馬拉松石油 (MRO) 2002 Q1 法說會逐字稿

Thank you for holding ladies and gentlemen and welcome to the Marathon Q1 conference call. At this time, all lines are in a listen-only mode. There will be an opportunity to ask questions at the end of today's conference. Instructions for asking questions will be given at that time. I thank you for your attention and I will turn the conference to over to our host Mr. Kenneth L. Matheny Vice President of Investor Relations.

Good morning. I would like to welcome everybody as well to the first quarter 2002 earnings reviewed teleconference and webcast for Marathon Oil corporation, available with me on this call today for Marathon Oil [Phil Berman] Senior Vice President of Worldwide exploration, [Steve Hinsham], Senior Vice President Production Operations, and [John Mill] Chief Financial Officer. Also with me from Marathon Ashland petroleum, our [Gary Hamigler] President and [Gary Piper] Senior Vice President of Financial Informational Technology. I will cover the height points of Marathon's first quarter and then we will open the call up for questions. Before I start, I want to make you aware of a few things that we are doing differently. When you go to our website to access our Invest Relations packet, you will see there, we've reformatted it slightly and provided additional data that we think will be helpful to all of you. We should also note that our earning release contains more information on realized prices. Another change, shortly after this call ends, we will place these prepared remarks on the Investor Relations portion of our website. It will be in a downloadable format and remain on the site for two weeks. It is just another effort toward being more user-friendly to [you] customers. My remarks today will contain certain forward-looking statements that are subject risks and uncertainties that could cause actual results could differ materially from those expressed in Form-5 by such statements. And in accordance with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation formally known as USX Corporation has included in its annual report on Form 10-K for the year ended December 31, 2001. And in subsequent Forms 8-K, 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 again a good operating and financial quarter for Marathon upstream business. The downstream was financially challenged, as refining in marketing margins were among the worst in recent history. Net income adjusted for special items was $27 million or $0.09 per share and that compares to adjust the net income of $98 million or $0.32 per share in the fourth quarter 2001. Special items in the first quarter totalled a positive $40 million aftertax and consisted of a $27 million [reversal] of nearly all of the inventory marked valuation reserve establish in the fourth quarter of 2002 and a $13 million aftertax impact from the cumulative effect of change in accounting principle. This change resulted from the required adoption of various FASB interpretations on the accounting for derivative instruments. The adjustment relates to two natural gas sales contracts in the U.K. that extends through 2009 included within these physical contracts is a very typical pricing [process]. It is based on the basket of U.K. government industries, which represent a producer price index that is adjusted annually. As the natural gas market has become more liquid and more parties are entering international gas trades, a separate marking pricing convention has risen referred to National Balancing Point or NBP for short it's similar to [Henry Hub]. As a result, the difference between Marathon's physical contract price is compared to the NBP is recognized as a derivative in accordance with FAS-133 guidance. Looking at the upstream segment, first quarter 2002 operating income totalled $165 million or $4.32 perr barrel of oil equivalent. Fourth quarter [like] numbers were $117 million or $3 per barrel of oil equivalent. Focussing on domestic upstream operations, first quarter operating income was $82 million or 348 per BOE versus $112 million for $4.32 per BOE in the fourth quarter. Our average realized domestic liquids price was $18.12 per barrel, up 279 from the fourth quarter compared to the $1.10 per barrel increase in the prompt NYMEX posting average primarily as a result of the continued narrowing of the average heavy [power] differentials during the quarter. I might add that all of the pricing information I put on this call will not include will be exclusive of hedging activities. Our first quarter average domestic gas price was $2.35 per million cubit feet increased $0.03 from the fourth quarter compared to the $0.20 decline in the NYMEX [Henry Hub] average. This better performance is primarily resolved a bid weak pricing which does not always reflect as [Henry Hub] average for the quarter. On a barrel of oil equivalent basis, domestic revenue on an average price times volume basis averaged $16.11 in the first quarter compared with $13.40 from the fourth quarter. The derivatives related to marked-to-market impact in the first quarter was a negative $9 million or $0.38 per barrel of oil equivalent primarily reflecting the marked-to-market value change in our previously advised crude oil hedge of 25, 000 barrels per day for 2002. Domestic exploration expense was relatively flat at $49 million or $2.9 per barrel of oil equivalent. All other costs in the first quarter totalled 1017 barrel of oil equivalent that's up a $69 versus the fourth quarter and the increase is primarily result of allocated cost from commercialization and development and business developments. Domestic liquids production came in nearly spot on with a guidance that we gave in January at 131,000 barrels of liquids per day that's down 6% versus the fourth quarter. Natural gas production of 787 million cubic feet per day was down 8% due to warmer weather in the Alaska, plant downtime in East Texas, and to a lesser extent downtime in the Gulf of Mexico. On a barrel of oil equivalent basis, overall first quarter daily domestic production was down 70% compared with the fourth quarter average and down 2% compared to the first quarter of 2001. Turning to the international upstream sector, operating income was $83 million or $5.69 per barrel of oil equivalent compared with $5 million or $0.38 per barrel of oil equivalent in the fourth quarter. Our average foreign liquids price of $20.37 per barrel was up to $3.33 sequentially reflecting an improvement in the dated brand crude market, which serves as a surprising reference for much of our international production. The average gas price of 2.46 million cubic feet was down $0.24. On a BOE basis again, revenue average $17.35 versus 1646 in the fourth quarter. Exploration expense of $8 billion was down $17 million to $0.55 per barrel of oil equivalent and derivative gains were 17 million or $17 per barrel of oil equivalent. All other cost totalled $12.28 per barrel of oil equivalent that's down a $1.89 per barrel of oil equivalent versus the fourth quarter and that's primarily due to a decrease in allocated commercialization and development and business development charges along with decrease DDNA. Internation liftings for the first quarter came in about as expected at 75,000 barrels of liquids per day, 21% higher compared to the fourth quarter. Primarily reflecting EG production [acquired] January 3 of this year and increase production [_____] of 6000 barrels per day offset by an 8000 per day underlift in United Kingdom. Gas production came in at 522 million cubit feet per day, slightly above our guidance of 500 that we gave earlier and up 8% over the fourth quarter again primarily a result of the EG acquisition. Sequentially, from the fourth quarter to the first quarter, worldwide production was flat at 424,000 barrels of oil equivalent per day and our total cost on a worldwide basis were also flat with the fourth quarter on a barrel of oil equivalent basis. Looking at Marathon's domestic development projects, petroleum achieved new production rates for gas and average the net 22.2, 000 barrels of liquids per day and 24.7 million cubit feet per day in the first quarter, down 7.9% and up 15% respectively versus the fourth quarter. Looking forward, petroleum should average about 27,000 net barrel of oil equivalent per day in 2002. The first production well at Haymen Hills, now holds world's record for the deepest depth completion in more that 7200 feet of water. The second well should be completed by early July ahead of planned. Start of production would probably delayed until later in the third quarter. This is due to slow progress on laying the Canyon express pipeline system that will severe Haymen Hills and two other fields. Flat [petrol] production more than 44 million cubit feet per day [less than] Haymen hills probably won't be reach until very early next year. The production impact of the Canyon express delay should largely offset by earlier than forecast production from the [wallet] field in Norway. This one well tieback to the Haymen platform is now expected to begin producing in late May or early June about one month ahead of plan. Net production at [wallet] is expected to be somewhat greater than that of Haymen hills about 24 million cubic feet per day of gas and 5900 barrels per day of condensate are close to 60 million cubic per feet day of gas equivalent. On April 11, Marathon agreed with XTO energy to exchange certain relevant gas properties in East Texas and North Louisiana for the recently acquired CMS, coalbed methane acids in the Powder River Basin. These assets will allow Marathon to leverage its expertise in coalbed methane development in this core area. Transaction is expected to close on May 1st. In addition, XTO will purchase Marathon's production interest in the standalone base of New Mexico for $43 million and this portion of the transaction is expected to close on July 1st. As a result of the asset trade, Marathon will add over 400 billion cubic feet of Powder River Basin resource including some 110 cubic feet of proven reserves. The company will also reduce per unit operating expenses by leveraging economies of scale in this core area. The overall effect on 2002 worldwide annual production is expect to be mutual or slightly positive. Over the life of the project this trade is accretive income, cash-flow production, and reserves. Initially, the trade will add 24 million cubic feet per day net gas production to Marathon's current Powder River Basin production of 60 million cubic feet per day net. Marathon will drill between 500 and 600 net wells this year, as we had originally forecast and we will use this additional acreage position to high grade our drilling opportunities. These agreements with XTO energy a part of trade option announced late February to market-selected properties in a competitive process designed and establish a greater presence in the core areas [for/while] the company's size, infrastructure, and regional expertise will create additional value. Additional trade transactions are being pursued and should be completed by the fourth quarter. It's all part of our focus on getting bigger and better in fewer places. In exploration, we plugged and abandoned our first well at Annapolis offshore Nova Scotia before reaching TD due to a well-controlled event caused by an influx of gas on March 24. We have moved the rig and commenced drilling a new well. Well should reach TD in approximately 60 days. We also started an appraise well at our Arizona deep discovery which should reach TD in the second quarter and we will start a 1-2 additional Gulf of Mexico deepwater exploration wells later in the year. The U.K. at Atlantic margin [_____] developments continued to exceed expectations following commencement of East [_____] oil production in last September. Total [_____] field production for the first quarter 2002 was just under 32,000 net barrels of liquids per day with annual production projected to be approximately 30,200 barrels of oil equivalent per day this year. On January 3, Marathon completed the acquisition of interests in equatorial Guinea West Africa from CMS for a total cash consideration including working capital just over $1 billion. This acquisition established to profitable new core business area from Marathon and is expected to increase 2002 production by 18,000 barrels of oil equivalent per day and increased Marathon's proven reserves by 250 million barrel of oil equivalent in 2002. Furthermore, the upside potential of these assets presents an opportunity for Marathon to become a significant regional player in West Africa. We regard this acquisition as an important new step in growing our integrated gas business with the application of gas commercialization technologies and deliver value-added production for local, U.S., and European markets. The Marathon project team is began work [_____] expand the field development and has nearly completed a plan to begin work on aggressive expansion. By the third quarter of next quarter, we expect to boost gross gas production from 250 to about 800 million cubic feet per day and increase condensate an LPG exports by at least 40,000 gross barrels of liquids per day. This expansion will include reinjection facilities that will allow essentially all the gas not converted into a condensate LPG or methanol could be return to offshore for reinjection into the reservoir boosting liquid recovery from [alba] and conserving the gas for future monetization. When the last of the expansion facilities are commissioned in mid-2004, this expansion will increase Marathon's net production to an average of more than 35,000 barrels of oil equivalent per day. Design work is also began on the process for monetizing Marathon's nearly 1.4 TCF of gas from [alba] as well as other standard [inflared] gas located within 100 kilometers of the [_____] Island. On February 28, 2002, we announced proposed plans for major liquified natural gas, regasification, and power generation complex [_____] in the Mexican state of Baja, California. The proposed complex would consist of an LNG marine terminal, an offloading terminal onshore LNG regasification facilities, and pipeline infrastructure necessary to transport the natural gas. In addition of 400-megawatt natural gas fired power generation plan would be constructed on the site, the complex would supply natural gas and electricity for local use, as well as for export to Southern California. Since our initial announcement, we have entered into a cooperation agreement with [____] and respective LNG supply and associated upstream developments and have secured land access in Baja. Also on February 28, we announced plans [to lead an] and initiative for a new North Sea natural gas pipeline designed to provide additional gas for the U.K. market. The proposed 675 kilometer dry natural gas pipeline would connect the Norwegian [_____] of the North Sea to Bacton on the South East coast of the United Kingdom. The pipeline would pass through the break complex and pass adjacent to other large gas processing and transportation facilities in the U.K., North Sea, and would terminate [____] near the existing Bacton terminal. The pipeline would allow gas to be aggregated from numerous U.K. Norwegian North Sea producer for transportation Bacton where then be sold to commercial, industrial, and residential customers. The Norwegian government continues to pursue changes to gas infrastructure and associated regulations and our propose U.K. gas export project has been very well received. We will commence the open season process for gas transportation in May of this year. In the North Sea, Marathon has acquired additional interest ranging from 50-65% in several Norwegian licenses as in the [____] area. This is part of a strategy to develop new resources through our existing brand [____] infrastructure while monetizing substantial Norwegian recent tax losses incurred earlier in the [____] field projects. These portfolio additions include several undeveloped discoveries and growth prospects close to Marathon's existing infrastructure in the [_____] areas of the North Sea. Plan of development has now been received from the operator for the first two of these fields [Bigba and Sterna]. First production of these fields anticipated in early 2004 and ship provide more than 5100 barrel of oil equivalent of net production. We are also looking at the development of [_____] as a satellite to [_____]. Exploration and appraisal activities in the [_____] area is planned for 2000 and 2003 with the development work likely to begin in 2003. The [wallet] project as mentioned earlier is in the same area. Explanation of our interest in Norway is consistent with and ties nicely in the work of those to build a gas pipeline connecting our Norwegian gas to the [brace] system to Bacton and South East England. In Ireland, preparatory work for developing the core field continues and has received government approval. First production is now expected in 2004 when peak rates of 65 million cubic feet per day net anticipated. Lastly, in deep water in [Angola], we find the drill one to two additional wells on block 31 and one well on block 32 which look similar to nearby discoveries. Turning now to downstream results, the reportable refining marketing and transportation segment income in the first quarter was a loss of $51 million compared with the fourth quarter income of $221 million. This includes MAPs first quarterly loss since MAP was formed in January 1998. Marathon share was a loss of $34 million versus $137 million profit in the fourth quarter. The Chicago 321 crack spread averaged $3.70 per barrel in the first quarter versus 459 per barrel in the fourth quarter. First quarter 2002, Gulf Coast [Crack spreads] averaged 297 a barrel compared to 206 a barrel in the fourth quarter. Our refining in wholesale marketing margin in the first quarter was 1.6 cents per gallon versus the fourth quarter level of 6.4 cents. The gross product margin for our retail business [Fieldway] Super America was 8.3 cents per gallon in the first quarter, as compared to a 11.4 cents per gallon in the fourth quarter. We finally run averaged over 891,000 barrels per day in the first quarter or 95.3% of rated capacity compared with 925,000 barrels a day or 99% of rated capacity in the fourth quarter as we reduced runs and performed maintenance in the face of the worst market environment in years. And nearly $200 million and $70 million swing in MAPS income sequentially from the fourth quarter is attributable to a number of factors that are not necessarily reflected in published [crack spreads] and that were significantly more material. The compression in sweep side on the crude oil differentials we saw in the first quarter, significantly increased MAPS overall crude oil cost relatively to WTI. Refine product price increases in the quarter were primarily driven by increasing crude oil cost inspite of relatively weak demand. This cost-push severely compressed wholesale margins compared to the spot prices that are reflected in the WTI 321 [crack spread]. Our intrinsic crude impact was a negative $20 million versus a $30 million gain in the fourth quarter resulting in a $50 million change sequentially. On the plus side, to start up to the Garyville [coker] last December in our pilot joint venture performed in line with our expectations. Total product sales averaged 1.23 million barrels a day in the first quarter down about 6.8% from the fourth quarter and down 2% from a year ago. Merchandized sales were down about 7.5% from the fourth quarter to $540 million in line with seasonal patterns, over up 11% over the first quarter of 2001. Last September MAP and Pilot commenced operation of their previously announced transaction to form pilot travel centers LOC. MAP and Pilot each have a 50% interest in this joint venture, which is the largest travel center network in the nation with about 230 locations. A new venture based in Knoxville, Tennessee has approximately 11,000 employees and MAP accounts for Pilot on an equity basis. MAP has improved its logistics network and is the operator of the Centennial pipeline owned jointly by [_____] Eastern and TE Products Pipeline Company. The new pipeline, which connects gulf coast refinery to the Midwest market, is fully operational and made its first product deliveries on April 5th. The line's initial capacity is 210,000 barrels per day. Garyville, Louisiana [corporate] reached [_____] put in December and total cost of this major improvement program was approximately $280 million. The expected corporate reduced Garyville's total crude oil feed stock cost by about $1 per barrel. We are very excited about these value-adding projects and their performance today is right on target to increase MAPs income from operations by more than $100 million in 2002, compared to 2001. MAP also has plans to build a pipeline from Conover, West Virginia to Columbus, Ohio. Pipeline will be called [Corno] Products pipeline and we will have a design capacity of 80,000 barrels per day and is expected to initially move about 50,000 barrels per day of refined petroleum in the Central Ohio. Getting back to Marathon's quarterly results, other energy related business had operating income of $25 million in the first quarter versus $22 million in the fourth quarter. The increase in 2002 was primarily the result of marked-to-market evaluation changes in derivatives used to support trading activities, increased gas marketing margins, and increased earnings from pipeline investments. Income from our 45% equity ownership in Atlantic Methanol Production Company or Amco is included in other energy related business and was essentially break even in the first quarter given that the first methanol environment during the quarter. Amco started the operations in Equatorial Guinea in May 2001 and has designed to produce the minimum of 2500 metric tonnes per day of methanol. The plans combined operating and transportation cost structure, are among the lowest in the world. On March 30th, the plant was temporarily shut down for approximately 60 days to replace certain materials used in the construction of steam reformer. Repair costs are expected to be covered by the manufacturers warranties and construction in delayed start up insurance is in place. Prior to shutdown, the plant was producing approximately 2650 metric tonnes per day. Most importantly, Amco has made arrangements to ensure that their customers will not experience any supply interruptions during this downtime. That brings total segment income in the first quarter of 2002 to $139 million down 61% from the $360 million from the fourth quarter. Upstream rose 41% while the down stream was 123% low. In the on an allocated category, administrative expense was $44 million in the first quarter. This compares with the fourth quarter-adjusted total of %50 million. Net interest expense was $64 million in the first quarter versus an adjusted 25 million in the fourth quarter reflecting out debt increases from the US Steel separation and our January 3rd Equatorial Guinea acquisitions. Cash adjusted debt rose by $1 billion during the first quarter to $4.3 billion and a cash adjusted debt to capital ratio on March 31st is 47%. Marathon's tax provision of $39 million for the first quarter includes non-recurring adjustments of approximately $4 million. Without these adjustments, the first quarter affected tax rate was approximately 38%. The United Kingdom recently announced proposed supplementary 10% tax on profits from UK Oil &Gas production. Our preliminary assessment is this tax increase, if an act is proposed, could add approximately 2% to Marathon's effective tax rate excluding a onetime non-cash deferred tax catchup adjustment. Given the UK tax proposal, we project an effective income tax rate of approximately 40% going forward. First quarter, preliminary cash flow from operations excluding working capital changes was $261 million or $0.84 per share. Capital spending was $292 million in the first quarter, while the 2002 excluding acquisitions our capital and exploration spending including 100% of MAP is projected to be $1.8 billion. The mix is 51% upstream and 45% downstream. If you adjust 2002 capital spending to include only Marathon's 62% ownership share of MAP, capital spending would be 61% upstream and 34% downstream. Marked-to-market derivative and hedging activities contribute a net gain of $5 million pretax in the first quarter included is a gain of $17 million due to the change in fair value related to our two gas sales contracts in UK, I referred to earlier. Our approached heading is both opportunistic and highly selective and is geared towards minimizing downside risk. For example, we hedged first three years of Pennaco's production we may acquire them in the lock in high gas prices at that time to mitigate the upfront risk associated with buying the assets. 2002 related to the Pennaco acquisition, we have hedged an average of 152 million cubic feet per day at the average prices of $4.36 per MCF. Approximately 100 million cubic feet per day qualifies for hedge accounting treatment. The remaining 52 million cubic feet is marked-to-market each quarter. Late in 2001, and continuing into the first quarter of 2002, we see traditional opportunities to mitigate significant downside risk and a portion of oil and gas production for 2002. Today, we have hedged 54,000 barrels per day at 2002 equity of crude production using a zero cost color option strategy. This represents about 25% of our total worldwide crude production. This hedge has been structured in such a manner that on an average we will receive market plus $4 per barrel in prices of below $19.30. 23.30 when prices are between $19.30 and $23.30. Market price, when prices are between $23.30 and $29.30 and traded away any upside of about $29.30 to obtain these hedges. This position does not qualify for hedge accounting and will be marked-to-market each quarter. We also [entered] this summer, the cost color strategies on a natural gas production. Again, we are using color strategies to sell upside potential in exchange for downside potential. We have two strategies in top place for the present time. First, we have a 150 million cubic feet per day for April and May where we traded the upside to about 278 a lock in $2.35 in the 205 market and we received market plus $0.30 when the market is below 205, before we receive market when prices between 235 and 278. Second strategy utilizes a two-way color on 200 million cubic feet per day for the period June through December 2002 that represents d to about 16% of the worldwide gas production. This is a two-way color and the trader way about 4.48 per million cubic feet and a lock in the minimum price of 3.19 per million cubic feet. Again these positions are currently subject to marked-to-market accounting. Finally, I just want to make a few observations about the second quarter and full year 2002. On domestic upstream side, we expect liquids production to be down slightly versus the first quarter to about a 125,000 barrels of liquids per day. Gas production should come to about 720 million cubic feet per day. NYMEX comparable average price show so far in April was up over $25.75 versus the first quarter average. In the first of the month Henry Hub Index for April was about $3.40. Domestic explorations expense is anticipated to be approximately $10-20 million in the second quarter. On the international upstream side, liquids production in the second quarter should be up relative to the first quarter to about 90,000 barrels of liquid per day, primarily, due to Equatorial Guinea and the make of an [under lift] in the United Kingdom of approximately 8000 barrels per day. We expect gas production to be about 450 million cubic feet per day again due primarily to the addition of Equatorial Guinea partially offset by lower UK gas volumes. Based on what we see so far in April, fall in oil pricing seems to be following the domestic pattern. And international exploration expense is anticipated to be approximately $10-20 million in the quarter. On a barrel of oil equivalent basis, we expect second quarter worldwide production therefore to be down sequentially to approximately 410,000 barrels of oil equivalent per day. For all of 2002, we expect production from the base business to remain flat with an average 2001 base production at 415 to 420 million barrels of oil equivalent per day and based on our current business development activity, we remain confident that we can profitably grow our production and average approximately 430,000 barrels of oil equivalent per day in 2002. On a downstream, our [crack spreads] in April have averaged over 560 barrels in Chicago and 520 barrel in the Gulf Coast and marketing margins have improved. We expect our crude oil cost to continued to be up as a result of the continued tightness and [_____] spreads. But it looks like, we have turned the corner from the worst market we have seen in years. As far as the other energy income line, we expect second quarter income to be approximately $15 million not including the impact of the temporary shutdown of the Amco methanol plant, administrative cost should be about $42 million and net interest expense will be about $73 million. Thank you for your time. I will now open the call up for questions and I ask you to please identify yourself and your firm affiliation for the benefit of everybody who are listening in. Operator, are there any questions?

Yes, we do have a few questions in queue. I would like to remind you everybody that if you would like to ask a question, you can do so by pressing the 1 followed by the 4 on your telephone keypad. To retract your question, you can press the 1 followed by the 3. And our first question comes from Douglas Terreson of Morgan Stanley.

Hi, guys. How are you?

Hello Doug.

I have a question about the U.S. [AMP] business specifically you talked about some allocated costs related to commercialization and business development. I think the prices that you use, if my numbers are correct that probably [depend] large results about $40-50 million. So, my questions is could you provide some specifics as to exactly what that was and whether or not it is likely to recur in Q2. Could you give us some color on that number?

Doug, I think that $40-50 million estimate is a very, very high. Steve do you have anything to add on that. I am going to look at something here.

STEVE HINSHAM]: Can you hear me?

Yeah.

STEVE HINSHAM]: I believe really Doug, what has happened there is probably more of a misallocation of some these costs between international and the U.S. I think it is much more over stated there, but the real cost associated with the allocation are probably about on the order of $15 million, not $40 million. I think if you look this as a whole between that distribution of business development and commercialization and development cost that is essentially, it is around from where it was from last quarter, but not [_____] I think rated on a per barrel basis, it tends to cause a little bit alarm. I imagine that we will see that somewhat reverse to it when we closer to the second quarter business.

Okay, so the increase in cost that you are talking about which is a $69 a barrel was included this commercialization and business development item, but other items as well as a point?

STEVE HINSHAM]: The other cost items are pretty flat.

Doug, that $1.69 was strictly in the U.S. side. If you look at [our side] on a worldwide basis, we were essentially flat and I think that is the allocation issue that Steve is probably talking about.

Okay, that clarifies and so I appreciate. Let me just ask one other question quickly on marketing. Margins, obviously they were worse in several years and marketing in the Midwest and so, my question is whether or not you guys witness any unusual competitive dynamics in this area, and so could you rely what they were?

STEVE HINSHAM]: Gary, do you want to handle that?

GARY HAMIGLER]: Of course. Hi, Doug. Yes we did Doug, in the first quarter we have seen more inversions than I can recall in a long, long time and most of the inversions were in the Southeast, little bit into the Chicago market, but I would say that as we turned around going into April here, we have seen that reverse and we have started to see demand pickup just a little bit, which is a positive note and as demand picked up we started to see the retail margins improved a little bit. So, [_____] that normally, we have competed against, but I think behind us at this point in time.

Okay, guys I appreciate it. Thanks a lot.

Our next question comes from Fred Leuffer of Bear Stearns.

Good morning Fred.

STEVE HINSHAM]: Good morning.

Just on the production profile 424,000 barrels equivalent in the first quarter [is getting us to] around 4.10, I think for the second quarter?

STEVE HINSHAM]: That's correct.

And so if you just add amount, I think if you would hit the 4.30 for the year that would require about a 26,000 barrel increase in the second half. Would you expect that all of that would basically come from business development in order to head it over there, would you expect some internal growth as well?

GARY HAMIGLER]: Let me hit that initially and then Steve, you can comment on [outside]. We expect from our base business to be in the 415-420 range, and yes that additional amount will need to be made up through business development activities.

STEVE HINSHAM]: To get the 430, the 424 in the first quarter that was 410 is a typical swing that we see due to seasonal effects on gas demand primarily in our Alaska gas sales and our UK gas sales. For instance, in the second quarter of 2001, we have reached around 412,000 barrels a day. So, this is not an untypical amount of swing for us from the first quarter into the second quarter and we expect that the seasonal effects and will pick back up. We see a stronger third and fourth quarter and I am still very confident in our ability for the base business to make between 415 and 420 for the year that is very achievable.

That is officially still at the 430 kind; it sounds like that you guys have an acquisition [achieved], you are pretty close. Can you read on that?

GARY HAMIGLER]: I guess, Fred, I just that we are still confident. We are going to be able to get it done and we have got to remember, we have always said we are only going to do this. We think that we can do it. We think that we will be able to pull it off. But we are only going to do it for something that is really a value accretive. We are going to [lod] and just buy that 10,000-12,000 barrels a day just hit the 430 that will not be the right thing to do. You will have not see that happen.

Okay. Just two more questions if I may. In Annapolis, what was the well cost and how soon do you think you will be able to drill followup well there?

GARY HAMIGLER]: Fred, good question. We really don't disclose the specific well cost out there and we were out there for a number of days. However, most of the costs were really on the operator, while the rig was incurring downtime.

Okay, that's great. And lastly, I know right heavy [_____] spreads were real tight in the first quarter, but do you have an estimate on what the Garyville [coker] may have contributed to earnings in the first quarter?

GARY HAMIGLER]: Yes Fred, we believe, we have given some information before that we thought, Garyville should improve our total cost about a $1 a barrel, and I would say that first quarter was right on that forecast.

Okay, that improved your cost, so what is the shrinkage in the spread Gary, do you have an estimate on what impact, net of all that you had in the first quarter?

GARY HAMIGLER]: That net at Garyville we recognized that cost benefits of a $1 a barrel.

Okay. All right thanks.

STEVE HINSHAM]: And Fred for you and any other listeners out there, the dollar that Gary quotes is across the entire Garyville slate not MAP slate or just the [coker] portion, but across Garyville slate.

Okay. Thanks again.

The next question is from Paul Cheng of Lehman brothers.

Hi guys. Several quick questions. Ken, you told about on the gas production in U.S. Do you think that there is sequential decline just because of the warmer weather in Alaska, sometime in Gulf of Mexico may be slowdown in drilling or that other item. Can you breakdown further that sequentially, how much of the shortfall or that the decline is contributed to each of the different items?

Steve, do you have that?

STEVE HINSHAM]: I will be happy to address that. Paul, you are talking about fourth quarter [to] first quarter?

That's correct.

STEVE HINSHAM]: As Ken mentioned, the biggest percentage of that is our Alaska weather. It is probably on the order of around $30 million. It is the deference between what we sold up there in the fourth quarter 2001 and first quarter 2002. We had some gas plant interruptions at [_____] the first quarter primarily in East and South Texas that probably contributed another $20 million or so and we had some downtime in the Gulf of Mexico, a well failure in Troicha and some maintenance that has taken place in the lower gas prices environment and some our facilities that probably contributes on the order of about $10 million. We also had a little bit of gas still left in our fourth quarter from our dispositions as we are trying to wind down our dispositions in Canada that probably rounds off in another 10 or so million a day net and that really makes up the lion shares difference between the gas in North America. I guess Canada would not be part of the domestic. I think that's the questions you asked.

Right.

STEVE HINSHAM]: Primarily Alaska and really warmer weather than what occurred in the fourth quarter, East Texas and South Texas disruptions in some gas plants and some downtime on wells and some maintenance [on] facilities in the Gulf of Mexico.

I [_____] that the Eastern and Southern Texas, as well as the Gulf of Mexico, those downtime is brought up by onetime measure. Should we assume why that in the second quarter your gas will continue to be declining down to about 7.20?

STEVE HINSHAM]: That's primarily again resulted historically a lot of gas in the U.S. will be able to bring back up, but again we will see much more reduction in our sales volume that of Alaska and the swings are huge between peak heating requirements in the winter and then the former sales.

Your Alaska gas is about 110 only, right?

STEVE HINSHAM]: In the first quarter it was 201.

GARY HAMIGLER]: Yeah.

STEVE HINSHAM]: But you can [be] as well as 110. It is almost a 100% swing in our Alaska productions.

So, that is actually for the domestic. You are not taking about the LNG gas productions right? Or its the [combination]?

STEVE HINSHAM]: The LNGP is more constant and it depends on the LNG liftings, ... you are talking about half of the introductions that is into the local markets.

Okay. Secondly, Ken, on the downstream, you have talked about several different [_____] forcing the results of the present days they was this quarter the including compression of the [solid] the signs of the wholesale margins and then the [crude intrinsic]. On the [crude intrinsic], I thought that with rising oil prices that should be a positive impact for you guys, why it will be negative? And also do you have a corresponding number that how much is the compression of the followthrough and wholesale margin compression that causing you guys in the first quarter?

GARY PIPER]: This is [Gary Piper]. On the [crude intrinsic] first, the issue there is that we take title to crude oil in the Persian Gulf and we do not price that crude oil for another 45 days or so until it rise in United States. So, the prices rise as they did in the first quarter, we owe more and more for that crude oil than we provisionally priced originally. So, as prices rise, we had a larger payables than what we subtitled that crude... price rise hurts us financially. Regarding the other matter...

But Gary, sorry, if you are looking at [crack spreads] that is based on the spot [crack spreads], ...

GARY PIPER]: NYMEX [crack spreads] ...

Right, and [_____] that will be on the spot prices on the way?

GARY PIPER]: We take titles to it from a [life hold] standpoint. Once we take a title net risk a lot, it goes into cost of sales. Everything we do is on a life hold-costing basis.

Okay.

GARY PIPER]: When we take title to it, even though it has [never refined], from a life hold standpoint, it goes into cost of sales, as if it have been refined.

Okay.

GARY PIPER]: Okay, once we take titles of those barrels, it has [_____] it's then refined assuming our inventories won't change period-to-period.

Okay. That's fine.

GARY PIPER]: Okay, on the other two matters the compression in the crude oil differentials and the compression that we also witnessed in the wholesale market, they are about equally divided in terms of how what their impact on us. So [when] you compare the fourth quarter to the first quarter, we had about a $50 million swing in the intransit effect that can laid out earlier. It was a slight tightening of the actual 312 which cost us about $20 million doing the MAP. The rest of it was pretty evenly divided between the squeeze on the differentials as well as the tighter wholesale margins we experienced in the first quarter versus the fourth quarter of last year.

GARY PIPER]: That is correct.

Okay. Very good. Thank you.

Our next question comes from Mr. Paul Ting of Solomon Smith Barney.

A question on the downstream. You mentioned infact that your utilization rate went from 95% in the first quarter partially because of the low margins are resolving in some work cuts. Can you identify expenses associated with work cuts and maintenance programs in the first quarter? Is that a fairly [sizable] number?

GARY PIPER]: This is Gary Piper again. We do not really look at it that way. I guess we would look at it better comparison as to the first quarter of last year which is more traditional of the seasonality in our business. We are selling a lot of asphalt this time year and we are using this opportunity of the lower margins to do maintenance in the first quarter. So I think the more relative comparison in terms of how we run our businesses will be to the first quarter of last year and in that basis, we are actually up quite a bit on our comparative basis.

Up quite a bit what is that I am sorry...

GARY PIPER]: Last year's first quarter, our crude oil refine averaged about 870,000 barrels a day; this year was 891,000.

Alright. Okay. Can you give us some idea, as far as to where are you now in term of the utilization rate to investor metric suggest people are kind of ramping up there refinery throughput. Can you tell us what you are doing the same thing and what the numbers may look like?

GARY PIPER]: Paul this is Gary. We are running all of our units at full capacity at this time. We just have a couple very minor units down for maintenance, but they are not affecting our throughput much. So, we are really running at full debating capacity.

Okay, all right. Second question on Centennial, I believe you mentioned it up in the beginning of April. Have you add capacity right now or you are still in the ramping up stage in terms of the actual throughput?

GARY PIPER]: Yes Paul. We are still in the ramping up stage and as we have stated, the capacity of that system today as it is a pumping equipment that we have on today is around 210,000 barrels a day. However, we never anticipated that we have run here in the first year, as we would ramp up getting new customers, getting the cruel springs tank [farm] complete and the [_____] complete. So, in the first month here, we just started up. We have taken a very, very careful attention to all the hydrostatic testing and every step by the way to ensure the safety of that pipeline and it is performed right on target from a mechanical standpoint. So, you will see that pipeline continued to ramp up as we go into the second, third quarters.

Is there anyway to [get through 10] second or third quarter?

GARY PIPER]: No. We never anticipated [get through 10] in its first year. It will be significantly less than that.

Okay. Have you seen any impact on Midwest of market as we thought at Centennial I know it is very short period of time and not a very big volume, but any indications that you can share with us?

GARY PIPER]: I have not seen any change in the market.

Okay. Last thing, in your discussion about [_____] you seem to indicate that there is an expansion program that is working smoothly, any chance of exceeding the target of 35,000 MBD in the order of magnitude a guess of what a recent new level might be if there is a new level?

STEVE HINSHAM]: This is Steve. I will take that question. I think, I am comfortable kind of sticking with the 35,000 I think that is a pretty certain number. Of course, it is always our job to try to over achieve on that, but based on what we have in mind, I think that is a pretty solid number to go by at this point.

GARY PIPER]: One thing, you might notice in the comments, I mean, we had initially our first [lets] thought that we may increase to 650. Now as we keep examining the price looking at it, we think we may be able to increase the gas production closer to 8. So I guess that is one of the reason Steve is very comfortable with the 35. Everything we have seen today has been actually seen plus side than the negative side.

Yeah, absolutely.

GARY PIPER]: Okay, thanks [all guys].

And next we have Mr Arjun Murti from Goldman Sachs.

Hi thanks, just another followup on the U.S. gas numbers. What are you expecting from the rest of this year and into next year, Pennaco split without within that?

STEVE HINSHAM]: Well, I will take your question. I don't have [remain] numbers here in front of me then I will do it up top of my head. Again I think our U.S. volumes are going to be pretty steady. We will see increases coming out of our coalbed Methane assets in the Powder River basin that will more than offset decline. Powder River basin is currently producing about 60 million a day in the original asset and of course, when we close on May 1st with the trade that we have concluded will be doing about $84 million. I think the guidance we had given earlier was that we would average this year somewhere between $90 million on a low-end, and $120 million on a high-end, Pennaco. I think that will continue to be the case and that's the base business as we have had few business on that's probably another a $20 or $30 million that will come about for the year. So, that's my expectation. I apologize, I am sitting in a hotel room in New York and I don't have all my numbers in front of me.

That's okay. I guess, if you seen into 720 guidance, the guidance you gave on Q1 versus Q4 seem reasonable, but then now we are down 7% year-over-year Q2 versus Q2 last year. I mean steady status, its feels like [tie] rates are pressuring whatever gains we are getting in the Powder River trying to adjust our asset sales and acquisitions.

STEVE HINSHAM]: I think, the underline decline on gas overall not just Marathon, but overall I think it is a pretty good treadmill and it takes a lot of activity just to make up for some of that decline. That's not the reasons that we like the Powder River and like the coalbed methane because we think it gives us some more consistent and lower decline production and a greater confidence in the overall resource base that helps to alleviate from that treadmill issue.

I guess, it feels like you kind a spend $500 million Pennaco, which [_____] and we are not really getting any net asset from that and that is how we should think about the U.S. gas business that has maturity increases and depletion rates increased you know you are going to have these sort of chunks extra-capital just to keep things flat. Rounded [in] acquisition being actually additive to volumes.

STEVE HINSHAM]: We really answer that question as we look at any new resources, it is on the merit of that resource and again a talking about returns of that particular transaction, it gives us what we are after is try to produce returns that are in excess of our cost capital and our projects that have upside that can give returns considerably above that and that's what we try to do if that's helping us gain ....if it's maintaining again the thing I tried to drive towards make sure it those investments are providing quality returns.

Terrific. Thank you very much.

Our next question comes from Mr [Matthew] with UBS Warburg (U.S.).

MATTHEW]: Yeah, good morning. Just I want to clarify in terms of the high level of exploration [rights of] in the U.S. in the first quarter. Obviously, [Redwood] was dry if you could give any more color on that. And secondly, you [_____] the impacts of lower production taxes in the U.S. CMP business, if you could quantify the extent [run out] in the quarter.

PHIL BERMAN]: I will take the exploration expense part of it. In terms of the exploration expense, three contributors to the exploration expense domestic writeoffs this quarter. First, it was [Redwood], a portion on the flat head well, and lastly a smaller portion of [_____] well; all were included in the first quarter results. So, those three were the key drivers for the overall exploration expense.

GARY PIPER]: And Matthew, I have not understand the second part of your question on the taxes?

MATTHEW]: The [excite] in the tax that the quarterly benefit was in the U.S., did U.S. benefitted from lower production taxes during the quarter?

GARY PIPER]: There was nothing said about lower production tax during the quarter. We had an effective income tax a little over 41% an that was the impact of the catchup of taxes from prior period and our overall effective rate would have been about 38 and because of the taxes in the U.K., our guidance was about 40% going forward.

STEVE HINSHAM]: Yes right, I am not [going to give] the overall growth rate. If you would look at the paragraph on at the state's upstream income [_____] included with high dry well expense partially offset by lower production taxes and a decrease in terms of losses. I just wonder if you could just possible quantify production tax side?

GARY PIPER]: I am sorry on the production tax side. John] do you have the quantified?

JOHN MILL]: I don't have the quantify Matthew, but if we are comparing I think we are in that paragraph first quarter of 2001 versus the first quarter 2002 with generally lower commodity prices, we would have be on a BOE basis would have incurred commensurately lower production taxes as well. Volumes were down a bit so that overall directionally our production taxes were down first quarter 2002 versus the first quarter 2001.

GARY PIPER]: That's true, they are probably almost half what they were in the first quarter of 2001, but they are essentially on part what they were in the fourth quarter 2001.

MATTHEW]: Okay. Thanks very much.

Next is [Mark Gilman] with [First Albany].

MARK GILMAN]: Yes guys, good morning. I noticed that the overall DDNA number for the corporation is very, very low, which prompts me to ask, what DDNA rating you was assigning to the EG asset on an unit basis place?

GARY PIPER]: One second here Mark we are [digging] through the finals. Mark EG on a BOE on a basis was about $2 per barrel of oil equivalent.

MARK GILMAN]: That seems very substantially below your unit acquisition cost. Could you explain to me, I have not get in there John?

JOHN MILL]: Obviously purchase price allocation and units that are being produced now versus you know, further units that are going to be developed with additional capitals throughout the 2002 beyond.

MARK GILMAN]: That likely to remain roughly at that level at $2?

JOHN MILL]: That's what we are forecasted for calendar 2002.

MARK GILMAN]: Could I just ask a clarification about the new set of realization that's recorded in the release. Do the realizations with hedging capture all of the hedging and marked-to-market effect or just those that are accounted for hedges?

GARY PIPER]: Mark those numbers include everything, hedges and marked-to-marked effects. Everything is included in that.

MARK GILMAN]: Can you comment as to hedging impact included hedge, marked-to-market, or both which?

GARY PIPER]: It included all of the marked, everything.

GARY PIPER]: I will break out to pieces for you a little bit. Remember, we had $17 million gain in the first quarter from this new determination that a gas sales contract in the U.K. needs to be marked-to-market that was $17 million positive and on the domestic side, including [_____] we had losses just under $9 million and in [OERB] it was about$ 3 million. So, on a net basis worldwide it was a net gain of just about $5 million.

MARK GILMAN]: Okay. You referenced pipeline earnings in [OERB]. What pipelines are in there?

GARY PIPER]: They have our interests in [_____] and they have our interest in [_____] are the two major ones.

JOHN MILL]: Yes, those two I believe Mark we also have Marathon's interest in [a couple of] lines including [explorer] and couple of products pipeline [_____] shore?

GARY PIPER]: [_____] shore and [explorer].

MARK GILMAN]: Centennial is in MAP, that's correct.

_____]: Hey, just want to clarify if I could, I was noticing in some of the trade tracks that there are things could be some difficulties and I believe its [_____] oriented with respect to the proposal on [_____]. Could you clarify what's the situation is there and what's their problem is?

STEVE HINSHAM]: This is [Steve Hinsham]. I will take that, you know basically I think that's a little bit of old news mark. There were some discussions early on about priorities in the [_____] and the project priorities between the [_____]. Those I think are now worked out and we still are looking for [_____] to come on sometime late by next year.

PHIL BERMAN]: This is [Phil Berman] just to add a little more color to it. I think that information is about three months old and I think you noted it was [_____] 01:05:32, but actually it was [_____] where the issues were.

__________]: I am sorry, I misquoted it is [_____].

PHIL BERMAN]: Okay. Just want to add a little more color to what [Steve Hinsham] just mentioned...

_____]: Okay. Thank you very much guys.

GARY PIPER]: Okay thank you. I think we have time for about two more calls, two more questions, I am sorry.

Our next question comes from George Gaspar of Robert W. Baird & Company.

Yes good morning to every one. A followup question on extra [_____] in terms of expenditure loads. What do you think it's going [to take] to get from current production up to this considerably higher level you are talking about? And what kind of timeframe do you view as the objective target?

STEVE HINSHAM]: Depending upon our LPG processing and what that really means is, how deeply got into the liquid product, the close cost of this would be somewhere from $600 - $700 million. We would expect that in the third quarter of 2003 that we would be bringing on the condensate processing and getting an initial ramp up of production from that and then completing the LPG facilities in 2004 which would get us up to the 35,000 plus in net liquids with those projects. That's the cost and the approximate timeframe.

Okay. In terms of the indicated level of capital expenditure for this year, how much of that is dedicated for the [_____].

STEVE HINSHAM]: This year we have about $120 million net dedicated to EG this year.

Okay. All right. Thank you.

GARY PIPER]: George and others listening those numbers that Steve were gross, our interest is just over 50%.

_____]: 120 was net.

Final question comes from Mr Steven Pfeifer of Merrill Lynch.

Actually guys all of my questions have already been answered.

GARY PIPER]: Okay. Thank you.

And we have no further questions. JOHN MILL}: Okay. Once again I thank you for time and we will be back with you again in about another 90 days. Thank you very much.

This concludes Marathon Oil Quarter 1 broadcast. Thank you for your participation.