馬拉松石油 (MRO) 2003 Q1 法說會逐字稿

Good day and welcome to the Marathon Oil Corporation first quarter 2003 earnings conference call. Today's call is being recorded. For opening remarks and introductions I'd like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations. Please go ahead sir.

Thank you very much, Patty. I'd like to say good afternoon to everybody and also welcome you to the first quarter 2003 earnings teleconference call for Marathon Oil Corporation. With me on the call today from Marathon Oil is Phil Behrman, Senior VP of Worldwide Exploration; Steve Hinchman, Senior VP of Production Operations; and John Mills, our Chief Financial Officer. Also with me from Marathon Ashland Petroleum are Gary Haminger, President; and Gary Peiffer, Senior Vice President of Finance and Information Technology. The format is the same as we usually use, I'll take about 25 minutes going over the high points of the quarter and then we'll open the call up for questions. About two hours after this call ends these prepared remarks will be placed on the investor relations portion of our website. It will be in a downloadable format and will remain on the site for about two weeks.

My remarks today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by the statements. In accordance with safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10K for the year ended December 31st, 2002, and its subsequent Forms 8K, cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

The first quarter of 2002 was a very good quarter for the upstream business as crude oil and natural gas prices remained above historical levels. Downstream felt the effects of rapidly changing crude oil costs, lower refinery through-puts and higher manufacturing costs due to increased maintenance work and relatively higher natural gas and other charge and blend stock costs. Unless otherwise noted, all quarterly comparisons will be the first quarter of 2003 versus the fourth quarter of 2002.

Net income for the first quarter was $307 million or 99 cents per share compared to the fourth quarter net income of $194 million or 62 cents per share. The upstream segment had first quarter operating income of $535 million or $14.37 per barrel of oil equivalent. In the fourth quarter that was $345 million or $9.01 per barrel of oil equivalent. The first quarter upstream segment included a negative $53 million of derivative activity. Most of the negative effects related to gas and occurred in March when [indiscernible] prices averaged over $9 per MCF.

The fourth quarter included a positive impact of $43 million. Domestic upstream operations had first quarter operating income of $355 million. That's $15.96 cents per barrel of oil equivalent compared to $198 million or $8.86 per barrel of oil equivalent in the fourth quarter. Our average realized liquids price excluding derivative activity was $30.28. That is up $5.90 cents from the fourth quarter. The [indiscernible] Nymex posting average was $33.80 per barrel versus $28.23 per barrel for the fourth quarter. That's an increase of $5.57 a barrel. Our performance above the Nymex change was the result of improvement in the domestic sweet/sour differentials and a spot WTI premium.

Our first quarter average gas price of $5.38 per MCF excluding derivative activity was an increase of $1.96 from the fourth quarter level of $3.42. The price realized reflects the overall Henry Hub [ph] market upswing including an increase of $2.59 over the fourth quarter bid week [ph] prices tempered by lower realizations from Alaska whose gas prices are not indexed to Henry Hub [ph] movements. On a barrel of oil equivalent basis, domestic sales revenue averaged $31.33 in the first quarter, compared with $22.40 in the fourth quarter. Derivative activity was a negative $47 million or $2.11 cents per barrel of oil equivalent. Domestic exploration expense was $38 million in the quarter or $1.70 per barrel of oil equivalent reflecting the impact of the Barracuda and Komodo [ph] wells in the gulf of Mexico. It was $45 million or $2-dollar per barrel of oil equivalent in the fourth quarter.

All other domestic costs in the first quarter totaled $11.83 cents per barrel of oil equivalent down 30 cents a barrel versus the fourth quarter. The reduction is the result of lower DD&A, primarily a result of impairments that were included in the fourth quarter offset by higher production taxes that resulted from the higher prices we realized in the quarter. Our field controllable costs was flat compared to the fourth quarter but lower than the average in 2002, reflecting our emphasis on cost control. Domestic liquids production came in flat with the fourth quarter at 118,000 barrels of liquids per day. Natural gas production of 778 million cubic feet per day was up 29 million cubic feet per day. Natural gas production was up primarily due to the first full quarter production from our Camden Hills field in the gulf of Mexico.

The two-well Campden Hills field came on-line in October of 2002 and production volumes improved as the Canyon Station facility uptime improved. The two wells are currently producing 53 million cubic feet per day net with an average uptime of 98%. This development has set a new industry benchmark for production in ultradeep water in the gulf of Mexico. A world record water depth of 7,209 feet. In the international upstream sector segment income was $180 million or $11.99 per BOE compared with $147 million or $9.20 per BOE in the fourth quarter.

Our average international liquids price at $30.63 per barrel was up $5.03 sequentially, slightly better than a change in data [indiscernible] primarily due to the timing of sales and liftings. The average international gas price of $3.45 per MCF was up 66 cents on a strengthening of seasonal European and particularly Canadian gas prices in the first quarter. On a barrel of oil equivalent basis, sales revenue averaged $25.07 versus $21.44 in the fourth quarter. Derivative activity was a negative $6 million or about 40 cents per barrel of oil equivalent.

Exploration expense of $16 million was up $7 million to $1.06 to a barrel of oil equivalent compared to $9 million or 60 cents per barrel of oil equivalent in the fourth quarter. All other international costs totaled $12.59 per barrel of oil, down $1.80 per BOE versus the fourth quarter. In February we booked an $11 million credit to foreign royalties due to a kingfisher gas royalty settlement in the United Kingdom. Operating costs per barrel of oil equivalent were also lower in the first quarter due to lower liftings at Pointhaven [ph] which is is a higher cost per barrel and due to lower workover expense in Pointhaven [ph] in the first quarter.

Production came in about as expected. International oil liftings of 73,000-barrels of liquids per day were down about 20% compared to the fourth quarter. The decrease was the result of overlift positions in Gabon and the U.K. in the fourth quarter compared to underlifted position in the first quarter. Production available for sale quarter over quarter was flat.

International gas production came in at 559 million cubic feet a day. Up 14% over the fourth quarter. We have taken an opportunity to accelerate gas sales out of the SAGE system where capacity has been available. Although our annual volume through SAGE remains fixed and we will balance volumes later in the the year, these accelerated sales allowed us to take advantage of higher winter prices. As a result of these variances, worldwide production averaged 414,000 barrels of oil equivalent in the first quarter.

Let's talk a little bit about Marathon's major upstream project. Coal bed natural gas production in the Powder River Basin averaged 87 million cubic feet a day in the first quarter. That compares to 92 million cubic feet per day in the fourth quarter. The reduction was the result of continued decline in our more mature areas that have not been offset by production inclines in new development areas due to longer than anticipated dewatering times. We expect these new areas to continue to improve in rates through 2003 and project production from the Powder River Basin to average about 100 million cubic feet a day in 2003 as previously advised.

Marathon plans to drill between 400 to 500 wells in the Powder River Basin in 2003. Receipt of the record of decision for the environmental impact assessments for federal lands in the Powder River Basin is pending and is still expected before the end of April. Our 2003 program is not contingent on issuance of the record of decision but access to the federal lands would allow us to high grade our program.

Our Equatorial Guinea expansion program is continuing on track and on budget. Phase 2A will expand our gas recycling and condensate recovery capacity. This phase is 85% complete and on budget with expected startup in the fourth quarter of 2003. Phase 2B which will expand on-shore LPG capacity sixfold is 22% complete and it's on budget as well with an expected startup in the fourth quarter of 2004. Upon completion of phases 2A and 2B our net production will increase from the current rate of about 22,000 barrels of oil equivalent per day to approximately 50,000 barrels of oil equivalent per day.

Our exploration efforts enjoyed early success in Norway and continued encouragement in deep water Angola. Marathon completed the first exploration well of its program in Norway last week. Another well was drilled into the prolific Heimdal formation located about seven and a half miles west of the Heimdal platform in 390 feet of water and was drilled to a total depth of 7,425 feet below sea level. The well encountered a 155-foot gross oil column including approximately 115 feet of net pay with high quality oil. This discovery is the first well in a three-well program designed to the evaluate the west Heimdal area this year.

The next exploration of wells to be drilled has already spud on the near Boa prospect in PL088BS which is expected to drill into the same formation. The presence of nearby infrastructure, shallow water depth, shallow drill depth, along with overall hydrocarbon potential in west Heimdal should allow Marathon to rapidly grow production in Norway to 40,000 barrels of oil equivalent per day in 2006. Marathon is operative in the west Heimdal area with a 65% working interest.

Turning to deep water Angola. Marathon participated in the Gindungo prospect on Block 32. This well has been tested and is now suspended awaiting the necessary approvals to announce results. Current plans call for one additional exploration well in Block 32 in 2003 and Marathon has a 30% working interest. In Block 31, Marathon is currently participating a well in the [indiscernible] prospect which is adjacent to the Plutao discovery which was tested at a maximum flow rate of 5,357 barrels of oil per day. We have reached total depth on [indiscernible] and are ready to begin testing the well. One additional well is planned for Block 31 during the third quarter of 2003 and Marathon has a 10% interest in Block 31. We continue to be encouraged by the drilling results in deep water Angola and see the opportunity to substantially grow our resource base in 2003.

In Equatorial Guinea a three-well exploration program in the vicinity of our world class Alba field should commence in the third quarter. In deep water Nova Scotia, Marathon is about to begin a proprietary 3D seismic survey over the Portland and Empire blocks. This data will help form the basis for our 2004/2005 drilling plans. Lastly, Marathon participated in two dry holes in the gulf of Mexico in the first quarter, Barracuda and Komodo [ph]. Due to the continued international exploration success we plan to lessen our exploration emphasis in the gulf of Mexico. For the remainder of 2003, Marathon plans to participate in the Neptune number five appraisal well which will spud at the end of the second quarter.

Turning to downstream results reportable arm and teeth [ph] segment income in the first quarter was $67 million compared with the fourth quarter level of $88 million and last year's first quarter loss of $51 million.The MAP portion for each quarter was $82 million in the current courter, $94 million in the fourth of 2002, and a loss of $43 million in the first quarter of 2002. Other downstream costs in the first quarter of 2003 of $15 million were higher than the $6 million in the prior quarter and $8 million in the year ago a quarter, primarily as a result of one-time environmental accruals reported in the first quarter of 2003.

Before we go into the details I want to point out that we have expanded the reporting of operational data for MAP in our investor packet and earnings release to include refined product yield by product group and other charge and blend stocks on a quarterly basis.This is information we used to provide only on an annual basis.

The first quarter of 2003 was a challenging time for the world economy and the oil industry. Crude started the year at about $31.20 a barrel, peaked out at about $39.99 on February 27 and ended the quarter at about $31 a barrel. Crack spreads were equally volatile because of the uncertainty in the Middle East and the political turmoil in Venezuela. Chicago crack spread hit a low of 83 cents a barrel on January 17th, peaked at $11.15 a barrel on February 7th and ended the quarter at about $7 a barrel. Of equal significance, the U.S. gulf coast cracks were actually peaked higher than the Chicago crack spread at $11.25 a barrel on February 27th. Due to the uncertainty of supply out of Venezuela and a significant amount of refinery industry turnarounds during this period on the gulf coast.

In addition to facing the challenges in the market place in the first quarter of 2003, MAP undertook major plan turnarounds at our Garyville and Texas City refineries. These planned turnarounds were done to allow us to have our refineries ready for the summer driving season and also to allow us to expand our fluid catalytic cracking units at each of these facilities in total by about 15,000 barrels per day.

Crack spreads and sweet/sour differentials improved significantly compared to the first quarter 2002. However, offsetting some of this improvement in these market indicated profitability metrics were the following factors: due to the significant amount of planned and -- planned maintenance activity we undertook at our Garyville and Texas City refineries as well as some unplanned maintenance at other refineries, our total refinery inputs were about a hundred thousand barrels a day or about 10% less in the current quarter than in the first quarter of 2002. The reduction in charge and blend stocks was primarily due to the fact that both Garyville and Texas City have excess capacity in their secondary processing units which, when operational, allows us to buy other feedstocks for further processing or blending in these facilities.

The reduction in through-puts this quarter resulted in a significant reduction in the amount of manufactured refined products we had available to sell this quarter versus the same quarter last year. Manufacturing costs were up significantly this quarter compared to the first quarter of 2002. This was due to the steep runup in natural gas prices which increased our purchased energy costs about $40 million compared to the first quarter last year. MAP purchased about 40 billion cubic feet of natural gas on an annual basis. In addition we incurred higher manufacturing costs due to maintenance activities that were previously mentioned. While the sweet/sour differential widened this quarter compared to last year, the improvement was largely offset by the steep backwardation [ph] in the crude oil markets in the current quarter versus first quarter of 2002.

It has always been MAP's crude oil acquisition strategy to attempt to establish the price of its domestic crude oil purchases as close as possible to the time the crude oil is refined to minimize price drifts. To do this MAP's crude oil acquisition price is affected by the future price of crude oil in the futures market. For example, in the first quarter of 2002 the futures market was in Contango [ph] an average above 35 cents -- on average about 35 cents per barrel. In contrast to this, in the first quarter of 2003, the futures market was backward dated about 90 cents per barrel. This $1.25 per barrel change in futures prices between the two quarters resulted in MAP's crude oil acquisition cost being relatively higher than the change in the WCI price would indicate by about 55 cents per barrel.

We ran significantly less charge and blend stocks in the current quarter compared to the first quarter 2002. But because of the strike in Venezuela and the surge in natural gas prices, the price of charge and blend stocks increased more than the change of price of WPI and also negatively impacted this quarter's relative results.

The first quarter 2003 in trans [ph] crude impact at MAP was a $15 million positive versus a negative $17 million in the fourth quarter and $20 million negative in the first quarter of 2002. Despite our produced production this quarter we did increase our total refined product sales from about 4.4 billion gallons in the first quarter of 2002 to 4.5 billion gallons this quarter, requiring us to buy a significant amount of refined product for resale to maintain supplies to our customers.

Regarding SSA, our per unit average volumes increased even though sales decreased from 852 million gallons in first quarter of 2002 to 829 million gallons in the current quarter. This was the result of having about 90 fewer units this quarter. Same store gasoline sales at SSA were up about one half per cent quarter over quarter. In addition, SSA's merchandise sales on a same store basis increased about ten per cent quarter to quarter. Refining and wholesale marketing margins increased from 1.6 cents per gallon in the first quarter of 2002 to 4.1 cents per gallon in the current quarter. As stated earlier this improvement was primarily caused by the stronger crack spreads and improved sweet/sour differentials.

In spite of the increasing prices of crude oil and refined products for most of the first quarter of 2003 and the relatively soft demand for gasoline, SSA's margin increased from 8.3 cents per gallon in the first quarter of 2002 to 11.7 cents per gallon in the current quarter. We continue to improve the SSA convenience store side of the business where merchandise gross margin increased from $130 million in the first quarter of 2002 to $133 million in the first quarter of 2003 in spite of the fewer number of units that were in operation.

I'd like to mention a few operating highlights from the first quarter in addition to the cat cracker expansions we successfully completed in Garyville and Texas City. During the first quarter we increased our ownership in Centennial pipeline from 33% to 50%. We believe in the long term viability of this strategic defined products pipeline to meet the growing shortfall of motor fuel requirements in the Midwest. The Cardinal pipeline project which will connect our catalyst [indiscernible] refinery in Ohio was under construction. 449 miles, 14-inch pipeline should be operational around mid- year 2003.

And on February 27th of 2003 Pilot Travel Centers closed the acquisition of the 60 Williams Travel Centers which were announced in the fourth quarter of last year. These 60 travel centers will be integrated [indiscernible] with the existing travel center network which will result in the sale of approximately 30 PTC and Williams locations by the end of this year. We expect to have almost all of the former Williams locations rebranded and remerchandised with the PCT style by Memorial Day of this year.

In the other energy related business segment, operating income was $11 million in the first quarter versus $15 million in the fourth quarter. Natural gas marketing results were adversely impacted by $18 million of derivative losses including an $11 million mark-to-market losses that will be offset in future periods as part of our purchase for resale activity. This was offset by a very strong quarter from our 45% equity interest in the methanol plant in Eugene.

First quarter net equity earnings from Amco [ph] were $13 million. The methanol market remains very strong on the back of high natural gas prices and higher than forecasted demand, mainly from MTBE sector.

Plant closures and reduced operating rates in Venezuela and New Zealand have also impacted supply balances. Realized methanol prices for the first quarter averaged $212 a ton versus $99 a ton for the first quarter of last year and $196 per ton in the fourth quarter. Our EG plant which is the newest methanol plant in the world has operated with great reliability since the reform or repairs reported in the second quarter of 2002. The first quarter on stream factor exceeded 95% with production rates above 100% of nameplate capacity.

Early last year we announced our integrated gas strategy which was designed to add value to the development of opportunities we saw created by growing appetite in North America for natural gas. While on the supply side there was an increasingly constrained North American gas supply profile. Based on our belief in that strategy we acquired our significant gas resource in Equatorial Guinea. We were also well along with our plans for the Tijuana regional energy center in the Mexican state of Baja, California. Our view continues to be that the Atlantic Basin will be L&G constrained while the Pacific Basin will be long L&G but short on North American access. This view had been developed through over a year of analysis and review. Since laying out our strategy almost 14 months ago, we've seen record low gas storage numbers and sustained historically high natural gas prices.

Many companies and analysts have jumped on the looming North American gas shortage train with the view that L&G is the only economic short term solution. A conclusion we made nearly two years ago. Since the time of our strategy rollout last February we have worked to acquire market access with the Elba Island offtake agreement. Awarded front end engineering and design contracts for both a EG Phase III L&G facility, and a Tijuana regional energy center, and continued our development of the energy resource base through design and construction of phases 2A and 2B.

We have been in discussions with Pacific Rim L&G producers and are working hard to acquire additional North American re-gas capacity. While we still have a way to go, our goal of becoming an integrated gas player is not far away and over the next several months we plan to make it and its value clear to all of you.

Moving back to financial results, total segment income in the first quarter of 2003 was $613 million, up 37% from the $48 million in the fourth quarter. Upstream was up 55% while the downstream was down 24%. In the "unallocated" category administrative expense was $44 million in the second quarter compared with a fourth quarter total of $69 million. The decrease in the first quarter is the result of a state franchise tax increase and a number of year-end employee and benefit related accruals, none exceeding $6 million that were reflected in the fourth quarter numbers.

Net interest and other financial costs were $65 million in the first quarter compared to $53 million in the fourth quarter. The difference is the result of foreign currency losses of $2 million in the current quarter compared to gains of $14 million in the fourth quarter. If you adjust for that, actual net interest expense in the current quarter it was $4 million less than the fourth quarter. Cash adjusted debt went down by $198 million during the first quarter to $3.885 billion. The preliminary cash adjusted debt to capital ratio at March 31, 2003 is just over 42%, down from 44.5 percent at December 31. Please note that these ratios and total debt include approximately $547 million of debt that is serviced by U.S. Steele.

As part of our commitment to maintain discipline and high grade asset -- our asset portfolio, we announced an asset rationalization program in February to divest of certain upstream and downstream assets determined to be noncore to Marathon's strategy. Two actions were announced during the first quarter as part of this program. The first is an agreement to sell 193 SSA retail outlets in the southeastern United States to Conoco [ph] for $143 million plus store inventory. The sale has received F TC clearance and is expected to close during the second quarter of 2003. This is a continuation of MAP strategy to focus its company operated business in the Midwest where the company can leverage its critical mass of locations and capitalize on its pipeline and distribution networks.

The second is Marathon's announcement to solicit offers for the company's interest in western Canada. Previously, we advised our asset sales in 2003 were likely to exceed $400 million. Marathon now estimates the sale of these and other upstream and downstream assets are likely to exceed $700 million. Proceeds will be used to strengthen our balance sheet and to invest in select business opportunities like KMOC consistent with Marathon's strategy to create superior long term value growth.

Marathon's pretax income for the quarter reflecting just Marathon's share of downstream income was $478 million. The tax provision was $175 million. That is a tax rate of 36.6%. And for 2003 we now project an effective tax rate of approximately 37% for the year. First quarter preliminary cash flow from operations excluding working capital changes was $677 million versus $590 million in the fourth quarter. Capital spending was $374 million in the first quarter.

Finally, I want to make a few observations about the second quarter and the full year 2003. For 2003 we have hedged a significant portion of our anticipated oil and gas production utilizing zero cost collars. We have also sold forward a part of our anticipated oil production for 2003 and part of our anticipated gas production for 2004. Natural gas hedges cover approximately 265 million cubic feet per day for the remainder of 2003 or about 21% of anticipated production and 50 million cubic feet per day for 2004 or about 4% of anticipated production. Oil hedges for the remainder of 2003 averaged approximately 52,000 barrels per day or approximately 28% of our anticipated 2003 production. The detailed volumes and prices related to these hedges have been disclosed in previous calls and are also included in our 10-K so I will not repeat them on this call.

On the domestic upstream side we expect second quarter liquids production to be about 110,000 barrels of liquids per day. Gas production should decline for seasonal reasons, coming in at about 725 million cubic feet per day and domestic exploration expense is anticipated to be approximately 10 to $25 million. On the international upstream side, liquids production in the second quarter should be up slightly to about 75,000 barrels of liquids per day, primarily due to balancing of liftings in Gabon and the UK and Equatorial Guinea. We expect gas production to be about 445 million cubic feet per day. Down due to volume balancing on the SAGE system in the U.K. International exploration expenses anticipated to be approximately 10 to $25 million. On a barrel of oil equivalent basis we expect second quarter worldwide production therefore to be down sequentially to about 380,000 barrels of oil equivalent per day. For all of 2003 we continue to expect production to average 390 to 395,000 barrels of oil equivalent per day excluding acquisitions and dispositions.

Downstream, while we have just come through a very volatile first quarter, we believe there will be moderate growth in light product sales in both the U.S. as well as in our major market pad too. [ph] As you know, total light product inventories have fallen below the five year averages mainly because of the significant draw of distillate stocks to about the same level as in late March of 2001. Therefore, we are optimistic we will have a relatively good motor fuel market this coming summer and MAP is well positioned to serve those markets. As far as the other energy income line, we expect income to be 15 to $20 million. Administrative costs should total about $45 million in the second quarter. Net interest and other financial costs are expected to be approximately $57 million for the quarter and for all of 2003 we project net interest and other financial costs of about $225 million.

One final comment before I open the call to questions. On Tuesday of this week we announced that we have entered into a definitive merger agreement under which Marathon will acquire Khanty Mansiysk Oil Corporation. I'll call it KMOC from here on out. A Delaware company with several production licenses in Russia, in a cash merger transaction. The aggregate purchase price for the transaction is approximately $275 million including our assumption of all of KMOC's outstanding debt obligations redemption of KMOC's outstanding preferred stock and cancelation of KMOC's outstanding derivative securities. The transaction is subject to the approval of KMOC's stockholders, Enterprise Oil Overseas Holding Limited, and Enterprise Oil Exploration Limited, both members of the Royal Dutch Shell group of companies own between them approximately 45% of the outstanding KMOC common stock, and under a stockholder agreement with KMOC have until May 6th 2003 to either make a matching offer for the common stock they do not own or approve the transaction. Currently a majority of non enterprise stock holders have committed to approve the transaction. Subject to the satisfaction of these and other closing conditions, the transaction is expected to close promptly but in any event not later than May 13th and a termination fee is part of the merger agreement.

This is an exciting opportunity for us to expand our international asset base and create a new core area in one of the world's most promising resource basins. Doing business in Russia is not new to Marathon. During the 1990s we led [indiscernible] Energy's successful first oil development under a production sharing agreement in Russia. While we traded out of those assets in a strategic deal with Shell, Russia has long been on our radar screen and we have maintained good relationships with the Russian government and the major oil producers in the country. Because this transaction is still subject to several contingencies, we are not able to talk about details at the present time. When the transaction closes we plan a conference call webcast to bring all of you up to date. While we are excited about this opportunity and wish we could tell you more, we are not able to provide any additional details today.

I will now open the call to questions. I ask that you please identify yourself and your firm affiliation for the benefit of those listening in. Thank you.

The question and answer session will be conducted electronically. If you would like to ask a question, please press the star key followed by the digit one on your touchtone telephone. If you are on a speaker phone please be sure your mute function is turned off to allow your signal to reach our equipment. We'll take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question.

We'll go first to Tyler Dan from Banc of America. Please go ahead.

Good afternoon, gentlemen.

Good afternoon.

Could you talk a little about your international upstream controllable costs. They seem to be low and I'm trying to figure out if it has to do the gas-ier mix or some -- per the lower liftings at Pointhoven [ph]. Could you go into some more on that, please.

Do you want to handle that?

I would be happy to, Ken. Our international is dominated primarily due to relatively lower lifting volumes from Pointhaven [ph] from the fourth quarter to the first quarter and as you know Pointhaven [ph] is a bit of a higher lifting cost because it has a leased FPSO operation and also lower from fourth quarter to first quarter because we had done workover on W14 well in Pointhaven[ph] in the fourth quarter and we've had no workover activity in the first quarter. And that's really the principal reason for the reduction on fourth quarter on field level controllable costs.

Okay.So to what extent then I guess on a go-forward basis then one might expect that to readjust a bit upwards?

Maybe upwards. Our forward forecast has at least worldwide to be around $2.90 a barrel going forward, average for the year. So there would be a bit of an adjustment up on international but again on an average for worldwide around $2.90 a barrel.

Okay.

Tyler. If you remember, maybe you didn't hear, the royalty adjustment that we had in the U.K. was equivalent to about 73 cents a barrel equivalent in the first quarter as well.

Okay.Thank you.

Our next question is from Arjun Murti from Goldman Sachs.

Thank you. My question relates to your gulf of Mexico business. You noted that you're probably going to be scaling back some of your deep water exploration activity . Is this a temporary pause until you get a new group of prospects and do some more work, or is this a more permanent pause and, if so, you also had a strategy of scaling out of noncore areas. Might you deem the gulf of Mexico or gulf cost to be noncore and consider putting that up for sale?

Phil, do you want to handle the exploration and Steve, you might want to talk about the gulf of Mexico production side of the business.

Sure, Arjun. It's really a hiatus at this point in time. We are going to do a technical assessment of what went well and what didn't go well. Learn from that effort. We see a lot of opportunities in the gulf and once we finish our technical assessment and our business assessment we'll slowly begin to evaluate ramping the program up again.

This is Steve Hinchman. From an operating side we continue to have high interest in the gulf of Mexico. As we look at our operations and benchmark against other operators that are in the gulf, we tend to be in the first quartile and have a very competitive operating performance so we're always rooting for exploration to continue or to have and continue to have success in the gulf of Mexico. There is in the future always the potential of additional access, especially if you move into the eastern gulf so at this point in time we have no -- no plans to put our gulf of Mexico assets in the market.

That's great.Thank you very much.

Our next question is from David Wheeler from JP Morgan.

Hi gentlemen. On the increased plans for asset sales, is that because of better prices or are you selling more assets?

John. Do you want to handle that?

Dave, I'd say it's a combination of the two. As you're aware, we have announced we're soliciting bids on our western Canadian operation. Prices have been as we have looked at comparable transactions up there, prices have been very firm so we do expect, I think, reasonably expect to realize somewhat better prices than what we thought we might achieve when we talked about asset dispositions earlier in the year.

Very good. And going back to Arjun's question on the gulf of Mexico, more specifically, in the Atwater full belt trend where you were identifying some 600 million-barrels of potential, do you do anything there left with Neptune; and secondly are you going to develop the Ozona [ph] discovery or is that on hold as well.

David, this is Phil Behrman. Our plans are to drill the Neptune 5. We continue to see an opportunity there that has potential to be commercial but we have to continue to appraise that area. But overall if you look at all of the opportunity that we presented early on was based on a number of prospects to be tested. Kansas and Komodo are both dry, and therefore we see a much smaller potential area but one that still can be commercial . We're looking at the Appraisal [ph] well in the middle of the year. We're also looking at commercializing Ozona [ph] at the same time as we do the technical assessment of the whole area.

Very good. And one last question for you guys. In ET, you were originally hoping to get an L&G sales contract in the first quarter. Where are we at on that process and when might we expect to land that?

David, this is, you know, we're still working very very diligently on that. I think the first quarter maybe we were a little bit aggressive, if you ever heard us when you heard us say first quarter, it is really looking like something that's going to stretch out throughout the year and hopefully as we get toward the end of the year, we'll be able to really have something firmed up there. I wouldn't be surprised if we have some interim events before the end of the year that will help indicate that project moving along further that we'll be able to talk about before we actually have a firm sales contracts lined up.

Thank you.

Our next question is from Matthew Warburton from UBS Warburg.

I wonder if I could ask two questions, unrelated. Firstly, I understand you can't give any details about the KMOC transaction, would it though have any bearing on your joint venture with Rossnet [ph]? Obviously that was your first [indiscernible] into Russia in terms of trying to expand your business there.

I guess I would say whether this is a successful transaction or unsuccessful, it would have no impact on that. If its successful it certainly can have some opportunities there.

Right. And just following on from David's question on the disposals, it looks to me that the bids on the Netherlands assets would have closed by now. I just wondered if you could maybe update us on that. And previously there was some talk of you selling your interest in Coreb [ph]. I wonder if you could make any comments on those.

I think due to the state of the net owners' assets its probably inappropriate to talk about the status of that right now.

And on Coreb [ph]?

Let me just add both Clam and Coreb [ph] are under active negotiations as we speak so it would just be inappropriate for us to signal in anyway how those negotiations are going but they are progressing.

And as you know, just from all the public sources, there certainly are two assets that have been up for sale.

So you would expect them though to close hopefully in the second quarter?

Can't say.

Okay. Fair enough. Thanks very much.

We'll go next to Al Anton from Carl H. Forsheimer. Please go ahead.

You got that right. Nothing was mentioned about the Symphony pipeline system which seems to be on the backburner because of reluctance of the people with the gas to use your system versus alternatives, and I wonder, given the brave [ph] processing facilities and the existing pipeline what is the economic viability of that whole system absent a Norwegian to southern England transport deal. And do you feel that as time passes by the volume of gas coming down will be so great that you're bound to be involved in it?

Al, I guess I would have to say, probably fair to say that Symphony, as we originally proposed it, is not likely to happen based on what we see at this point in time. When you look at total gas outlook in the UK going forward and kind of strategic positioning of all the Brae assets we have there, there is certainly still a lot of other -- there's still other opportunities we're looking at and we certainly would not say we even come close to giving up at this time including Brae infrastructure in part of the gas supply solution in the UK. Steve?

This is Steve Hinchman I believe there is a high likelihood as this begins to be better understood that potentially both the Heimdal and the Brae infrastructure in some way or another could play a role or be connected to that. So we still believe that the benefits in our existing infrastructure over there as a result of moving gas from Norway into the UK can still be realized although perhaps not realized in the way that we had originally thought.

Thank you very much.

Our next question is from Mark Gilman from First Albany.

Hi, I had a couple of things. So, I wonder, can you talk at all about the size of Neller [ph]. Give us a range or something to work with.

Mark, this is Phil. We haven't done that yet to date. We have given a scale of the overall potential in the Heimdal area and at one point in time I think Clarence has met at numerous presentations where he said, in general it looks like a gross 200 million barrel target. Number of prospects. The first phase of the program was a four well program targeting three of the prospects in the west Heimdal era. Neller [ph] was very successful and we have finished the second two of the prospects and I think we will be able to redress scale and size of specifically that west Heimdal area.

I think it would be safe to say that from what you've seen of the Neller [ph] well, it certainly wouldn't make you want to make you think any less of the area.

That's right.

Can you clarify Ken the listing position internationally at end of the quarter. Are you in balance, overlifted, underlifted, at March 31.

There is a mixture there, I am going to let Steve handle that he has that information.

Mark, overall internationally at the end of March we had a net underlift position of around 419,000-barrels

And Steve, the first quart overall was an underlifted quarter. Can you quantify that?

Overall the first quarter was 851,000 underlifted but we carried into the year around a 432,000-barrel overlift at the end of 2002. So that results in a net underlift position at the end of this first quarter of 419,000-barrels.

Okay. And just one or two more if I could. Can John or Ken talk about what the impact of FAS143 might have been in terms of the DD&A items on a current and or restated basis? I'm not talking about the accumulative one time piece but rather the going forward piece.

Yeah. You've seen the cumulative number, Mark. And it is very small and on a going forward basis it is -- the various pieces of the 143 amortization are virtually identical to the -- the abandonment accrual that we would have had on the upstream side for under the prior accounting rules, so for us it is just virtually a push.

Okay. So no change to speak of of any significance?

No significant change.

You would be talking pennies a barrel is what you would be talking about going forward.

Just one more. Any plans to utilize Alba Island and the processing rights that you have. Anything firm you can talk about there?

There is really nothing firm we can talk about at this time. We're certainly actively trying to utilize that facility.

Okay. Guys, thank you.

Our next question is from Paul Cheng from Lehman Brothers. Please go ahead.

Hi, guys. I have a quick question. Ken, how much is the oil and gas that you guys consumed internally for both your U.S. and downstream operation. Downstream I think you said is 40 BCF per year. Do you have a number for the U.S. upstream and international upstream.

It's fairly minimal in terms of our consumption on gas compared to our production volume so I don't have a number off the top of my head but it is fairly minimal.

So that it pretty small?

Yeah.

How much oil do you burn internally?

Virtually none.

Virtually no oil.

We would consume some gas in our plant operations, Paul, but most of that is not going to be measured until it comes off the lease so you know the volumes are relatively small and we don't have -- around this table we don't have an accurate estimate what they may be.

I see.

But they're. So --

So, John, essentially that means that you guys are not really energy intensive in your U.S. and international upstream operation?

Correct. We don't have any big stream flood projects or other things that some producers have, Paul, that do consume a lot of either crude oil or natural gas.

Most of our energy use is used in terms of running compressors. Most of our electricity used we actually buy electricity as opposed to self-generated.

Okay. Very good. On the Powder River Basin, I think, Ken, you had give a number there, 100,000,000 cubic feet per day average or '03. Any number for '04.

For Powder River Basin?

Yes.

We're projecting nominally around a 25% growth. It depends on our level of activities. So in previous discussions that we have had, you know, we have said around 100 million in 2003 and then up to around 120 or 125 million or so in 2004.

I see. And Ken I think earlier you said that -- how much is your underlift in the first quarter. I'm sorry I missed that.

The underlift if the first quarter if you look at what we produced that was available for sale compared to what we actually sold only in the fourth quarter, we underlifted 851,000-barrels.

Okay.

And that was fourth quarter, Paul, was your question?

No, the first quarter. Your underlift in the first quarter -- your overlift in the fourth quarter, and your underlift in the first quarter, right.

Yeah. We ended 2002 in an overlift position.

Right.

Of 432,000. We underlifted in the first quarter 851,000 so ended the first quarter at a net underlift position on a cumulative basis of 413,000 barrels.

Do you have a quantified number that how much you may have reduced your earnings by?

I don't have one handy.John.

We --

We only measure on our sales volumes.

Okay. That's fine. If I could, just last question. Other than Russia which you're trying to regain a position for acquisition, is there any other country or region that you think you may want to either reenter or that to establish a new position?

We continue to look around some of our core areas like in west Africa and EG, both looking for growth through the drill bit and drill exploration program and also looking for other stranded gas opportunities that could potentially fit in to our vision of a gas processing hub on the Oka [ph] island in EG. We also are interested in looking around Norway for other sort of satellite development opportunities not too dissimilar of what we're executing on west of Heimdal today.

Very good. Thank you.

Just a reminder it is star one. If you wish to ask a question today. We'll go next to Jack Aydin from McDonald Investments.

Hi, Ken. Two questions. One on the down stream, could you quantify for us what is the downtime and also lost opportunity cost you in the first quarter in terms of refining -- what downtime in terms of refining and maintenance.

Gary do you want to handle that?

Well, we have -- just a second, let me turn to the right page here. In total, our -- from a crude standpoint, Jack, we were down first quarter '02 versus first quarter '03, we ran 891,000 barrels a day in the first quarter of '02 and 853,000 barrels a day first quarter of '03. But another very important number is that in the first quarter of '02 we ran 160,000 barrels per day of refinery charge and blend stocks and only 96,000 barrels a day in the first quarter of '03. Again, because of our two big turnarounds that we had and that we have secondary processing units that can handle more through-put than just what comes out of the crude units so both of those were negative because of the big turnarounds that we had. And Gary Peiffer you might have some --

I guess if you were to assume that everything did not change in the market place by our downtimes and our lack of production and you multiply that hundred thousand barrels a day times the crack spreads in effect, at that time you're talking about $70 million.

Okay.

But that is making a lot of assumptions that things wouldn't change with the amount of product that was not on the market.

Okay. Fair enough. Second question on KMOC -- for the money you paid $275 million what kind of reserve you might get? Can you talk about it or?

Jack, like we said both in the release and today. We did say in the release that our estimates are reserves production et cetera will be different than those that are available publicly but since we don't own it it's really inappropriate for us to make that -- even try to give you that information Jack. We can't do it right now.

How about what is the estimates what is out there? Not yours?

Jack. Like I said we really can't talk about that.

Okay. I appreciate it. Thanks.

Okay.

We will go next to Michael Mayer from Prudential.

I want to follow up on Jack's Aydin's excellent question. How much more would you expect to earn with comparable margins in the second quarter given that you've expanded your refinery capacity by 15,000-barrels a day with the new fluid catalytic cracking cracking unit at Garyville?

Michael, we cannot talk about forecasting the numbers. What I can say -- or forecasting profits. But what I can say is in the second quarter we expect that all of our plants should be running pretty much full out. We have those two big turnarounds behind us from the first quarter so depending on whatever the forward crack spreads and what actually happens in the market place, our plans are to run all the plants full out.

Maybe in the alternative you could refresh my memory on what was the expected return on investment of that new unit?

On the two different expected crack improvements?

Yes.

On the cat cracker improvements and here we do not -- we do not divulge on those types of small projects what the rates of return are.

Can you tell us what the cost was?

Total between the two about $100 million.

Okay. Great. Thank you.

And we have a followup question from David Wheeler from JP Morgan.

Well, perhaps one way Gary -- another shot at this perhaps one way of getting to what you guys had set a target of enhancing profitability through pipeline and refinery upgrade projects of about $100 million. How far along that timeline or along that profit line are you, or were now you in the first quarter?

Sure, David. And of course the biggest project when we stated that was the Garyville coker and it has been performing very, very well from a both from a through-put and an economic stand point. The balance was Pilot travel centers and we are very pleased with the performance of Pilot. And then Centennial pipeline was a piece and Centennial has through-puts are continuing to improve slightly but Centennial was a very small piece of that hundred million dollars. And the last piece was Cardinal pipeline which should be complete late second quarter and when we stated that hundred million we had thought that we would have had Cardinal built or early startup this year. We have just been delayed because of severe winter and very, very wet spring but again that -- the amount of money there isn't material to a hundred million. The majority of it was in the coker which is performing on target and Pilot travel centers has had a very strong first quarter.

And both of those operations were in effect all last year so year-on-year they're all in the numbers for this year too. So there is no variance year on year.

So there is no additional upgrade to profitability '03 over '02?

Correct.

Not in the first quarter. We should start seeing here in the second quarter, the effect of the Williams Travel Centers we picked.

A second question for you .It looks like you sold your Canadian natural gas for a higher price than you sold your U.S. natural gas. How did you do that trick?

David, what you're looking at on the average realization here, you have to remember our U.S. average realizations include all of your Alaskan volumes which bring that average down so that would -- you certainly don't have that influence in Canada. Canadian gas prices in the first quarter where there is always a differential for Henry Hub [ph] they track very well with Henry Hub being up and that is the whole reason in Canada.

Okay.

Thanks Ken.

Uh-huh.

We'll go next to Jay Saunders of Georgia Bank. Please go ahead.

A couple questions on Alba and then one on the downstream. There seems to be a little bit of volume creep after 2B you guys are saying now 50,000 barrels a day, and I think you said 47 earlier. I wonder what is behind that and if there's scope for more. The second question is on the timing for 2A. Is it still October, can you be more specific than the fourth quarter. And finally on the downstream what percentage of the slate for MAP is domestically sourced, that is the crude slate. Thanks.

Steve do you want to take those first?

I would be happy to. Jay, the slight increase that we have is really the result of a little additional offstake off shore. As we have been working the project and are now in the execution we have been able to increase our capacity of producing a gas offshore to about 825 million and then we have seen better run time also overall in the operation. So really those things combined are the primary result for increased production in what we have shown before.

The project is going extremely well. We're around 85% complete. We have -- we're very comfortable with the pace that we're setting and you know our estimate is for October for a rampup. Probably the biggest thing that could potentially get in the way of that is just having significant weather problems over there especially with our onshore construction. If we just have too much rain it doesn't allow us to get in and finish some of the onshore construction work. But right now the team is doing it very well, on time, on budget and we do expect around October that we would be ramping up production.

Okay. Thanks and by the way where are the three wells in the third quarter that are going to be drilled?

This is Phil Behrman. The three wells sit in between Block B and Block D that surround the Alba field.

And Jay, I thought you had a downstream question.

Yeah. Just the crude slate. What portion of that is domestically sourced for the whole network.

Right. Jay, in the first quarter, we're right around 45%. We generally float kind of mid 40% range. It will be a little different probably as we go forward depending on foreign source barrels and how the Iraqi crew comes back on stream. But it will float kind of in the low 40s to mid 40% range.

That I assume changed when you got the coker off at Garyville?

Somewhat, but it is all based on the pricing. What's the most attractively priced crude for the system.

Okay. Thanks.

That does conclude our question and answer session. I would like to turn the call back over to Ken Matheny for closing remarks.

I thank you all very much for participating. We look forward to being able to tell you the story on KMOC and other things that may come up in the future. And, if not, we'll talk to you again next quarter. Thank you very much.

That does conclude the conference call. Thank you for your participation. You may disconnect