouncement concerns the retirement of long lived assets such as producing well sites, offshore platforms and natural gas processing plants.

The statement requires that the estimated present value of future abandonment cost be recorded separately on your balance sheet. The difference between the discounted cost, that is the present value, and the actual eventual expected cost of abandonment is accreted over time in the income statement and generates an expense.

Prior to FAS 143 these were in the total cost subject to completion and reflected in DBand A expense. Really we have a shift from DBA and this new accretion expense.

During the first quarter we recognized a 15.7 million after tax gain, that's due to the cumulative effect of adopting phase 143. In our first quarter of accreting we had a $7 million accretion expense.

The last expense item I want to cover is income taxes. The first quarter they totaled $199 million. That's 32% of pretax earnings. That's a little higher than our guidance. That's due primarily to higher than expected earnings.

I point out as our pretax earnings go up, our effective tax rate increases. The reason for that is the positive effect of certain tax advantages we've entered into diminishes relative to overall taxable income as income goes up.

We expect our full year 2003 income tax expense to be between 25 and 45% of pretax earnings with about 1/3 of that current and about 2/3 deferred.

It's also worth pointing out that these ranges -- this range is so side because our income taxes are based on a lot of different assumptions and are very difficult to forecast. When you take out the revenues, back out expenses, you'll find that we had first quarter net income of $436 million.

That's an all-time record as Larry pointed out.

That translates to reported earnings per share of $2.67 on a diluted basis. That $2.67 per share includes some income and expense items that the analytical community typically excludes from their published estimates. These items in the first quarter were the affects of changes in foreign currency rates and the change in fair value of financial instruments. Oh, and also that cumulative effect of a change in accounting principal.

In aggregate, those items increased our net earnings by 21 cents per diluted share. Adjusting for those items that are excluded from the consensus estimates, we had $2.46 per share, that compares to a full cost consensus estimate of $2.26 per share. That level of earnings translates into cash flow before balance sheet changes of $868 million as shown in our press release.

The new Reg G forbids us from giving you that number on a per share basis. I can tell you our 163.1 million shares.

That wraps up the prepared remarks, and we will now open the call to the questions.

At this time I would like to remind everyone if you would like to ask a question, press star, then the number one on your telephone keypad. Again, that's star and the number one on your telephone keypad.

One moment, please, for your first question.

Your first question is from Shawn Reynolds with Petrie Parkman and Company.

Some fairly unsavory places in West Africa.

I was wondering if you could expand on what's happening in Angola and thoughts on block 24. I thought it was interesting you mentioned it was a commitment we will on 24. I don't know if you're backing off your interest on block 24 at all.

Sure, Shawn. Good morning, Shawn.

On block 10, we've got our 3d, moving ahead with our partners there.

We're close to announce that partner, just have to get one final signoff by the government. We see a couple of big structures that are in about 900 feet of water and expect to be picking rig at Brill block 10 and follow with our fourth prospect at block 24.

I might add that was John Schiller answering that question.

Shawn, we had a little bit of trouble hearing the question. Did we cover all the parts of ?

Yeah. What about the timing there, John?

It's going to be a little rig dependent, but I would look for it probably late third quarter, Shawn.

Will it be a program on block 10 or just one we will.

I think this time it will be one we be one well on 10 and one on 24.

We're hoping it's a program, Shawn.

Your next question is from David Khani with Friedman Billings and Ramsey.

Hi, guys.

Now that you have the two companies put together, is there any change in some of the cost savings outlook? And there is any thoughts of trimming some of the combined entity asse?

Yeah, we announced at the time of the merger that we thought we'd have 50 million in synergy savings, and we are keeping close watch on that. We think that's very achievable and don't really see any reason to change tha guidance now. Obviously hope to achieve more than that but I think will stick with the 50 million for the time being.

We'd expect to achieve the full 50 million in 2004, David.

Okay.

And on the Barnett shale, it seems like the outlook just keeps getting better and better. Is really essentially the drivers here now you're using horizontal rigs on a more after program basis.

And the second really is that you're feeling more comfortable on drilling outside the core area, sort of the 400,000 plus Akers that you h? That Is summing it up.

That's correct.

Yeah, both those observations are right on.

Great.

Being in D.C., Larry, things aren't so bad here. Good. Thanks.

Your next question is from Irene Haas with Sanders Morris Harris.

Two questions regarding the deepwater.

I just want to make sure I hear the write thing, Yorktown roughly three weeks from TD. You said net to Devon eventually will be 50 million including testing.

And I guess you spend 50 million gross. Is it complying 100 million dollar we will? Second question, aside fromTuscany, shiner, deep red, whatever, what happened to the other JV's that came from Devon's side of the deepwater? Can I have a little more color on that? Than.

Irene, this is John.

I've got to tell you were cutting in and out pretty bad. I think the first question was Yorktown and how far from TD and the cost.

She said 50 billion in cost and three weeks from 3 D was her question.

Jim talked about the cost. We're coming up on 19,000 feet.

I'm going to tell you that I think, you know, unless things go really well regarding the pressure difference between our pour precious and frac gradients we'll do good to drill 25,000 feet, I don't think we'll get to where we though originally but should get a fair amount of sand evaluated. We had to come out of test VOPs and we'll go back to drilling on Friday. Your second question was on shiner deep and another well.

It was on the Chevron joint venture, which we covered.

If I remember, Irene, the Chevron joint venture, we mentioned the next prospect we'll be drilling, and we haven't actually been released by our partners to talk about any prospects beyond that. What we're trying to do is give you a sense of what's happening in summer on the exploration fro.

This is Bill from Houston.

It's under way, they have mentioned from Chevron, JV standpoint we intend to spud another JV well by the end of the year and a fourth one, which would fulfill the obligation of the Chevron sometime in 2004. We also have a potential offset to the cascade discovery schedule for the fourth quarter.

And another potential walker ridge well in the vicinity of cascade that we're currently working on. That's outside the Ocean frame of deepwater drilling as well.

So we -- from a deepwater standpoint, we could be exposed to somewhere between nine to 11 wells in 2003.

Great. One more question.

The cost involved so far you said is going to be net to Devon about 50 million. Now, is that including, -- does it imply if you gross it up it's going to be $100 million well at Yorktown.

I think we said 65 million gross well, our net share of that is 50 million dollars.

Ladies and gentlemen, as a reminder, if you do ask a question and are on speakerphone, please pick up your handset before asking your question. We'll take our next question from Mr. Mark Meyer with Simmons.

Morning.

Larry, if you could a little more specificity on the Barnett shale as it relates to, I guess, transitions from more after diagnostic with the horizontals to more of a program, as it was referred to earlier. Was it something you tweaked on the drilling side, completion side or significantly increased confidence in the early performance of the wells that you had drill?

Well, no one has ever completed horizontal wells and frac'ed them the way we're doing in black Shales for the Barnett. While the initial results were quite astounding, quite good, we just wanted to make sure that there wasn't something that we didn't know about how these wells would perform.

We wanted to watch the performance for some time. Some of these wells we completed in the fourth quarter of last year and we've just been sitting watching them making sure there was nothing we had not anticipated. And over time the wells have performed very nicely.

And we got to the point where we concluded that it was -- we could take with additional -- do additional drilling without incurring any additional risk. We started ramping up, decided it was time to start ramping up the level of horizontal drilling and did it significantly.

Shift to the Powder River.

Anything related to the record decision that kind of changes your outlook that you laid out in December, either from an activity standpoint or you had presented a long-term production profile that you guys expect.

I think so. It's Don DeCarlo that runs that division.

We're very satisfied, it's been a long time coming. Certainly give us an opportunity to see more drilling permits come out there on federal land.

I will caution it's a 1700 page document and does have some issues we'll have to work through over time, but it's certainly a positive thing for Devon and the industry out there. This is kind of a transition in the play transitions from shallower to deeper holes.

This is right in line with our expected timing on the EIS, so it's good news.

Thanks.

Your next question is from Fidel Ghett with Comstock and Company, Incorporated.

I have a few questions. The first one is on Egypt. Is Egypt the core holding or still putting good money after bad th?

No.

This is Jim Hackett.

It is still a core holding. We talked about in the past the gulf and Suez in particular has attracted our interest and we have participated in additional lease sales there and are awaiting final ratification of two additional concessions that we were notified that we had been high bidder on. So we still have years of activity going forward there.

Obviously in a new company you continue to low at all the assets in take country but we've not made any decisions different than what we have in Egypt and folks on the gulf and Suez a particular priority at this point.

Okay. The second question on the Gulf of Mexico, the deepwater program. When Ocean dealt with Kerr-McGee, that was a different relationship.

Now Devon is dealing with Kerr-McGee.

Do you see any changes in the program, acceleration, deceleration, expansion, or anything like th?

No, we don't see any change at all.

In fact, for the most part it's the same people that were, , you know, working with an Ocean name on their business card are now working with Kerr-McGee with the Devon name on their business card, so we see no change at all.

A couple more questions very quickly.

When do you feel comfortable not hedging at all?

Most of the large companies do not hedge.

If you attain certain financial flexibility, why would you want to continue with your hedging strategy?

I think hedging is, , you know, kind of like insurance. You don't want to do an overwhelming amount of it, unless your balance sheet compels you to.

Our philosophy, board of authorization is to hedge up to 50% and we've been in general in that 40 to 50% range for the last year or so. Oil and gas prices are volatile and provides you some protection against that.

It's something we evaluate all the time as we look at hedging and where gas prices are. We have been from a few years ago Devon had no hedging.

And I certainly would not want to say where we'll be two years from now. It's very much dependent on market conditions.

Hedging really doesn't do anything to your stock. I mean, companies that don't hedge usually have the better performance than companies that do hedge.

Well, we'll keep evaluating it all the time.

Then final question on the good will.

What do you think a drop in gas prices to, say, for a dollar, drop in oil prices to $22 would do to your ceiling test? What kind of writeoff you would have to ta?

You're asking about the ceiling test or good wi?

Goodwill.

That would have no impact on our good will. I would not anticipate any impairment on goodwill.

Prices can temporarily fall far below the price scenario you gave without causing a goodwill impairment. I do not see any impairment in the future in which there will be any impact on goodwill.

Thank you.

Your next question is have Van Levy with CIBC World Markets.

Morning, gentlemen.

The question ties in to reducing your debt.

You in the Azerbaijan area, the ACG field, there's been some transactions, some sort of value.

What have those been in terms of value for you, and would you be moving tha asset any time over the next six months to help you with your target?

Well, the goal -- any transaction we do with any property, based on where we are now, would really not be focused on debt reduction.

We're very comfortable where debt is trending based on cash flow and earnings we had from our properties. As I said, we'll be in the low 40s by the end of the year. We're very comfortable with where the debt is.

With regard to Azerbaijan, it is an asset in the area as we said in the past, where we don't see an opportunity for Devon to grow. If we saw an opportunity to swap that asset with another company, probably a major, or assets of equal quality for areas in our areas, we would do so and have had and are having conversations about doing that.

Having said that, it is a world-class field. It's a field that is just going to get bigger and bigger as we continue to do drilling there, as the pipeline is being built. It's a field that would add about 50,000 barrels a day net to Devon in 2008, 2009, at a minimum based on where production is now. So it's not a field that we would feel compelled to dispose of any time soon, unless we could swap it for something of value.

Okay.

Second question, Larry, you've built the company largely on acquisitions. Obviously you have a very large exploration portfolio now, and it's only enhanced by the Ocean transaction.

At what point would you basically adjust your strategy if the exploration was not working out, either just from a standpoint of success rate or cost structure, any reserves to higher cost from the drill bit.

At what point do you sort of kind of make that adjustment or that -- in the existing portfolio. I know it's something you probably monitor quarter by quarter.

How long do you let it run before you would make some sort of adjustment there, or would you?

Adjustment in what direction?

Adjusting the amount of money that's being spent object exploration.

First of all, if you look at our portfolio and where we're spending money, lot of it is in areas like the Barnett shale where we had 100% success rate.

Just look at the success rate we had in the first quarter of this year, both on the Devon stand alone and Ocean properties, a phenomenal success rate, with the drill bit. In the United States offshore, Gulf of Mexico, in Canada, in international. So we had a high level of confidence in our exploration portfolio that we have evolved over time.

It is true that we have grown in the past a lot by acquisition, but it has been a very gradual shifting, by acquisition, but a very gradual shifting from acquisition to exploration to where we are today. Our acquisitions have been designed not to get big, in fact, that's not even on the list, it's been to give the company a platform with which to grow by the drill bit.

We did that with Mitchell and getting the Barnett shale, which we have grow significantly since we acquired them in January of 2002.

We did that with Anderson where we established an acreage position that led to a successful program.

We've done that with our merger in Ocean, enhancing our Gulf of Mexico an international exploration. So I don't see any shift at all.

Obviously any exploration program is going to meet with success in some areas and not others. And where we allocate the capital dollars will shift from place to place based upon success.

I'm looking at a chart that says, a December presentation, $370 million for high risk kind of long-term projects.

Are you suggesting within those a large portion would be like lower risk ventures like Barnett shale, et cete?

The part that was not the 350 million, yes, was in projects like that. Of course the total budget for Devon for this year, stand alone was 2 1/2 billion, Ocean's was a billion, that 2 1/2 billion combined, we really see no reason to adjust that budget materially for this year.

We're very pleased with where we are, where Ocean, the combined companies are spending money. A little money to Barnett, based upon the success there. We're very happy with the budget and the balance of the budget of where we are now.

It is balanced between low risk, very profitable drilling like the Barnett shale and then some -- the other extreme, some of the drilling we're doing in deepwater and West Africa. So a very balanced portfolio.

Okay. Thanks, Larry.

Your next question is from John Harlin with Merrill Lynch Research.

You didn't mention the Cherokee at all, so could you give us a status update on what's happening the?

Yeah.

We are just now commencing activities in 2003. Over the last four to six months really wanted to take a look at what we've done.

We've been very active since acquiring the properties, adding the acreage over the last couple of years. Results over the last several months have been encouraging, so we're starting to ramp our activity up out there.

The two major areas being the portion in northeastern Oklahoma currently running about 10 million a day, and far side area in western Kansas is running 10 million and slowly ramping up. We will initiate drilling out there next week and anticipate a relatively steady drilling program during the year.

Steady meaning what?

Probably one to two rigs and probably for the remainder of this year drill somewhere between 50 and 100 wells.

Got a situation where we've probably got our drill bit ahead of our infrastructure, allowed that to catch up, tried to get a better handle on th performance of the wells. We're now going to get back to where we're going to be able to get our production on more consistently with our existing infrastructure.

Next question, with your Canadian program you drilled a lot of wells. Are there any left to be tied ?

John, do you want to handle that one.

John Richels in Calgary.

The winter drilling season was a little truncated, we got in late. Typically what happened when you've got a shorter drilling season is you get the wells drilled, it's the completions and tie-ins suffer a little bit.

As a result of cold weather in March, we did get most everything tied in, there's still some left in the deep basin. Some of that area does have seasonal access. It's not totally winter access only.

But cut through it really means if we don't get a lot of rain in the summer, we can still get into some of those areas during the summer season. We were pretty successful in tying most of it in. We had a really successful season up in the Hamburg, Chinchuga area west of that and the sub.

We will not be able to tie all those in immediately because of infrastructure restraints in some of the facilities, some of which we are the owners and operators of. So we'll have some gas that will come on over a period of time there. But generally we got most tied in that we expected to.

Okay.

Last question for me.

Could you put down your Cap Ex budget further for Devon deepwater on shore, Canada, and then international?

The answer is yes, we can break down our capital budget further.

Thanks.

Give me a moment.

Sure.

You mean just for the first quarter, John?

, For the year.

You're looking for a proforma c?

Exactly.

Bear with me. I'll tell you what might make some sense is for us to move on to the next question and come back to this one in a minute.

Ok.

Next question? Okay. I guess we've got the data here for the pro forma capital budget. This is Q1. No. Let's go on with the next question.

Could the moderator queue up the next --

Your next question is from Frank Barracken with Jefferies and company.

I've got two questions. One is easy to answer the other might take some looking around.

Jim highlighted current production rates at Nansen I was wondering if those were inclusive or exclusive of the Navajo tie in, particularly the 30,000 barrels a day of oil.

Yes, they are. They are inclusive.

Secondly.

We'll be looking to fill out that oil and gas leg later this summer. That's kind of the path we're headed towards. We actually switched out some wells.

Basically you get Navajo in, three dry trees on and you're probably full.

The problem, Frank, is we're close to full now, too. We're having to deal with the high gas volume.

We got the Navajo up to six and starting having head willing problems, so we're trying to back off a bit. That's what they are trying to work out now, get the maximum rate from the wells.

Secondly, as it receipts to Barnett shale, you walked through kind of a snap hot of what's going on in your horizontal wells.

You said you had seven that had come on and settled in about 15 million a day. What I was hoping to maybe get out of you is for the same dollars, I know it's not the same number of wells, but for the same dollars vertically, what would be your expected production to kind of give me an apples and apples of what the horizontals are doing versus the verticals.

Yeah, this is Brad Foster.

If you look -- let me give you a little bit of information on the horizontals. A horizontal is typically twice as much as a vertical.

When you drill a horizontal, what you see is you end up with about two to two and a half times more than a vertical well on the production side. You also end up with somewhere between two and a half to three times on the reserves.

So if you go ahead and take that, you'd end up with about 14 wells, you'd end with somewhere between 12, 13 million versus the 15 you're getting out of the seven wells on the horizontals.

Okay.

And then how are the horizontal wells going to affect your ability for refrac down the road?

That's a good question. And right now we don't know.

You know, this is something new to us, as far as the horizontals and frac'ing down there. We're drilling out 1500, 2,000 foot displacements. We're using three-stage, four-stage fracs. It's just too early to tell. It took us a lot of time to get to the light sand fracs.

I think once we see what the pressure is doing on the horizontal fracs, it will take us some time to find out the potential on the horizontals.

I appreciate it.

It's not just new for us, but the industry. We're pioneering on this.

The main story on the horizontals is not just that it improves the economics, which it clearly does in the core area, and it also allows you to go in the core areas and drill in areas underneath residential shopping centers and access some locations that you could not access with the vertical well, but the big story is that outside the core area, where we don't have the lower frac barrier that protects our ache regime is not successful at all.

How many of the 50 wells you're going to drill will be in the area where the lower frac barrier doesn't exist?

Right now we're sitting there thinking it's going to be somewhere between 20 and 25, depending on how things develop out there.

Those are primarily in Johnson county?

No, those will be west wise county, Parker county and Johnson county. Right now we're filing west wise, which is the western part of wise, which is outside the frac barriers where right now we have the most information and are feeling comfortable and encouraged.

Thanks very much.

Okay. We're running over our hour. We'll take one more question before we wrap up.

Next question is from David with South Coast Capital.

Actual Frank hit my question about frac barriers and additional wells.

Thanks a lot.

Got one more in the queue?

Your next question is from Shawn Reynolds.

Yeah, I wanted to know how many of the 50 were going to be outside the core area.

Thanks.

Okay.

Back to John Harlin's question I was wrong I do not have a proformeal capita budget what I've got is what we expect to report, 12 months of Devon and eight months of Ocean. And the breakdown is really consistent with what was in our 8-K today. I will get you a detailed capital budget on a pro.

Proforma basis and call you back in the next 30 minutes, John. If you anyone wants it and you call in today, we'll be glad to provide it.

Your next question is from Ray Tyson.

Just quickly here. Could you chat a shed a little more light on the east Tuscany, I thought you didn't have any plans to drill that this year.

And could you give us some idea of what you might be looking for there as predominantly an oil or gas. Do you have any predrill estimates.

This is Mike Lacey.

It's kind of an interesting story, this is a prospect Devon and Ocean came into from different directions.

You might update on east Tuscany.

We're waiting on discharge and other permits waiting to drill are in line there. We do have the millennium rig that is contracted to drill that well. So we're looking for probably a third quarter startup to theTuscany project.

And basically I think we've increased our working interest with the combination from Ocean and Devon to about 65%. And with EOG having the remaining we're looking forward to drilling that this year.

That's been on our drill schedule and we intend to do it. Pretty optimistic about that project.

Any predrill estimates the?

I think we're in the -- I think from a standpoint of total reserve sites on a mean basis we're in the 150 million barrel class.

Okay. Thank you.

There's only one more question in the queue. We're going to go ahead and take that.

Before we do that, John, we've added up the proforma capital budget numbers in round numbers. Let me go ahead and give the data that John requested.

In the Gulf of Mexico deepwater we expect to spend between 550 and 600 million on a combined basis. On the shelf we'll spend between 250 and 300 million. In Canada, we'll spend about 500 million for the full year. And then in the international arena, we'll spend about 500 million in the full year.

The balance is on shore U.S., comes to about 2 1/2 billion for a pro forma combined full year budget.

Okay. Next question.

Your next question is from Mark Meyer.

Thanks.

Larry, just a follow-up.

You had mentioned that the integration of the Houston office complete, I think, by July. Does that include Houston only or will you make decisions about Lafayette at the same ti?

Of course the July was combining the two offices in Houston, both Ocean and Devon are downtown Houston. We will maintain an office in Lafayette. Exactly how each of those offices are staffed is what we'll be working on between now and June.

Very good. Thank you for clarifying.

Okay. That ends today's call.

Thank you very much. Look forward to second quarter results.

Thank you, ladies and gentlemen for participating in today's Devon energy first quarter earnings results conference call.

As a reminder, this call will be available for replay beginning at 2:30 p.m. eastern time today through 12:00 p.m. eastern time on May 15th, 2003. The conference ID number for the replay is 9426302.

Again, the conference ID number for the replay is 9476302. The number to dial in for the replay is 1-800-642-1687 or 706-645-9291.

Thank you again for participating. You may now disconnect.