德文能源 (DVN) 2003 Q4 法說會逐字稿

Hello, and welcome to the Devon Energy Corporation's fourth quarter and year-end 2003 results conference call. At the request of Devon Energy, this conference is being recorded for instant replay purposes. At this time, I'd like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you, and thanks, everybody, for joining us on the call today to review our 2003 results. Larry Nichols, our Chairman and CEO, will begin by giving an overview and highlights. I will then return to discuss our fourth quarter operating and financial results, and, as is our custom, following my prepared remarks, we'll open up the call for Q & A.

We'll limit this call to an hour, but we'll be available throughout the day to answer any additional questions you may have. Before Larry begins, I have a couple of compliance items to cover. First, I want to remind everyone that Devon filed a Form 8-K this morning. This filing provides our our full-year 2004 forecast, including our outlook for oil, gas and NGLs production, expected price differentials, expenses, taxes, capital expenditures, and it also has a pretty detailed description of our hedged volumes for 2004.

Also, by popular demand, we are adding a breakdown of the U.S. into its onshore and offshore components and our guidance, and we will begin reporting that way for 2004. One other enhancement that we've added is a forecast summary table near the end of the 8-K. As I'm sure you've heard me say before, when we provide forward-looking information, we run the risks that our actual results will differ from our estimates, and a discussion of some of the factors that could cause our actual results to differ is included in our Form 8-K.

I also want to point out that we made some enhancements to the supporting data pack that accompanies today's news release. We're now including floating price differentials by product and area. We're also adding tables of drilling activity and numbers of rigs running. Also included today in today's news release are detailed reserve reconciliations and cost-incurred tables.

One other item I need to cover is non-GAAP performance measures. Current disclosure rules require that when we use a non-GAAP measure, that we reconcile it to the closest GAAP performance measure, and that we explain why the non-GAAP measure is useful. That information, as well as the Form 8-K that we filed today and today's press release, all those items are available on Devon's website. That address is www.devonenergy.com. With those items out of the way, let me introduce our Chairman and CEO, Larry Nichols.

Thank you, Vince. I want to begin by recognizing two members of Devon's senior management team, for whom this will be their final quarterly conference call. Mike Lacey, our Senior Vice President of Exploration and Production; and Bill Vaughn, our Senior Vice President of Finance and CFO. They're both retiring after lengthy careers with Devon.

Bill joined Devon in 1983, Mike in 1989. Since they've been with us 15 and 20 years, respectively, these gentlemen have been instrumental in Devon's growth and success, and I want to thank them for their many years of service. I particularly want to thank them for both staying on this past year as we plannedfor the merger of Ocean and carried out the integration of those two organizations.

I also want to bring to your attention some recent promotions within Devon's senior management group. John Richels has been named President of Devon. John had been in charge of Canada since 1998, when Devon acquired the Canadian independent Northstar. John is in the process of relocating in Oklahoma City. In addition to his duties as president, he will be the interim Senior Operations Manager, while we conduct a search for Mike Lacey's replacement. Another promotion is Chris Seasons, who also came to Devon with the Northstar acquisition. He will now head up our Canadian division.

Final promotion is that of Brian Jennings, a senior VP of Corporate Finance and Development. Brian will succeed Bill Vaughn as CFO. He will continue to head up our corporate development capital markets and treasury functions, and will also assume leadership of the accounting and financial reporting and tax. It is really gratifying to me that Devon has able to develop such a management depth that we're able to fill three senior positions from within -- from within our own talent pool of very qualified people.

Now let's move on to the other business of this call. The fourth quarter wrapped up an extraordinary active and profitable year for Devon. Our fourth quarter reported production was up year over year, and up sequentially. We increased quarterly productions 7% on a year-over-year pro forma same-store basis and 1% on a sequential quarter basis. For the full year, we delivered organic production growth of 5.5% at the high end of our guidance. As you will recall, we've been predicting all year long that we would come in between 4% and 6 %. We came in at 5.5%, and we're very pleased with that. For the year we also set all-time records for annual production, revenues, net earnings, and earnings per share, breaking our records in all of those categories.

For the full year, we earned over $1.7 billion, or $8.07 per diluted share. Back-counting items that analysts don't typically don't forecast, we earned $17.16 per diluted share, beating the first call mean. Cash flow from operations was $1 billion for the quarter, a strong $3.9 billion for the full year. This cash flow, as we've been saying all year -- as predicted all year, would allow us to fully fund our $2.5 billion drilling and facilities budget, meet all of our other cash demands, and at the same time retire over $500 million of long-term debt.

During the year, we reduced our net debt to cap ratio from 60% to 41%, coming in lower than most people had forecast, and we generated in the fourth quarter alone $433 million in excess cash, which allowed us to end the year with $1.3 billion of cash on hand, which is earmarked for debt retirement this year, 2004, and 2005. Also during 2003 we supplemented our portfolio of properties and improved our growth outlook with the Ocean merger. We also substantially -- we have substantially integrated Ocean and Devon organizations. We consolidated all of our Houston employees into one downtown location, this including closing our office in the Woodlands and bringing those people, as well as closing a number of our -- of taking a number of our employees from Lafayette to our downtown Houston office, and some of those people to our Oklahoma City offices. So we've improved the efficiency of our operations.

With drilling and acquisitions during the year, we replaced over 300% of our 2003 production, had an overall finding cost and development of $10.82. We finished the year with 2.1 billion barrels of prude reserves. Although not reflected in our reserves or finding costs, we had meaningful success with our high impact exploration program, our deepwater Gulf of Mexico discoveries, at St. Malo a discovery; and Sturgis, our earlier Cascade discovery, are all very significant.

During 2003, we also sanctioned our Jackfish thermal heavy oil project in Alberta. As we delineate these discoveries with follow-up wells in 2004, and as we begin development of Jackfish, we will move much closer to the point where our reserve bookings will reflect the fruit of these long-term, high-impact investments.

Before I turn the call over to Vince, I want to take just a minute to touch on reserve integrity. Oil and gas reserve bookings and review practices have understandably come under the microscope recently, as a result of some rather surprising announcements. Let me describe Devon's approach, and this is not a new approach, it's what we've been following ever since we were public, and, in fact, it's been our attitude ever since we started as a private company. First, the reserves of all of our international and Gulf of Mexico properties are determined by an independent firm, Ryder Scott, every year. That means they get the raw data and they establish those reserves themselves.

In Canada, another independent firm, AGM Petroleum Consultants, evaluates on a rolling one-third of our properties each year, so that all of our Canadian properties are evaluated by outside engineers on a three-year cycle. For the U.S. onshore, individually significant properties are prepared or audited by two sets of engineers. One is LaRoche & Associates, and the other is Ryder Scott, and the minor properties are engineered in-house. This results in independent engineers working over half of our U.S. onshore reserves each year. You add all that up, and over any three-year period, more than 95% of our company-wide reserves are either prepared or audited by an independent firm.

We believe this approach gives a high degree of assurance and a cost-effective manner. I might add anecdotally that, during our entire 15-year history as a public company, we have never had a negative performance-related reserve revision that would have any consequence to our reserve base overall at all. Now, let me turn the call over to Vince for a more detailed financial analysis and operational update. Vince?

Thanks, Larry. My comments today are organized around three main topics -- topic areas. I've got a lot of ground to cover. First, I'll cover operating highlights, then I'll talk about our reserves reconciliation and finding costs, and finally, I'll provide a brief financial analysis.

Starting with the fourth-quarter operations, I'll begin with a quick activity summary. At the end of the year, that's the end of 2003, we had 113 rigs running company-wide. Seventy-nine of these were Devon operated and 34 were outside operated.

Total upstream capital, that is exploration and development capital, in the fourth quarter was about $850 million. That brings our full-year 2003 exploration and development capital to $2.5 billion. With that, we drilled 2,229 wells during the year; 293 of those wells were classified as exploration, and we had a 79% success rate on the exploration wells. The remaining 1,936 wells were classified as development wells, and 97% of those were successful.

In the Barnett Shale, this is in North Texas, we have 12 rigs running currently. Six of them are drilling horizontal wells, six vertical wells. And, despite some plant downtime and minor operational interruptions that we had during the fourth quarter, our average production from the Barnett for the fourth quarter was 575 million cubic feet per day. That's just about flat with the third quarter and about 22% ahead of the fourth quarter of 2002 on a NCF equivalent basis.

In the fourth quarter of 2002, we produced 470 million cubic feet equivalent per day. We currently have a little over 1600 wells producing in the Barnett. Of these, 53 are horizontals and those 53 horizontals are producing 69 million cubic feet equivalent per day. Of those 53 horizontals that are currently tied in, 35 are within the core area and 18 are outside the core area. The 18 horizontals outside the core area are producing 16 million a day. However, the last six horizontals that we completed outside the core area had IPs averaging a little over 2 million cubic feet per day per well, so we are very encouraged by that progress.

In 2004, we plan to drill 94 horizontal wells in the Barnett, with 52 of those outside the core area. We also have 98 vertical wells planned for inside the core area. We've just completed a study and we've identified over 270 additional vertical locations in the core area, so we have the option to drill additional verticals in the core, should we decide to do so. In any case, we feel like we've got a good shot at increasing production from the Barnett again in 2004.

Moving now to the Washakie Field in southern Wyoming. Our working interest here runs between 90% and 100%, and we completed 18 wells in the Washakie during the fourth quarter. That brings our total for the year up to 38 wells. We are currently -- have six rigs running in the Washakie, that's an all-time high, and what's really driven that is an improved permitting and regulatory environment. We plan to drill a total of 40 wells in 2004 in the Washakie, and we have most of the permits for those wells already in hand. Our net Washakie production is now at an all-time high at almost 90 million cubic feet per day.

In the Powder River Basin, we drilled 33 coalbed methane wells in the first -- in the fourth quarter. That brought the total in the Powder up to 86 for 2003. The increase in drilling activity in the second half of the year reflects the easier permitting there as well. Q4 production was up about 3 million cubic feet per day over Q3. Q4 production averaged 88 million a day.

In 2004, we plan to drill 110 new wells in the Powder. Eighty-five of those wells will not be the traditional shallow Wyodak coals or either deep Wyodak or Big George wells. We're also planning an active recompletion of well deepening program for 2004 in the Powder. In the San Juan basin, most of you know that that's the play that really put coalbed methane on the map. We've received approval for downspacing on all our acreage. We drilled 13 infill wells in 2003 and we plan to drill 65 in 2004. Those 13 infill wells in 2003 flattened our decline there, and we expect to increase production with our infill program in 2004.

In East Texas, we continued with the five-rig drilling and recompletion program in the fourth quarter. We drilled 21 new wells and recompleted 10. The net production from our East Texas fields, this includes Carthage/Bethany and Groesbeck, is currently running at about 225 million a day. In 2004, we plan to drill 80 wells and recomplete 90 wells in this area. And we have a -- we have a big drilling and recompletion inventory in East Texas. This is going to keep us active for the foreseeable future.

In Canada, the -- the winter drilling program is now at its peak. In January, we had 48 Devon-operated rigs running. Because a lot of the areas that we operate in Canada are winter-access only, December through March is typically our most active period. During that period this year, we plan to drill about 400 wells and spend about $360 million or roughly half of our full-year Canadian capital budget.

The winter drilling program this year is focused in three main areas: the deep basin, northeast B.C., and the northern plains. The deep basin is our most active area this winter. We currently have 16 operated rigs running there. We expect to drill 106 wells in the deep basin. That's up from 71 wells drilled in last winter's drilling program. I said we would also be active in northeast B.C.. We have over a hundred wells planned this winter compared to 76 last winter, and in the northern plains we expect to drill about 93 wells in this winter program compared with 73 last year. You can see from our guidance that Canadian well production is expected to grow a lot and these drilling programs are contributing to that.

Turning now to the offshore U.S., I'll begin with an update on Nansen and Boomvang. In our third-quarter conference call we told you that two satellite wells had been drilled around the Boomvang area and were successful. Both of these wells are currently in the process of being tied into the Boomvang facility. That will add about 3 or 4 thousand equivalent barrels net to Devon's interest later during this month.

During the fourth quarter there were two wells successfully completed in the Boomvang area. We are -- the sub-sea work is going on. Those wells will be tied into the Boomvang facility in the third quarter and those two wells will add another 4,000 barrels a day, approximately, net to Devon's interest. The continued success that we've had in the Boomvang area with these satellite discoveries is helping us to hold up production out of that facility.

At Red Hawk, that's Garden Banks 876, the construction of the cell spar and top sides is moving along on schedule and on budget. We expect the spar to be towed to location in March. The topside installation is scheduled for May. First production is expected in the third quarter of this year at about 10,000 barrels a day net to Devon's interest. At Magnolia, this is on Garden Banks 783, the wells have now been drilled and are awaiting the production facilities.

The construction of the Pension Lake (phonetic) platform continues. The hub is actually on its way. It rounded the Cape of Africa in late January, moving from the construction yard in Korea to the U.S. Gulf, where it will be installed. First production's expected around the end of the year, and I will remind you that we expect a peak right here of between nine and twelve thousand barrels equivalent a day, net to Devon's interest. Early design work is in progress for a potential deepwater hub facility. That could bring our Merganser and Vortex discoveries into production in 2006. This project, if it goes forward, would bring together several deep-water discoveries by Devon and other industry parties in the Atwater Valley area.

In our deepwater Gulf exploration program, both York and Hawkes have been plugged and abandoned. And while Hawkes encountered hydrocarbons, the well location itself was deemed uneconomic. Our net cost for these two wells was about $40 million, and that money's not totally down the drain. By drilling Hawkes, we earned a 25% interest in Exxon's previous discovery on that block and we also think there may be another drilling opportunity that we've now earned the right to participate in.

The Toledo well, this one's Alamosa Canyon mine 51. We had 25% of that one. It was determined to be non-commercial. Toledo was a lower Tertiary test and it was the third of four commitment wells in our Chevron Texaco JV. Our net cost for Toledo was $18 million, including the promote. We plan to spud the fourth commitment well in the Chevron Tex JV next month. This is on the Jack prospect. Jack lays just west of our St. Malo discovery on Walker Ridge 759 so we're pretty hopeful for Jack. Like St. Malo, it tests the -- the lower Tertiary H prospect.

When we complete the drilling of this fourth and final commitment well in the Chevron-Texaco JV, we will have earned 25% of Chevron-Texaco's interest in 71 deepwater blocks. And while this will complete our commitment under the JV, we expect to continue to explore on this acreage with Chevron-Texaco well into the future. We've currently got nine additional prospects identified on the acreage. And I might add that we've already had what looks like a Miocene discovery in the JV with the wild cat that was drilled at Atwater Valley 182 on the Sturgis prospect. We plan to drill an appraisal well at Sturgis during 2004. We also have appraisals planned for our lower Tertiary discoveries at both Cascade and St. Malo during the first half of 2004.

Moving now to the Gulf Shelf, we are approaching first production from the Gray's Field located on Galveston 424. Devon drilled the initial Gray's discovery well in April of 2003. This was followed by two additional successful wells in the third quarter. We expect first production next week of about 30 or 40 million cubic feet per day, net to Devon's interest. We operate Gray's with 100% working interest in one of the wells and 65% in the other two wells. Internationally, we drilled 19 wells in the fourth quarter. We had 10 rigs running at the end of the year.

In China, development drilling on Panyu, that's a Devon-operated field in the South China Sea, that continues to go well. During the fourth quarter we drilled and completed six wells. The project calls for a total of 27 producing wells. Gross production in Panyu is now over 50,000 barrels a day from eight wells. And Devon's net share of that production is currently running about 15,000 barrels per day and should average about 16,000 barrels a day for 2004.

In Equatorial Guinea, this is offshore West Africa, the Zafiro field continues to exceed our expectations. Total gross field production has been in excess of 290,000 barrels per day. In the southern expansion area, the 11 wells that have been drilled there are currently producing 105,000 barrels a day. This is into the relatively new Serpentina FPSO. We have a total of 14 wells producing -- will have 14 wells producing by the fourth quarter in the South southern expansion area. And our current share of field-wide production from Zafiro is running a little over 55,000 barrels a day net, to Devon's interest.

Elsewhere in west Africa, the N-1 (phonetic) exploratory well, this was on block N in Equatorial Guinea, and the Zinza prospect offshore in Gullah, both of those exploratory wells were unsuccessful. In Egypt, this is east side C 5, the -- we have a 55% interest in this one, and it looks like a good discovery. It was hooked up to our existing facilities, began producing this week at 6,000 barrels a day. It was a successful exploration stepout to a new area, found original pressure. We're going to monitor the production performance of this reservoir and evaluate the potential for drilling two additional locations on this block.

I'm going to move now to our year-end reserves and finding cost results. We've provided a reserve reconciliation and costs incurred table. This is on pages 11 and 12 of today's news release.

We entered 2003 with total reserves of 1.6 billion equivalent barrels. Of course, we closed the Ocean merger during April. This added 556 million equivalent barrels. Discoveries and extensions for the year added another 188 million barrels equivalent. And those additions will reduce by 11 million barrels of revisions and divestitures of 25 million barrels. When you sum it all up, you'll see that we booked total additions for the year of 733 million equivalent barrels, that is 321% of our 2003 production. So, healthy reserve replacement rate. When you take out the additions, back out the divestitures and revisions and the -- what we produced during 2003, you'll find we ended the year with 2.1 billion equivalent barrels of estimated crude reserves.

Looking at the finding and development costs, the cost for the year for acquisitions, exploration, development, and capitalized expenses totaled $7.9 billion. That gives us an all-sources F&D of 10.82 per equivalent barrel for the year. Our so-called drill-bit-only F&D was about $15 a barrel. I'll point out that, while this -- this matrix commonly referred to as -- as drill-bit only F & D, the development of crude reserves that we acquired in the Ocean merger and in recent -- other recent acquisitions, pushed this number a lot higher than it otherwise would have been. And as evidence of this, we reduced our percentage of reserves classified as proved undeveloped from 30% following the Ocean merger, to about 24% at year end.

Those F & D numbers are pretty much in line with the guidance that we provided in our September executive briefing, so we don't expect them to surprise anybody. In any case, we're really not satisfied with these results, but we believe that, as the long-term investments that we've been making over the last few years at least start to show up in our reserve bookings at places like Sturgis, Cascade, St. Malo and our Jackfish SAGD project, we think that our F & D should return to competitive levels. As a reference point, I'll point out that our five-year all sources F & D is $8.25 a barrel.

Turning now to the financial results. I'm sure that most of you recall that our merger with Ocean closed on April 25th of 2003. Since that transaction was accounted for as a purchase of Ocean by Devon, Devon's 2003 results only reflect the eight months of the impact of the Ocean assets.

Starting with production, company-wide production of oil, gas and NGLs on a recorded bases came up to 227.7 million barrels equivalent. That represents a 21% increase over the reported 2002 number. When you add the 18.8 million barrels that Ocean produced for the first four months of 2003 before we closed the merger, you'll find that we had 2003 pro forma production, that's as if Ocean and Devon were merged all year, of 246.5 million equivalent barrels. That compares to total 2002 production from retained properties for Devon and Ocean combined of 233.5 million equivalent barrels. That yield same-store sales growth that Larry referred to of 5.5% in 2003, and as Larry pointed out. that's near the top of our guidance range.

In the fourth quarter of 2003, total production came in at 64 million equivalent barrels, at 696,000 barrels a day average. That's a 7% increase over fourth-quarter 2002 production from retained properties for Devon and Ocean combined. Fourth quarter production also grew on a sequential quarter basis, up about 6,000 barrels a day or right at 1% over third-quarter 2003 production.

Looking forward to 2004, we're again forecasting total production growth of 4% to 6%. That's from 256 to 261 million equivalent barrels. As far as the profile throughout the year, I want to point out that we now expect Zafiro to pay out a lot earlier than we previously estimated. That's due to the strength of oil prices in late 2003 and early 2004. The earlier payout reduces Devon's share of production sooner than we previously anticipated, but of course from a return perspective, that's clearly a good thing. In any case, we now expect payout to occur sometime during the second quarter of 2004 and that's built into our guidance. When that occurs, Devon's company-wide reported production will drop about 7,000 barrels per day. As a consequence of that, we expect second and third quarter production to be a little below the first quarter and then to pick back up in the fourth quarter with the incremental production coming on from Red Hawk, the recent discoveries at Nansen Boomvang, and a few other areas. In total, we expect production to be slightly less in the second half of 2004 than during the first -- than during the first half.

Looking now to fourth-quarter product price realizations. 2003 oil, gas and NGL prices were all up significantly over 2002. Devon's floating price realizations, that refers to the prices that we received for our oil and gas that's not subject to color, swaps or fixed-price sale agreements, those floating price realizations came in pretty much in line with our guidance with just one exception that I want to mention. Our realized price on floating gas in Canada averaged $4.38 per MCF in the fourth quarter, which is just 20 cents under the NYMEX Henry Hub. That's much higher than the realized price that we forecasted of 60 cents to a dollar ten under Henry hub for Canada.

There were several factors that contributed to those unusually high fourth-quarter Canadian realizations, which included unusually strong relative prices at the ACO hub in Alberta. Looking forward, though, we expect the differential for our Canadian gas to widen to the more normalized level of 60 cents to $1.10 below Henry hub.

Moving now to marketing and midstream. In the fourth quarter our marketing and midstream revenues were $357 million, and the associated expenses were $273 million. That generated a marketing and midstream margin of $84 million. That's an all-time record for this part of our business, and it exceeded the midpoint of our forecast by about 20%. This part of our business continues to perform very well.

Looking forward to 2004, we forecast the full-year marketing and myth midstream margin to come in between $210 and $230 million. You may recall that for 2003, we forecasted a range for the marketing and midstream with a midpoint of $193 million and then we have blown out that number to a higher-than-expected NGL spreads and a number of cost-cutting initiatives that have been put into place during 2003.

Moving now to expenses. Most of our 2003 expenses were in line with our guidance. On a year-over-year basis, almost every expense category increased on an absolute level, just as a result of the much larger size of the company following the Ocean merger. Due to the large operation that we have in Canada, the weakening U.S. dollar also put a lot of pressure on our lease operating expenses, general administrative expenses and D D & A, as those are expressed in U.S. dollars. We expect this to continue in 2004. I just point out that our 2004 guidance is based on an exchange rate of .76 to one. That is, .76 U.S. dollars to one Canadian dollar. That compares to an average exchange rate in 2003 of a little under .72 to one.

For 2003, DD&A came in at $7.87 a barrel. That was slightly higher than the top end of the full-year forecast of $7.82 a barrel. We are forecasting our 2004 DD&A rate to be in the range of $9.00 to $9.30 per barrel. The increase in '04 reflects the strengthening Canadian dollar, a full-year impact of the Ocean acquisition and the impact of our 2003 finding and development costs.

Next item I want to cover is G&A expenses, general and administrative expenses, that is. Fourth quarter G&A came in at $86 million, or about $7 million higher than we expected. There were two items that drove that overrun. First, we had $3.6 million of unbudgeted severance expenses in the fourth quarter. And the other item is that $5.4 million of G&A expense recorded in the fourth quarter was related to a change in the market value of investments held in a deferred comp plan. This is a non-cash charge and it is completely offset by increases in other income and comprehensive income, but it does cause volatility in our reported G&A expense.

Looking ahead, we expect full-year 2004 G & A to total between $305 million and $325 million. Included in the 2004 G & A estimate is an additional $6 million of severance expenses that will be paid in the first quarter of 2004. Even with those severance expenses, our G & A per barrel in 2004 is the estimate -- the midpoint of the estimate's about a $1.22 a barrel.

During the fourth quarter we recorded $111 million pre-tax or a $74 million after-tax reduction in the carrying value of oil and gas properties. This non-cash charge is related entirely to certain of our international concessions, and reflected in that charge is our decision to impair exploratory blocks in both Brazil and Ghana. Interest expense came in on budget at $502 million for the full year 2003.

Looking forward to 2004, the midpoint of our estimated range is $515 million. That may surprise you. Since debt is going down, reported interest expense going up is counterintuitive. The increase results from a reduction in the portion of our interest payments that we will capitalize. Certain long-term projects, such as Panyu and China and those in the deepwater Gulf, have been completed now, and so less of our interest qualifies for capitalization. Of course, looking forward, as we retire debt in 2004, 2005, we expect our actual interest expenses to come down.

The final expense item I want to touch on is income taxes. We recognized a deferred tax benefit in the fourth quarter. That is related to recently enacted reductions in Canadian federal income tax rates for the next few years. This change allowed us to reduce our deferred tax liabilities recorded in prior years, and resulted in a benefit recorded in the fourth quarter of $218 million. Disregarding this out-of-period effect, you'll find that our 2003 taxes were $732 million. That's 33% of pre-tax earnings, and 24% of -- of the pre-tax -- or the income tax was deferred tax expense, 9% was current.

For 2004, we expect our consolidated financial income tax rate to be between 25% and 45%. That's unchanged from our 2003 guidance. However, our guidance on the split between current and deferred taxes is changing significantly. The 2004 forecast is for current taxes to be about two-thirds of the total tax bill and deferred taxes to be about one-third.

Cutting all the way through to the bottom line, we reported net earnings of $543 million, or $2.25 per diluted share. The non-cash items that are typically excluded by securities analysts and their published estimates are detailed in the press release. And aggregate, those items increased second quarter net earnings by 63 cents per diluted common share. When you adjust for those items, we had earnings of $1.62 per diluted share, and that's 15 cents over the first call mean. That level of earnings translates into cash flow before balance sheet changes of $1.049 billion for the fourth quarter.

Summarizing, the fourth-quarter wraps up a year of record production, record earnings, record earnings per share, and while we definitely need to restore our finding and development costs to the competitive levels that we've delivered in the past, we think the 2004 delineation of our major discoveries in the Gulf should give us some visibility to that objective. That ends up my -- wraps up my prepared remarks. We'll now open the call to your questions.

Thank you. At this time, we will begin our question-and-answer session using our polling feature. If you have a question at this time, you may press star one on your telephone touch pad and you will be prompted to record your name for pronunciation purposes. Should you need to withdraw your request, you may press star 2. If you are using speaker equipment, you may need to pick up your handset prior to pressing star one. Once again, that's star one if you have a question and star two to withdraw your request. One moment, please, for the first question. And our first question comes from Arjun Murti.

Thank you. I'm with Goldman Sachs. I just wanted to follow up on some of the reserve replacement and S & D comments you all were alluding to. I mean, I think, in round numbers, you've historically, from the drill bit only, replaced something like, you know, 70 to 80% of your production. And it sounds -- and that's basically been from, I believe, lower or medium risk exploitation and exploration. It sounds like continuing those programs, plus some reasonable success case on the high-risk stuff, plus the discoveries you've already made, plus Jackfish, can get you to something meaningfully above 100%, let's just call it a sub-$9 per barrel of oil, coalbed (inaudible). Is that a fair characterization?

This is Brian Jennings. I think that is a fair characterization. We have made investments -- actually, for the past several years, in exploration projects, which -- some of which we will have the opportunity to delineate in 2004. Some of which will be delineated late in the year and moving into 2005. So we've got a lot ahead of us and a -- as you describe, a good opportunity to -- to get to that very competitive levels of -- of our peers. So we feel we've got the right pieces in place right now, but as Vince pointed out on the call and as Larry's pointed out, we recognize the challenge. But I think we're well positioned to achieve that -- that target you had talked about.

And I guess, you know, we certainly recognize that the exploration component can be uncertain and volatile and it's high risk.

But if we think of deep Gulf as, on average -- and I know there's a variety of different types of prospects - but having some maybe reasonable or base-case success scenario 20 to 30%, if you end up making more discoveries at a greater rate than that, then we should be particularly excited about being well above 100% and obviously, if the rate is lower than that, then we may be more concerned about it cheaper than 100%, is that fair?

I think we're confident we can replace more than 100% of production with a program we have in place today. Of course, in addition to the -- to the attractiveness of the Gulf of Mexico, we can control, we believe, our timing in that basin. Not only are we able to identify reserves but bring them on-line into production and to the bottom line. And a time schedule that -- that we find to be attractive.

That's very helpful. And just one follow-up. In terms of prioritizing free cash flow, I know you saved up some of the cash to pay down some of the debt this year, but for additional free cash flow in '04 from good commodity prices, is the idea still to reduce net debt, even if you don't pay down actual debt, or is there some other use of free cash flow?

You know, our first and foremost we're going to fund our budgets, which we have laid out, and we believe that budget will allow us to continue to grow production next year while we continue to make investments in exploration, and we'll have another big exploration year next year. Beyond that, we do have significant maturities in -- in '04, actually less than '04, but in '05 and we'll be well positioned to actually repay those with cash on hand today. Right now we're very comfortable with our budget and will continue to maintain financial discipline with that -- with capitals built in the -- in the bank.

Yeah, Arjun, (inaudible). I think it's $339 million that we can pay this year.

Right.

So -- which is why we've been building up the cash on hand. So we're in an excellent position with all that cash, we can pay off all of '04 and '05 maturities.

Yes. I guess sort of the -- the other question was I think you all feel more comfortable with the balance sheet now than you did, you know, a year and a half ago at the time of the deals.

Having brought the ratio down from over 60% to 41%, you know, that's below a lot of people thought where we'd get to at this time. We're pleased with that result. And obviously next year -- or this year, 2004, with any kind of decent oil and gas prices, we ought to get down into the mid-30 range somewhere.

Yeah. We would expect our net debt-to-cap and recognizing we'll continue to build up cash as maturities come along, but we would expect net debt to -- net debt to cap, given this price environment to be in the mid-30s by year-end.

That's great. Thank you very much.

Thank you. And our next question comes from David Khani from Friedman, Billings & Ramsey.

Yeah, hi, guys. A quick question on the Barnett. How much volumes did you lose from the plant downtime, fourth quarter ?

Yeah, this is Darryl. Actually, in terms of -- of shutting and production, we didn't have to shut any production. I mean, a minor amount, maybe four or five million a day over a course of about three or four days in some areas, but we could not process the gas because we had some problems with the plant. So we actually re-routed the gas around the plant, and that reduced the number of NGLs that was available, but increased just slightly the number of MMBTUs we had to sell.

The NGL extraction process adds -- adds production on a -- on an equivalent basis.

Right.

Darryl, while you're there, can you give a forecast what you see for the natural gas prices, given the volatility, and right now price seems to be coming down.

Well, that's a hard one. It gets more difficult each -- each year, I guess, to look at this. You know, from a fundamental perspective, what we see in the U.S. and in Canada is, at best, flat production. Some of the indications are that that production's going to trend downward rather than upward.

You're talking about the nation overall?

Yeah, nation overall. It's going to trend downward, flat to downward. On the demand side we're starting to see some rebound in industrial demand. Of course we've had cold weather in the northeast, as you know. It's now moved down into the Midwest, so we're starting to see some pickup and increase in demand there. If the economy keeps on rolling the way it has over the last four or five months, we see some industrial demand come down. You know, we should see supply and demand be pretty well in balance and remain fairly tight.

Great. Larry, I guess Arjun was trying to see if maybe stock buyback was in the cards, given that your balance sheet was getting fixed fairly quickly. What -- what's your comment to that.

Well, as we've said, and this is -- is not new, although we're closer to that point now with more certainty as we said in our meeting with investors last September, as we built up cash flow and strengthen the balance sheet, looking at increasing the dividend, we recognize our dividend as a -- far below our peers, is certainly something that we can address with the board. We have not done that yet, but bringing that dividend more in line is something that we can address and, you know, buybacks are certainly another possibility, based on -- as the cash accumulates. We're not going to, just because the cash is there, spend it on -- on projects that don't make long-term economic sense based on -- on very conservative oil and gas prices. And based on where the stock price is and -- and where our cash is, buybacks are certainly a possibility.

Okay. Last question. Given that it's such a hot asset market, is there any opportunity to take some -- opportunity to sell some assets in this environment?

We always look at cleaning up our portfolio. You know, we just sold the -- our Cherokee coalbed methane plant for over $100 million. So, you know, there's hardly a year that's gone by that we have not found some property that was not meeting return hurdles that we want, not performing as we want, where we find someone who thinks it's more valuable than we do, and if we do that, we'll sell it. It's hard to predict that now, because we've done a lot of that clean-up over the years as we've sort of made acquisitions. So I don't know that there will be anything significant, but that's certainly a possibility.

So nothing really planned for this year that you -- of big importance?

No, nothing planned of any consequence this year. And, of course, we'll continue to look at acquisitions, both large and small. It's hard to predict those. You know, we're real happy with the asset base that we have now, both the balance of the -- the capital budget with some exciting explorations, but a lot of close-in safe drilling in the Powder River and the Barnett Shale and in Canada, which is producing the high percentage success rates that we talked about earlier. You know, we're happy with that. So we're not -- don't feel compelled to go do anything. But if we find something that we think would be accretive financial and hold the value, we'll look at it.

Great, thank you.

Thank you. Our next question comes from Van Levy with CIBC World Markets.

Good morning, gentlemen. Congratulations on getting your debt down so rapidly.

One question I had, if I went up on the finding cost on the last three years' drilling revisions, I'm coming up with a number of about 427, a big number. And, it seems to me that, you know, you'd have to add, you know, clearly these reserve adds are lumpy, but you'd have to have a tremendous amount of reserves at very low cost to get this within a reasonable, you know, metric. Larry, could you comment on kind of what your targets are? I'll also note, I guess over the last three years you spent about $1.4 billion on exploration out of 17.6. So that's only 8%. You guys are known as one of the most rational, I think, companies out there. This seems to be a bit irrational to me.

I'm not sure what seems irrational. We've been -- the last three years, we've been building, you know, a base to grow in the future. We built a lot of PUD locations that, you know, you can't look at a drill-bit only when you're doing acquisitions, you've got to look at the all-in costs. To separate drill bit and acquisitions is not meaningful given the acquisition level that we've done.

It's a question of where you allocate the capital between -- you know, if you buy the reserves for the acquisition and allocate the capital in the -- the drill-bit, you come up with meaningless numbers. We have brought the PUD down as a per cent. We said all year that that was one of our goals, and we said that both in 2003 and in 2002, that our goal was to bring the PUD down. We have brought it from 30% down to 24%. Very much in line, if not below the average, of PUD for a lot of our peers, so we've got that back in line. With that back in line and as we bring on the -- a lot of the longer term major projects where we've been spending money, you know, we think that that F & D cost will become very competitive over time.

Van, this is Vince. I would add to what Larry said. If you look at our reserve replacement rates and our F&D, and you presume that we could add in the range of 50 to 100 million barrels from this high-impact stuff on an annual basis, which, you know, given that we're getting exposure to multiple prospects with potentials from 250 million barrels up to close to a billion barrels per opportunity, that is not an unreasonable rate to expect to get incremental reserve adds. And that would clearly push us over 100%. And I haven't run through the math, but it does a lot for bringing our -- our F&D to competitive levels. So I don't think it's out of the realm of reason or even probability to think that that will occur.

I might draw an analogy with you. Two years ago we made two large acquisitions at the same time, Mitchell and Anderson, when gas prices were high. We were very much looking toward the long term, though we incurred a lot of debt to do that. And there are a lot of people that doubted whether we could bring our debt down. The debt today is lower than anyone expected would be within that time frame, and with the record cash flow and record earnings that we're -- we're reporting, clearly the wisdom of that, although it wasn't entirely apparent to the street at the time, has proven itself.

Similarly, we understand full well that people can look at the drill bit only F&D and say it's a high number and doubt that. We think our long-term plan that we have on F&D is going to work just as well as our long-term plan we had two years ago to bring the debt down. That worked and so will -- it will for F&D.

So essentially what you're saying is, in 2004, 2005, as you move through these -- shift in the PUDs and again the front-end costs, that we should see this drilling revision number come down pretty substantially.

Absolutely.

Okay. Thank you.

Thank you. And our next question comes from Mark Meyer with Simmons and Company.

Good morning. Larry, a couple of questions about, I guess, future reserves booking, particularly related to Jackfish, and whether or not we'll see anything in '04 and really what the -- what the schedule is and if the number's still 300 million barrels?

So far we've booked nothing in Jackfish, just as we booked zero reserves at St. Malo and Cascade and some of those discoveries. It's hard to say at this point exactly whether we'll get any of those major projects booked in '04. They certainly can start being booked in '05. And we are pushing as hard as we can to get some of those into '04 to try and tie the bookings closer to when we're spending the money.

Okay. Thanks.

Or, you know, it's a close call exactly how much of that we'll get in '04.

On the Barnett Shale-related question, with respect to your PUD-booking philosophy outside of core area, could you -- could you shed a little light on how that may be different than kind of your bread and butter onshore U.S., or is it pretty much the same? Not having insight into what your current well geometry is, how many offsets are you booking?

Well, we, as a broad statement, you know, we've always wanted our goal is to have our PUD bookings be very conservative, at least average or below average in relationship to the industry. You know, it's very easy to get really kind of ahead of yourself and get wild and book a lot of PUDs. That can produce some nice short-term results.

Over the long term, you've got to drill those wells and sooner or later you can run out of them if you get too aggressive, and you've seen that happen in some of the major reserve revisions with Shell and some of the others, where they got ahead of themselves in booking PUDs. We have always tried to be conservative in that and brought that -- said we'd bring that down, and indeed, we have. With regard to the Barnett, I'm not --

This is Mike Lacey. Brad Froster can probably answer this better than I can, but the majority of -- if not all of our PUDs we have in Barnett are located inside the core. We're still doing a lot of exploration work, if you will, outside the core from a technological standpoint, trying to see what works and trying to really understand that, and Brad, you might fill in here, but I think if we have any PUDs booked outside the core, it's a limited amount.

It's very few. I think you've hit it right on the head, Mike. Most of our PUDs right now are inside the core and we -- we have a handful outside the core.

You know, I -- this is Vince. I'd point out that the percentage PUD on the Barnett is much lower than when we acquired the asset, and that's true of the Mitchell assets overall, and really of the -- the -- our history of acquisitions, for instance, in Ocean, Ocean had a pretty high PUD component and we've already brought that down considerably during -- on those assets during 2004. So to the extent that our peers or the companies we acquire have a higher percentage of PUDs, when we acquire them, our history has been to bring that down.

That lower percentage of -- of PUDs does not reflect anything on the quality of the reservoir. If we wanted to, we could book more PUDs there and be more aggressive and push the envelope, and that would -- would help this year's F&D costs for those that look at drill bit only on a year-to-year basis. But that's not the way we try to run this company.

Thanks. One more for me. On the eastern Gulf of Mexico, it sounds like momentum accelerating in terms of putting together a joint industry development plan. In terms of economic threshold, how do we think about that? Is that -- is that a number closer to 500 Bs or something closer to the T, or do you have any comments on that?

That may be just too early to tell at this point. And, of course, as we work with other industry participants and pipeline companies, we'll obviously get better definition on that, but too early to tell at this point.

Thanks.

Thank you. And our next question comes from Shawn Reynolds from Petrie Parkman & Company.

Hi, guys. I wonder if you can make some comments about the new core-area locations you have in the Barnett. You said you added some locations. is that actually in-filling or are you thinking there's some refrac possibilities?

Shawn, this is Mike Lacey again. Most of the -- the opportunity, the PUD opportunities inside the core, are drilling opportunities. Large percentage of those are -- are verticals, still taking down -- going down to the -- what's been termed the 27-acre infill. It's really 40-acre infill , that we think will drain about 27 acres. There are a number of -- a smaller number of horizontal wells that are included as PUDs in there. On the refracs at this point in time, I -- I think, particularly, with your technical background, you understand this. But we have to draw the pressure down in an existing well bore in order for the refrac to work. And that -- that -- drawing that pressure down can take up to five years. So the -- the refrac potential, I think, is still out there, but we don't have much of that on the books at this point in time.

All right. So those additional, I think you said 270, verticals is just the infill?

Yes.

Right. And this, you know, might be somewhat facetious. But, given the way you're trading right now, Larry, you could basically hedge out your volume for three and a half years and buy the company back. What do you think about that?

I think I'll go think about that.

We've -- we've got time for one more question. We have actually gone over but we'll take one more question before we cut it off today.

Okay. Thank you. And our final question comes from Frank Bracken with Jefferies & Company.

Just a couple quick questions. One, you're talking about turning your production profile around in the San Juan, drilling 65 infill wells there. How many -- what is that as a percentage of your total population? I mean, do you have hundreds of these things to do or can you give us a handle on -- on what kind of legs this downspacing will have for you in the San Juan?

This is Don DeCarlo. It'll basically probably take about maybe 30, 35 per cent of our inventory in 2004. So we've got a couple of years of downspacing there. We had a pretty good year in '03, '04 will be relatively robust and I would expect a pretty solid year in '05. So we've pretty much done the decline and expect a modest growth here in the next year or two.

Got you. And then, secondly, I think the quote was you have a good shot at increasing production in the Barnett Shale. Does that mean year over year, or does that mean from current levels?

You know, if you -- let me just tell you, we've budgeted a very conservative amount of production in our production forecast for the Barnett Shale. That's based on -- on the infill drilling, and we deliver roughly flat year-over-year production. However, we've -- we've got -- because the horizontal outside the core area we consider exploratory, we have not put much production -- not counted on much success from that. If we have success outside the core area -- continued success, we could take production up from these levels and generate growth, both in absolute level and in year-over-year production.

Okay. Thanks very much.

Thank you, and at this time I'd like to turn the meeting back over for any final thoughts.

Thank you very much for the call. As always, we'll be available for any follow on questions that anyone has during the rest of the day. Take care.

Thank you very much for participating in today's conference call. Have a wonderful day and you may now disconnect.