馬拉松石油 (MRO) 2002 Q4 法說會逐字稿

Good day, everyone. And welcome to this Marathon Oil Corporation fourth quarter 2002 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.

All right. Thank you very much, and good morning. I, too, would like to welcome everybody to our fourth quarter 2002 earnings teleconference for Marathon Oil Corporation. With me on the call today for Marathon Oil are Clarence Cazalot, President and CEO, Phil Behrman Senior Vice President of Worldwide Exploration, Steve Hinchman Vice President of Production Operations, Steve Lowden, Senior Vice President of Business Development and John Mills, Chief Financial Officer. Also with me today from Marathon Ashland Petroleum are Gary Heminger, President and Garry Peiffer, Senior Vice President of Finance and Information Technology.

I'm going to spend about 25 minutes going over the high points of Marathon's fourth quarter and the full year 2002. Then we'll open the call up to questions. Approximately 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 remain on the site for 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 such statements. In accordance with the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2001, and in subsequent forms 10-Q and 8-K cautionary range identifying important factors but not necessarily all factors that could cause future outcomes to different materially from those set forth in the forward-looking statements.

The fourth quarter of 2002 was a good quarter for the upstream business. But the downstream felt the effect of rapidly changing crude oil costs, lower refinery through-puts due to increased plant maintenance work and the impact of lower retail and gasoline distill Atlanta margins and lower pipeline transportation revenue. Net income was $194 million or 62 cents per share. There were no special items in the fourth quarter 2002. Third quarter net income adjusted for special items was $149 million, or 48 cents per share. Reported net income for the third quarter was $87 million, or 28 cents per share.

Special items in the third quarter totaled a negative $62 million after tax and consisted of a $7 million loss on the early retirement of debt, a $61 million one-time retroactive adjustment related to the supplemental United Kingdom tax, and a $9 million loss for a contract settlement, all offset by a $15 million gain on the disposition of production properties primarily in the San Juan basin of New Mexico. For the full year 2002, adjusted net income totaled $563 million, or $1.18 per share, excluding $47 million of after tax special items. This compares with 2001's level of 1.485 billion or $4.80 per share excluding 1.328 billion of after tax net special items and discontinued operations relating to the spinoff of US Steel. Reported net income applicable to Marathon common stock for 2002 was $516 million, $1.66 per share, and for 2001, it was $377 million, or $1.22 per share. One of Marathon's key achievements during 2002 was the replacement of more than 250 percent of production and finding and development costs of less than $5 per barrel of oil equivelant at year end Marathon had proven reserves the more than 1.25 billion barrels of oil equivalent and is on track to increase its reserve base to approximately 1.4 billion barrels of oil equivalent by the end of 2004 excluding any acquisitions or dispositions.

Before I begin the segment discussions, it is important to point out that in the fourth quarter 2002, Marathon changed its reporting to include costs of certain emerging integrated gas projects in other energy-related businesses. Reclassified costs relate to the Tijuana Regional Energy Center, the Equatorial Guinea Phase 3 LNG project, and the ultraclean fuels research an development project sponsored by the US Department of Energy. Previously in 2002, these costs were reported in exploration and production. We also reclassified costs between our domestic and international ENP operations for certain business development and other expenses. Segment income and capital expenditures for previous quarters in 2002 have been revised to reflect this change. There was no impact on the RM&Tsegment nor is there any impact on net income for the quarters. Our Investor Relations pact which is available now on our website reflects all of these changes.

The segment analysis in the following discussion of fourth quarter to third quarter segment income will also reflect the revised numbers. I'd like to point out that no changes will be made to 2001 segment results. Looking at the upstream segment, fourth quarter operating income totaled $345 million, or $9.01 per barrel of oil equivalent. In the third quarter, it was $256 million, or $7.22 per BOE. The fourth quarter upstream segment included $43 million of derivative gains while the third quarter was negatively impacted by losses of $18 million. For all of 2002, upstream operating income was $1.033 billion, or $6.87 per BOE, versus the 2001 level of 1.419 billion, or $9.23 per BOE.

Now focusing on upstream domestic operations, fourth quarter operating income was $198 million, or $8.86 per BOE versus $202 million, or $9.13 per BOE in the third quarter. Our average realized liquid price excluding derivative activity was $24.38 per barrel, up 37 cents from the third quarter level of $24.01. The increase is attributable to the significant outperformance against WTI of NGL prices in the quarter. The prompt nimex posts average was essentially flat (phonetic). Our fourth quarter average gas price of $3.42 per MCF excluding derivative activity rose 67 cents from the third quarter level of $2.75. The change was in line with a bid week price increase of approximately 80 cents over the third quarter as our gas sales in Alaska do not follow Henry hub price movements.

On the a barrel of oil equivalent basis, revenue, that's average prices times volumes, averaged $22.40 in the fourth quarter compared with $20.32 in the third quarter. Derivative gains were $15 million, or 68 cents per barrel of oil equivalent. Expiration expense was was $45 million in the quarter or $2 of barrel of oil equivalent reflecting the impact of Neptune 4 and Kansas wells in the Gulf of Mexico.

All other costs in the fourth quarter totaled $12.11 per BOE up 87 cents per BOE versus the third quarter. The increase is primarily as a result of one-time FAS 144 property impairments and unproved property impairments. For 2002, DD&A is anticipated to remain flat for 2003. Liquids production came in at 118,000 barrel of liquids per day, down 3 percent versus the third quarter primarily due to Hurricane Lili in the Gulf of Mexico. Natural gas production of 749 million cubic feet per day was up over 5 percent, primarily due to increased seasonal demand in Alaska. On a barrel of oil equivalent basis, overall fourth quarter daily domestic production was up 1 percent compared to the third quarter average.

Turning now to the international upstream segment, segment income was $147 million, or $9.20 per BOE, compared with $54 million, or $4.04 per BOE in the third quarter. Our average foreign liquids price of $25.55 per barrel was up 8 cents sequentially slightly better than the change in dated brand primarily due to the timing of (indiscernible). The average gas price of $2.79 per Mcf was up 49 cents on the strengthening of seasonal European and Canadian gas prices in the fourth quarter. On a barrel oil equivalent basis, revenue averaged $21.42 versus $19.36 in the third quarter. Derivative gains were $28 million, or $1.75 per BOE, primarily related to two long-term gas sales contracts related to Bray.

Expiration expense of $9 million was down $16 million to 50 cents per barrel of oil equivalent. All other costs totaled $14.40 per barrel of oil equivalent up $1.01 per BOE versus the third quarter. The increase -- pardon me. Excuse me. The increase is a result of increased liftings in the fourth quarter at Bray and Point Haven.

For 2002, DD&A was $6.31 per barrel of oil equivalent. For 2003, DD&A is expected to be less than $6 per barrel of oil equivalent. Production came in about as expected. International oil production liftings of 92,000 barrels a day were up 33 percent compared to the third quarter. The increase was a result of higher liftings of Bray, Point Haven and Gabon. Gas production came in at $489 million cubic feet a day, up 7 percent over the third quarter due to increased seasonal demand in Europe.

Worldwide production averaged over 416,000 barrels of oil equivalent per day in the fourth quarter, up 32,000 barrels of oil equivalent per day over the third quarter. Production for the year averaged just over 412,000 barrels of oil equivalent per day down 9,000 barrels of oil equivalent per day from 2001. The full year reduction is a result of weather-related down time and natural field declines.

Now turning to Marathon's development projects in the United States. In the Gulf of Mexico, Marathon's 50 percent owned Camden Hill project came on production on October 11. It is currently producing 105 million cubic feet of gas gross per day from two wells. Camden Hill set a new world record for production from ultra-deepwater at a depth of 7,209 feet. It is an outstanding technological achievement and sets a new industry benchmark. Coal bed natural gas production in the Powder River Basin averaged 29 million cubic feet per day net in the fourth quarter compared to 90 million cubic feet a day in the third quarter.

For the year, production averaged 79 million cubic feet per day compared to 47 million cubic feet per day in 2001, a 70 percent increase. A portion of the increase is a result of a property exchange. Excluding the acquired volumes production increased over 25 percent and is consistent with growth from 2000 to 2001. The property exchange represented an addition of 400 Bcf of total resource of which 110 Bcf is proven. Marathon's total resource in thes basin is 1.6 trillion cubic feet including 417 Bcf of proven reserves.

The Bureau of Land Management published the final environmental impact study for the Powder River Basin on January 17. Following a comment period, we expect a record of decision to be issued in March. Marathon plans to drill between 400 to 500 wells in the Powder River Basin in 2003, all of which are currently permitted and not dependent on approval of the EIS.

Looking forward to 2003, production from the Powder River Basin should average between 100 and 115 million cubic feet per day. The UK Atlantic Margin Point Haven development continues to perform well. Point Haven net sales for the fourth quarter were 31,000 barrels of liquids per day and 14 million cubic feet of gas per day. We continue to discover additional near Point Haven development opportunities and we'll have three or four-well development program in 2003.

Net sales for 2003 are projected to be 29,000 barrels per day of liquids and 14 million cubic feet of gas per day. EquatorialGuinea is currently producing near record high liquid hydrocarbons at a gross rate of nearly 21,000 barrels of liquids a day and 130 million cubic feet of gas sales to the methanol plant. Gross liquid production for 2003 is projected to increase to 28,000 barrels of liquids per day, gross gas sales to the methanol plant will remain at about 120 to 130 million cubic feet of gas per day. Therefore, Marathon's net production for 2003 will average 27,000 barrels of oil equivalent per day, up from 18,000 barrel of oil equivalent per day in 2002.

An aggressive two-phase expansion plan to increase gas recycling and expand continent state and LPG production was approved by partners and the government in2002. When these two expansions are complete in the fourth quarter of 2004, our Equatorial Guinea business will be producing and selling nearly 90,000 gross barrels of liquids per day consisting of 54,000 barrels of condensate, 16,000 barrels of LPG, and 20,000 barrels of methanol.

Marathon's net share of liquid sales will be 30,000 barrels per day of condensate, and 8,000 barrels per day of LPG as part of the exploration and production segment. And 9,000 barrels of liquids a day of methanol included in our other energy-related business segment. Marathon's net proven reserves in Equatorial Guinea now total approximately 300 million barrels of oil equivalent, about 2/3 liquids around 1/3 gas.

Turning now to exploration, Marathon participated in two deepwater wells in the Atwater Valley area of the Gulf of Mexico. The first was a Kansas project on Atwater Valley block 489 located in about 4500 feet of water. This well was unsuccessful and was abandoned. Marathon has a 33 percent working interest in the block and is the operator.

The second well was the Neptune number 4 appraisal well which tested the northern part of the Neptune prospect. After failing to find hydrocarbons, this well was suspended for possible re-entry in the future. Marathon's interest in Neptune is 30 percent and BHP is the operator.

Marathon is currently drilling two wells in the Gulf of Mexico, the first is the Kamoto prospect on Green Canyon block number 569 adjacent to Neptune. The prospect is five miles Northwest from the Neptune discover well. Marathon operates Kamoto (phonetic) and has a 50 percent working interest in the prospect.

The second is the baracuda prospect on desoto Canyon block number 927, the first modern deepwater well in the Eastern Gulf of Mexico. This well is located in about 8500 feet of water, Marathon is the operator with a 50 percent working interest The first well on Angola block number 32, the Gindungo prospect has reached total depth of about 15,600 feet. Results are encouraging and the well is currently being tested . Marathon's interest in this block is 30 percent.

Looking at exploration for all of 2003, Marathon plans to increase drilling from 14 wells in 2002 to about 26 wells in 2003. While keeping total exploration spending relatively flat at $250 million. We will maintain activity levels in our three deepwater trends with the majority of the increased activity expected to occur in new core areas around Heimdal in Norway and the Alba Field in Equatorial Guinea.

Turning now to downstream results, the reportable RM&P segment in the fourth quarter as $88 million, compared with the third quarter level of $108 million and last year's fourth quarter level of $221 million. The fourth quarter downstream environment produced financial results for MAP that were substantially lower than what market indicators would have suggested. A simple look at the change in Chicago and Gulf Coast crack spreads weighted two-thirds Chicago and one-third Gulf Coast indicate MAP's income for the fourth quarter would have improved by over $100 million.

The widening of sweet/sour differentials quarter over quarter would have added another $25 million. About $60 million of this improvement in market conditions was offset by lower crude oil and other feed stock through puts primarily due to planned maintenance work at MAP's Robinson, Illinois, and St. Paul Park, Minnesota, refineries.

Volatile crude oil prices during the quarter compressed both wholesale and retail margins, further reducing MAP's income by more than $25 million. In addition, maintenance and energy costs and lower pipeline revenues resulting from the lower crude runs and the effects of the hurricanes in the Gulf of Mexico late in the third quarter also reduced income. The net effect of these and other miscellaneous factors was a $20 million reduction in Marathon's RM&T segment income versus the third quarter.

Chicago 321 crack spread averaged $6.38 per barrel in this year's fourth quarter versus 5.02 per barrel in the fourth quarter and fourth quarter 2002 crack spreads averaged $4 per barrel in the third quarter and $2.06 per barrel in the fourth quarter of last year. For the full year, Marathon's refining marketing and transportation segment income totaled $356 million or 74 cents per barrel versus the 2001 record level of $1.914 billion, or $4.02 per barrel.

Our refining and wholesale marketing margin in the fourth quarter was 4.6 cents per gallon versus the third quarter level of 3.9 cents and 6.4 cents a year ago. The gross product margin for our retail business Speedway SuperAmerica was 10.1 cents per gallon in the fourth quarter, 10.6 cents in the third quarter, and 11.4 cents in the year-ago quarter.

Refinery crude oil runs averaged 831,000 barrels per day in the fourth quarter of 2002, or 89 percent of rated capacity, down approximately 10 percent from the third quarter and year-ago levels. Refinery runs were down in the fourth quarter primarily due to turnaround activity at Robinson and St. Paul Park. Total product sales averaged 1.306 million barrels per day in the current quarter, down about 6 percent from the third quarter and down less than 1 percent from a year ago.

Merchandise sales and margins are flat when comparing the same quarter 2002 to 2001, but on a same store basis, merchandise sales were up about 2 percent compared to the same period in 2001, which was up approximately 12 percent over the same period in 2000. The fourth quarter decision was $17 million negative. The effect was a negative $15 million in the third quarter and a total 54 million negative for the full year. Fourth quarter 2001 by comparison included a $30 million positive impact.

In the third quarter, MAP received final approval and began construction on the Cardinal Products Pipeline. The new line will extend from West Virginia to Columbus, Ohio, will have a design capacity of 80,000 barrels per day. It is expected to initially move about 50,000 barrels per day of refined petroleum into central Ohio and the line is expected to start up midyear 2003.

Turning to the other energy related business segment, operating income was $15 million in the fourth quarter versus $23 million in the third quarter. The $8 million difference is primarily attributable to derivative-related losses of $8 million in the quarter versus a gain of $2 million in the third quarter, offset by increased income from the Amco methanol plan in EG and higher income versus a gain of $2 million in the third quarter, offset by increased income from the Amco methanol plan in EG and higher from Gulf of Mexico pipeline assets. The remaining difference is attributable to the reclassification of business development and other costs related to integrated gas projects that were previously charged to the upstream segment.

On December 10, we were awarded a front end engineering and design contract for the Phase 3 LNG project to monetize the 3.1 TCF of gross recovery dry gas from the Alba Field as well as other stranded or flared gas one 100 kilometers of the island. With our recently acquired Rigas off-load capacity at Elba Island, we continue to define and develop our Atlantic basin LNG strategy. On January 6, we were awarded the front end engineering and design contract for our LNG regasification project near Tijuana in the Mexican State of Baja, California. This complex would supply natural gas and electricity for local use as well as for export to Southern California.

The next major milestone for this project is the granting of the permit to build the plant. We expect the permit will be issued in the first quarter.

Now turning back to total corporate results, derivative-related gains were $35 million pre-tax in the fourth quarter, consisting of $17 million of gains on natural gas and crude oil hedges and a $26 million market-to-market gain on two of our long term gas contracts related to Bray. Offset by a loss of $8 million in other energy related business. For 2003, we have hedged a substantial portion of our anticipated gas production utilizing zero cost collars. For the first half of 2003, we have hedged 225 million cubic feet per day with a weighted average floor price of $3.71 per Mcf and an average ceiling price of $4.71 per Mcf.

For the second half of 2003, we have hedged 285 million cubic feet per day at a weighted average floor price of $3.83 per Mcf and an average ceiling price of $4.97 per Mcf. These contracts should qualify for hedge accounting.

On the liquids side, we have entered a number of contracts on 2003 equity crude oil production using options to establish zero cost collars and forward swaps for fixed price sales. To date, we have hedged using zero cost collars 33,500 barrels per day for the first half of 2003 with a weighted average WTI equivalent floor price of approximately $23.35, and a weighted average WTI equivalent ceiling price of approximately $28.50.

For the second half of 2003, also using collars, we have hedged 24,000 barrels per day with an average floor and ceiling price approximately the same as the first half of the year. Again, these contracts should qualify for hedge accounting. Also for the second half, we have hedged using swaps for fixed price sales a total of 37,000 barrels a day of our domestic and international crude production, a WTI or equivalent forward sales price of approximately $27.50 in the third quarter and $26.00 in the fourth quarter. Like our 2003 gas and other oil contracts, these should qualify for hedge accounting limiting most of the mark-to-market volume volatility we have experienced in 2002.

Moving back to financial results, total segment income in the fourth quarter of 2002 was $448 million, up 16 percent from the $387 million in the third quarter. Upstream was up 34 percent while the downstream was down 18.5 percent. In the unallocated category, administrative expense was $69 million in the fourth quarter. This compares with a third quarter total of $42 million. The increase in the fourth quarter is the result of a state franchise tax increase and a number of of nonrecurring year-end employee and benefit-related accruals, not exceeding $6 million.

Net interest expense was $53 million in the fourth quarter, versus $75 million in the third quarter. The lower expense for the quarter was a result of foreign exchange gains of $14 million, and increased exposure to short-term interest rates. Cash adjusted debt went down by $282 million during the fourth quarter to $4.1 billion. The cash adjusted debt-to-capital ratio at December 31, 2002, is 44.5 percent, down from 46.5 percent at September 30.

These are preliminary numbers. Debt reduction has been and will continue to be a priority for Marathon. Our cash adjusted debt to total capital ratio peaked at 48 percent at the end of the second quarter of this year following our acquisition of Globex interests in Equatorial Guinea and, as stated before, year end is at 44.5 percent, a 3.5-point reduction in six months. We also worked hard this area to take advantage of the low interest rate environment. We issued $1.85 billion of new public long-term debt and retired or repurchased the face amount of $337 million of high-cost debt we assumed with the spinoff of US Steel.

Additionally, we utilized interest rates swaps to further reduce our overall debt cost, excluding liquidity facilities we have reduced our long-term debt cost by over 125 basis points to approximately 6.7 percent. Marathon's pre-tax income for the fourth quarter reflecting just Marathon's share of downstream income was $294 million. The tax provision was $100 million or 34 percent effective rate. The effective rate for all of 2002 excluding the third quarter $61 million deferred tax in the UK was 35.5 percent. The lower-than-expected tax rate in the fourth quarter and for the year is the result of higher-than-anticipated foreign tax credits due to the timing of foreign dividends.

Looking to 2003, we project an average effective rate of approximately 38 percent for the year. Fourth quarter preliminary cash flow from operations excluding working capital changes was $580 million, or $1.87 per share. That's up 16 percent versus the 500 million, or $1.61 per in the third quarter.

For the full year 2002, cash flow totaled nearly $2 billion, or $6.27 per share. For all of 2002, is including acquisitions and including 100 percent of MAP, capital spending was $1.57 billion, upstream 55 percent and downstream 39 percent. Adjust our 2002 capital spending for Marathon's 62 percent ownership share of MAP, capital spending was 64 percent upstream and 28 percent downstream.

Our capital budget for 2003 will be approved very soon. While not final, the preliminary budget would have production spending of $770 million, exploration and exploitation spending of $335 million, refining marketing and transportation spending at MAP of $730 million, and $120 million in other capital spending including approximately $55 million of capitalized interest. The 2003 expiration and production spending budget is focused on our new core areas and has shifted to international spending as compared to 2002. International spending is projected to be 65 percent of our E&P spending in 2003 versus 53 percent in 2002.

Benefit plan accounting have been prominent in the press of late so I'd like to provide an update on the Marathon and MAP plans. For 2002, both pension plans used plan earnings assumption of 9.5 percent and a discount rate of 7 percent. For 2003, these assumptions have been revised to 9 percent and 6.5 percent respectively the impact on pension expense in 2003 will be an increase over 2002 of approximately $18 million for the Marathon plan and $35 million for the MAP plan. The net pre-tax impact on Marathon adjusting for Ashland's 38 percent minority interest in MAP is $40 million. Both plans have been funded such that no cash contributions have been required of the Marathon plan for more than a decade and no contributions have been made to the MAP plan since the company was formed in January of 1998.

In 2003, MAP will make a contribution to the MAP plan relating to the 2003 plan year of $35 million. No cash contributions will be required for the Marathon plan in 2003. Looking to other post-retirement benefits, for 2003, the annual rate of increase in per capita cost of covered healthcare benefits was increased from 7.5 percent to 10 percent. The expense impact to Marathon and MAP will be an increase of approximately $8 million and $10 million, respectively, over 2002. The net pre-tax impact on Marathon adjusting for Ashland's 38 percent minority interest in MAP is approximately $14 million.

Finally, I want to make a few observations about the first quarter and full year 2003. On the domestic upstream side we expect liquids production to be down slightly versus the fourth quarter to about 113,000 barrels per day. Gas production should remain up for seasonal reasons, coming in at about 790 million cubic feet a day. The Nymex prompt average price so far in January is $32.49 versus the fourth quarter average of 28.23. The Henry hub average gas price is up from the average of 4.32 to 5.28 per Mcf. Domestic exploration expense is anticipated to be approximately 25 to $40 million.

On the international side, liquids production in the first quarter should be down relative to the fourth quarter to about 74,000 barrels of liquids per day, primarily due to lower liftings in Europe versus the high liftings we had in the fourth quarter. We expect gas production to be about 500 million cubic feet per day up slightly due to higher seasonal sales in Europe. Based on what we have seen so far in January, foreign oil pricing seems to be following the domestic pattern. International exploration expense is anticipated to be approximately 20 to $30 million.

On a barrel oil equivalent basis we expect first quarter worldwide production therefore to be down sequentially to approximately 402,000 of barrels oil equivalent per day. For all of 2003, we expect production to average 390 to 395,000 barrels of oil equivalent per day excluding acquisitions and dispositions.

On the downstream, crack spread year-to-date have averaged about $2.63 a barrel in Chicago and $3.40 per barrel on the Gulf Coast. As far as the other energy income line, we expect income to be 15 to $20 million and administrative costs to total about $45 million. Net interest expense will be up to approximately $61 million for the quarter, for all of 2003 we project net interest expense of $235 million.

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

Thank you, our question-and-answer session will be conducted electronically If you would like to ask a question, press Star 1 on your touch-tone phone. If you are on a speaker phone, please make sure that your mute function is turned off so your signal will reach our equipment. We'll take our first question from Bruce Lanni with AG Edwards.

Yeah, good morning. How are you doing?

Good morning, Bruce.

Good morning. Good. Just a couple quick questions. Could you give us a little more detail regarding your reserve replacement for this year as far as what the organic portion versus the acquisition is?

Sure. Steve?

I'd be happy to do it. This is Steve Hinchman. For the year as we said, we would be over 250 percent with the finding and development costs of under $5 per barrel. And, of course, that includes the acquisition in Equatorial Guinea both CMS and Globex. Without -- if we exclude the acquisition, the organic part is still at a finding and development cost of under $5 per barrel.

Bruce, this is Clarence. I think we would reiterate as we have done in the press release that it is our expectation loops excluding any acquisitions or dispositions that at the end of '04, our proved reserves would be 1.4 billion barrels of oil equivalent and I think when you look at that relative to the capital spending, we projected for '03 and about the same in '04, again, that yields very competitive F&D costs of between 5 and 6 dollars a barrel.

And Clarence, just one other thing, though. I understand you told me about the F&D still being under $5. But what would the reserve replacement be if you excluded the acquisition and divestitures in 2002?

It would still be about 190 million barrels.

Which on a percentage basis, so I don't have to do the math, I mean works it --.

We produce 150 million barrels....

Okay. So it would be in excess of 100 percent.

Yes.

Oh, excellent. Okay. Just to follow up on one other question, then you talked about the capital spending. I guess I didn't get it clearly or quickly enough. But you outlined what it was going to be for 2003 and if I added that up co I guess I didn't get it clearly or quickly enough. But you outlined what it was going to be for 2003 and if I added that up correctly, I think it comes out to about 1.9 to 2 billion, is that correct?

It would be 1.96 billion, Bruce. Correct.

Okay. How does that compare again to 2002 on an apples-to-apples basis? Was that 100 percent of MAP that you put into that number? That number includes 100 percent of MAP, yes, Bruce. So if we can include 2002, what was the total again?

With MAP included? Your total Cap Ex in 2002?

We have that number.

It would be about 1 point. Just under $1.6 b excluding acquisitions. So that would be an apples to apples comparison.

Great, thank you very much.

Moving on we'll hear from David Wheeler with J.P. Morgan.

Good morning. I have two questions for Clarence. 2003, it will obviously be critical for you guys to show some progress on the LNG projects in Equatorial Guinea and the Baja peninsula. What are the key milestones we should be watching for on that front and the second question for you is, I know you are eyeing doing some assets swaps to upgrade the upstream portfolio? Can you give us an update on plans for asset swap ups?

I'll take the second part there, David, and I'll let Steve allow deny talk about the LNG projects. We did have as you know, a program called big wheel where we intended to core up by swapping out of some of the areas that we didn't think were long term strategic assets for us and using that value and that -- those assets to core up in our primary focus areas.

I've got to say, we had some success of that swapping out of the San Juan basin into the Powder River but for the most part, we found it very, very difficult to trade assets amongst other parties. So that wasn't nearly as successful as we would have liked. With respect to the LNG milestones, I'll let Steve comment on that.

Yeah, David. In respect of Baja, our LNG Rigas terminal permit was submitted in 2002 this past through the public consultation. And we expect approval from CRE in the first quarter of this year. So that's really the first milestone to be watching for.

In terms of the Equatorial Guinea LNG project, we have completed this year. So that's really the first milestone to be watching for. In terms of the Equatorial Guinea LNG project, we have our analysis of the (indiscernible) as we mentioned previously and selected LNG. We have award the FEED contract and acquired capacity in Georgia, Elba island.

The government is certainly very supportive of the project and the key milestones for 2002 and we contract for the remaining of the markets in 2003, we'll contract for the remainder of the market and final Government approval.

Steve, how about partners for those projects? I know from both a feasibility and a financial standpoint, you would like to bring in partners. Where are you at in terms of bringing in partners on those two projects? Are those things we should look for to happen this year?

Yeah, we will look for partners certainly in respect to Baja and we ultimately expect to have about a third interest in the overall project. In terms of Equatorial Guinea, we already have partners. -- for that project and we'll see really how two-thirds -- how that pans out in terms of potentially bringing other partners in.

Okay. Very good. Thank you.

Moving on, we'll now hear from Arjun Murti with Goldman Sachs.

Thanks. The question was on Annapolis and how you're seeing the East Coast of [INAUDIBLE] you've obviously had some time to study the results of the first well and you are encouraged enough to be drilling, I guess, a second well there. Has your assumption of what the plate could hold change at all from what you learned? What do you expect to learn from the second well? Any plans to drill other prospects? Obviously I guess a lot is dependent on the second well here at Annapolis.

Arjun, this is Phil Behrman. I'll be glad to answer that question. Regarding Annapolis, the partnership has now gotten together. We have agreed as to where the next location will be t won't be an appraisal well on the Annapolis prospect. It will be another prospect that will be tested. Our logic is that we have learned quite a bit from the first well. We've learned a lot about the seismic as well as the geology and Incorporated that into our thinking.

In addition to the drilling activity, we plan to acquire seismic on the two adjacent blocks which we also own in 2003. We don't have a revised estimate of the resource potential. I think we're required to do that in the additional drilling, the new seismic taken together will probably allow to us assess and reassess the play in 2004.

I guess the seismic must then be giving you confidence sort of structure, sizes and so forth. The reservoir quality and produceability that's ultimately the bigger question here, can you comment on any of that?

I think the question is not the produce ability of the reservoir quality, it's the thickness of -- and finding the thick sands and the commercial quantities of sand will be on these structures.

Okay.

But I would say, Arjun, I think the essence of your question is, do we see the potential for this to be a commercial development? And we do, obviously, or we wouldn't be conducting even the follow-up drilling.

Sure. Thank you. And then just one follow-up on the Baja question. To the extent you get the permit approval in the first quarter, what happens after that then? What will be the follow-up milestones for this year?

Yeah. Arjun, this is Steve again. Follow-up actions to that are first to secure LNG supplies and we are talking to our partners and a number of other potential suppliers in that respect. Then it will be to complete the downstream marketing which were also equally active on.

Okay. Thank you very much.

We'll now take a question from Fred Leuffer with Bear Stearns.

Good morning, gentlemen.

Good morning.

Ken, just a couple of questions. First, I'm still having trouble getting to the refining and marketing number. thUhm... if I took down the components correctly, we also showed our indicators that you should have been up on the order that you indicated, about $125 million in the quarter. Then you gave us -- I wrote down three offsets, 60 million from lower through puts, retail margins about 25 m million lower pipeline volumes and maintenance expense about 25 million. Still should have put you up quarter to quarter. Did I miss an item or are there some other offsets in there?

There is a $25 million didn't include the latter items but I'm going to let Gary expound upon that they can handle it.

Okay. Thanks, Ken. This is Gary Piper. As Ken pointed out, when he was giving that about 60 million, we -- as you can see from the statistics, we ran a lot less crude oil, almost 9 million barrels less crude oil this quarter versus the September quarter. And the 25 million that was also referred to just refers to retail and to a certain degree some wholesale margins that we were lower this quarter versus the third quarter. Everything else we had higher manufacturing costs.

We also had some other effects in the quarter that essentially brought us down to this difference of about $20 million below the third quarter. So it's kind of cumulative on all those other effects.

These -- the two refineries that were taken down were planned, right?

Correct.

So I don't understand the impact of lower through puts. Didn't you build inventories in anticipation of this?

Well, we d but in the month of -- or in the fourth quarter this year, if you look at the statistical summary there we ran in the total system was 830,000 barrels a day. In the third quarter, we ran 931,000 barrels a day. That's 100,000 a barrels a day less quarter to quarter.

How about your sales?

Our sales were down somewhat I guess in total about 300 million I believe, total sales were down about 300 million but we supplemented some of those sales were greater purchases so the main issue here, though, is we were not manufacturing refined products to the tune before 100,000 barrels a day less quarter to quarter. So we weren't realizing those benefits of the -- if you just use the Chicago crack spreads of about 9 million barrels times five or six dollars a barrels depending where those barrels were now being produced at.

All right. I understand. Now, the (indiscernible) fire that you had earlier in the month? What's the status of that in the refinery?

Right. This is Gary. Uhm, coincidentally, the transformer that failed, failed shortly before we were going into our planned turnaround so we do not believe, Fred, there will be any material impact on first quarter results, that we expect to be back up from turnaround right on schedule and in fact we expect to get the crude unit up shortly.

Thank you, Gary. Ken, if I may just one more, you indicated that Neptune was suspended and I think in your remarks you said that there was some exploration expense recorded for that. But I imagine because it's a spin, you haven't written off your investment. Can you tell us what your exposure is at Neptune at this point?

This is Phil Behrman answering your question. The exposure is very, very small. We have written off virtually the entire well. We have maintained it so we can side track out as we continue to do more technical work and assets overall potential. And as you know, we are looking at drilling a fifth well in the second or the middle of the summer of this year.

All right. Thank you very much.

We'll now take a question from Matthew Warburton with UBS Warburg.

Good morning, gentlemen. Two questions if I may. I just wondered if Ken could quantify US asset impairments he mentioned in his remarks in terms of the dollar amount and reserves associated and field if possible.

Matthew, it was just under $14 million and it really was no no meaningful reserve impact from that at all. In fact, in our reserve replacement this year, we are going to have -- we will have net positive revisions. All right. So these were a number of small older fields.

Right. Thanks. And the follow-on, if I may, on the Symphony Project. Various comments this week in the press in terms of the stages. I wonder if Steve might bringing us up to date in terms of where that stands.

Yes, Matthew. The Norwegian and UK governments now fully recognize the need for additional gas supply and sales to the UK. And the need for new pipe lines to deliver these supplies to Southern England. Equally the European gas merchants and the UK buyers have conditionally reserved up to 1.3 Bcf on Symphony. However, we have not reached agreement with the Norwegian gas suppliers on the use or the routine of the export system through Bray. The original design of Symphony is probably in question today.

All right. Okay.

But there are other options which may well involve the Bray infrastructure.

Right. Okay. Thanks very much.

Moving on we'll take Mark Flannery with CS First Boston

Hi, good morning. A question on the pension and benefits. You mentioned that you have reduced the assumed rate of return from 9.5 percent to 9 percent. for 2003. Where does that number come from? And do you consider that to be in line with the assumptions being made by other companies in the rest of the market?

Yeah, Mark, we'll let John Mills take that.

Yeah, Mark, you know, we've looked at that number pretty carefully, and it is very much in line with the long-term return that our pension fund manager has achieved over a, you know, 50-year period that we believe that looking at our, you know, equity in bond investment mix, that's 9 percent assumed rate of return on plan assets is achievable over the long term. Obviously we have not achieved that number over the last three years. No one else has, either.

But we believe that it's an appropriate long term return and I'd say that you know, as you look at where our competitors are and other large defined benefit pension plans, greater return has a lot to do with equity debt mix within that portfolio and some plans that areplans that are, uhm that have a heavier fixed income component or debt component should have -- you should so a lower rate of return. But again, because of the overall funded status of our plan, roughly 75 percent equity allocation, we're very comfortable with that 9 percent plan earnings assumption.

Okay. And just turning, then, to the other staff costs, the healthcare costs, et cetera, 10 percent increase in per capita expense there, that's quite a big number the can you explain what's going on?

Well, it is a big number. We and other large employers have seen significant increases in healthcare costs in 2002 and that number is simply a reflection of what we're seeing in the marketplace.

Right. And are you seeing also, for example, increases in per capita salary required for 2003, as well?

Well, the, uhm, I mean, there's some upward adjustment to salaries. But certainly not in a range of 10 percent.

Right. Okay. Thanks very much.

We'll now take a question from Steve Pfeifer with Merrill Lynch.

Hi, guys. I wanted to follow up with the question regarding reserve replacements. I think you said that organic reserve adds 190 million on a production basis, about 150, which would be obviously very, very strong to serve as replacement of 126 percent. Could you just help us understand exactly what were some of the components of the reserve adds that were booked in 2002?

There is probably about 80 million of that comes from our base business, dmet domestic US on shore offshore and about 100 million of it is associated with the expansion projects in EG that were approved this year. If you look at the base business adds of about 80 million, that's coming in still at a price at F&D cost of just slightly over $5 a barrel.

Is that coalbed methane?

It's that and our project in Alaska. It has our some of our lower 48 gas development drilling which is scattered all throughout the mid connent primarily in Oklahoma. It includes a [Braymar] project in the UK, it would include our [Kinslehead] project Green Sand development well, and Powder River.

Okay, great. And on the EG, the expansion -- I assume none of that is really predicated with the 100 millions there, none of that is predicated on LNG?

This is just the Phase 2 expansion which would include the condensate expansion and the LPG expansion projects.

Okay. Great. And on the downstream, again, in looking at the refinery run, you had the lowest runs this quarter in at least the last three years. And was this just a very, very heavy turn for the quarter and maybe put in some context how this particular quarter in terms of refinery turns looks compared to the past and what would you expect into next year, and maybe some sense for what your runs are roughly for 1Q and where you think they will be for the first quarter.

Can I take that?

Sure.

It was if you go back and look at 2000, 2001, we were blessed that we didn't have many big turnarounds in those two years just as we look at the cycle in the way we do our turnaround business. So, yes, we, unfortunately, these two turnarounds fell in the fourth quarter. I guess looking at first quarter, we think our business plan for the first quarter is pretty much in line with the first quarter of '02. However, current market conditions, you know, we look at every day at current market conditions and the run rates and the crack spreads and that will dictate, you know, what our actual run rate is. But with some work we have planned, I would say it would be pretty close to the first quarter of last year, depending, Steve, on where the markets go.

Okay. Great. Thank you very much.

Yes.

We'll now take a question from Gene Gillespi with Howard Weil.

Good morning. Couple of things. In your third quarter conference call, I believe, Ken, you had indicated that interest expense would be flat at around $75 million. And it came in at $53 million. And I know John Mills is good -- but is he that good? (Laughter) can you explain that?

Thank you, Gene!

I will explain this because John is smiling too broadly to talk right now, Gene. (Laughter) as we pointed out on top, about $14 million of exchange gains netted against interest expense, Gene. We don't anticipate any exchange gains in that estimate that we put out in the third quarter call. And we also were able to take advantage through swaps, et cetera, of lowering and taking advantage of short-term rates to a greater extent than we thought we could in the fourth quarter. That's really where the difference is.

Okay. How about on the same similar thing with G&A, we were looking for something more like $49 and it's $69.

Right. Gene, the difference there again was essentially a state franchise tax increase and a number of different employee and benefit-related accruals in the fourth quarter, none of which are really recurring and none of which individually total exceeded $6 million. So we don't expect that -- that's why I have given you an estimate of closer to 45 for the first quarter, a more normal level.

One last thing. As it relates to Barracuda, that's going to be the first well drilled in the Eastern portion of the Gulf of Mexico for a long, long time. And I know that that had been permitted I think prior to the most the latest deal with the State of Florida. And I guess my question relates to if you find something, does the State of Florida have to approve a development plan and is there a time frame -- do they have a time limit with which to do that, with which to act, or can they drag their feet indefinitely?

Gene, this is Phil Behrman. Just a comment on it. All of the state that is could be affected, of course, have the ability to have input to the coastal management plans that are required in that time frame. And again, a development there would have input from Florida, amongst other states in that area and, of course, it would be approved by the MMS. There are defined time frames for all those processes.

And the defined time frame is less than a year?

Yes. That's correct.

All right. Thank you.

We'll now take a question from Paul Cheng with Lehman Brothers.

Hi, guys. Good morning. Several quick questions. On the pension, either Ken or John, (indiscernible) after the contribution are you guys at this point fully funded? If not, what's the deficits? Second one, maybe for Gary, on MAP, in the fourth quarter (indiscernible) compared to the bench market of substantially lower.

Are we looking into the first quarter '03 sequentially from fourth quarter, the change in earnings, is the benchmark change in margin is a reasonable proxy or should we take into other consideration or adjustments? If we do, what are those that may be? And then lastly, uhm, maybe this is for Karen, for the -- I think that there is some room talking about the -- rumor talking about Saudi Arabia gas co-venture too at this point may not be able to go forward. Wondering is there any comment you can make?

Take that in reverse order?

There is not much I can say about core venture 2. I think ExxonMobil as now is a leader of that venture. They continue the discussions and we remain involved and optimistic that those will go through. So... I wouldn't listen too long to rumors.

Okay.

And John?

Paul, on the pension side, the -- if you compare the accumulated benefit obligation for both plans to the fair value of plan assets at December 31, '01, in the aggregate, the plans are -- excuse me, '02, in the aggregate, the plans are underfunded by $140 million or so. But that's comprised of Marathon plan being overfuned and the MAP plan being underfunded.

As Ken mentioned, it's the MAP plan for which we'll be making cash contributions for the 2002 plan year in third quarter of 2003. And the forecast of that contribution is about $35 million.

John, can you break out how much is the Marathon overfund and how much is the MAP underfund at this point?

On the qualified plan piece, the Marathon plan again, Paul, on a cumulated benefit obligation basis is -- and you'll see this in the footnote in the K, the when it comes out, but it's looks like about Marathon plan about $70 million overfund you had and the difference then would be attributable to the MAP plans.

Thank you.

Gary, you want to comment on the marketing?

Sure. On marketing, Paul, our main indicater, of course, other than the crack spread and sweet/sour spreads and running about 60 percent or so sour to 40 percent wider grades, the other big keys would be the production or through puts to the refineries vis-a-vis our plan turnarounds and then of course, watching opus every day to see how that stacks up against the spot market.

The other big thing is the absolute price of crude oil, obviously we got this in transit crude effect which you can calculate, too. But just the absolute price.

How about in terms of the tank ray over the past couple of months has been going up drastically. Is that going to cause your material costs to be substantially higher and hit on your earning?

You're right. The tank arrays -- I don't know if they are at all-time highs but they have really have spiked up here recently. It all depends on what happens with that short haul crude oil coming out of Venezuela. If that short haul crude oil comes back on the market, I think it's going to level out the tank array business. But it just all depends, I think, on what happens in Venezuela.

And this is Gary Piper, Paul. Yes, to the extent we don't rover those higher rates it's going to have an effect on our earnings.

Okay. Very good. Thank you.

We'll now take a question from Paul Ting with Salomon Smith Barney.

Good afternoon, gentlemen. Two questions. One on upstream, the other one on downstream. I want to have a better understanding of your non Equatorial Guinea production profile over the last year. You mentioned in the fourth quarter your production is about 416,000 barrels per day on a BOE basis. And if you exclude the Equatorial Guinea portion of that and just compare non Equatorial Guinea production of 4Q '02 versus 4Q '01, there seems to be 40, 30,000 barrels a day of decline, if my math is correct. Can you enlighten me as to what are some of the components of the decline, whether it's divestiture, et cetera?

Excluding Equatorial Guinea, that's about 17,000, so we're around 400,000 barrels a day without Equatorial Guinea in the fourth quarter. And Equatorial Guinea has been running about that, third quarter production was around 385,000 barrels a day. And a lot of that has to did with lifting times between the third quarter and the fourth quarter. We were significantly --

I'm thinking about 4Q versus 4Q.

4Q versus 4Q, I think components of that are probably some declines in primarily in the Gulf of Mexico and if you recall, we have -- we've had some disposition effects that were still residual coming out of some of our Canadian sales than we did that represent around 5 or 7,000 barrels a day off memory. So it's a combination of some natural decline in that base business and disposition.

Okay. Do you expect that decline rate to be maintained at about similar level we have seen previously going forward? We estimate that our base decline without spend is somewhere between 15 and 17 percent. Okay. That makes sense.

Just to be clear, Paul, when we talk about our base decline, because there's a lot of different terminology, what Steve just said to you is you take your proved developed producing reserves and you don't spend any more money on development drilling or anything else and you just play out your current completions, it's a 15 to 17 percent decline.

Okay.

Other people give you a net decline that includes workovers and development drilling and everything else. This is the pure depletion.

Yours is gross, basically?

Yes.

Follow-up question on the downstream. I think you mentioned that your downstream anticipated refinery through put for this quarter is going to be comparable to the first quarter of '02? What are you doing right now, not your projected 1Q '03 but are you -- there is a lot of indication about run cuts, et cetera, et cetera. Are you doing that right now? Are you at about the same as previous year or comparable to the low level that we saw on the fourth quarter?

We are when I was stating about where we think we'll be in Q1, that's very close -- our business plan and forecast is very close to where we were to Q1 '02.

Right.

And that includes any maintenance we have planned turnarounds we have planned. Now, as always, you know, we do not discuss what we are doing today or what our plans are in -- and how that's reflected in the current marketplace. But, Paul, we are, you know, like everybody else, we're watching every day where the crack spreads are and where our hurdle rates are in running our plants, and we will make market changes daily based on the economics in the marketplace.

Given the marketplace economics today, you don't see any need to deviate away from your planned amount right now?

I -- I didn't go that far. (Laughter) as we all know, the market is very difficult today. And there are certain instances today that doesn't make sense to run the next barrel. But I'm saying, you know, where he would stand right now, we believe that we will be close to the first quarter of last year.

Sure. I can appreciate that thank you very much.

Okay.

We'll now take a question from Mark Gilman, First Albany.

Gentlemen, good afternoon. A couple of things by way of clarification. The indicated increase in pension and healthcare expenses, I assume that's going to be spread across the business segments? Or is it going to be included totally in the corporate?

We charge that out.

It gets allocated?

Yes.

Ken, your forecast for 2003 interest expense, does that take into account the $55 million of capitalize interested indicated in the preliminary capital budget?

It is indeed, Mark, net of capitalized interest.

What was that number for 2002, Ken?

Capitalized interest it was something in the neighborhood of $25 million. It was not a big number in this -- in the $25 million range, Mark.

It was $16 million.

Oh, I'm sorry. 16 million. I'm sorry.

Okay.

About 4 million a quarter.

At year end '02, were you either over or underlifted at all with respect to the Bray and Gabon liftings? Or did you come into this year in balance?

Steve?

We were slightly overbalanced around 400,000 barrels a day. We were 400,000 barrels. We were a bit overlifted in Bray and Gabon and we're underlifted in EG. But the balance is around 400,000 barrels.

All right. I wonder if perhaps Phil might elaborate for just a sec on the block 32 well and what encouraging, quote, unquote, means. Have you seen the logs? Anything more substantive that you might say, Phil?

Mark, what we have given you is all the information that we are allowed to share at this point in time. Yes, we have the logs. We are proceeding with testing. And it is encouraging. And that's all we can say, and there will be a formal announcement by the operator when all operations are completed as is traditional in the deepwater Angola.

Okay.

Mark, we had to get approvals to tell you that. So... it's, uhm, you understand the circumstances.

Okay. Yeah. The UK gas volumes in the fourth quarter seemed rather low. Was there anything other demand-related issues that was responsible for that?

No, Mark. It was mostly weather. The early winter at least in the UK was very mild. The temperatures were significantly above normal. So it was market-driven.

Okay. Not -- no field effects or anything along those lines?

No. No field effects. I can tell you in the first quarter, that's turned around and the market's very good right now.

Okay. Is it possible to quantify at all, the Gulf of Mexico storm impact on the fourth quarter US numbers, volumes?

We had about -- I'll give it to you this way, Mark. We had around 3300 barrels of oil equivalent per day impact annualized and about 2/3 of that occurred in the fourth quarter and 1/3 of that in the third quarter. I don't know if that gets you there or not. If I look at the fourth quarter impact on production, normalized to the fourth quarter, it was around 7,000 barrels a day.

Barrels a day or barrel equivalents?

Barrels of equivalent per day. You know, in the storm, Hurricane Lili especially, what was particularly damaging in that was the downstream. We were able to get back to our facilities but we couldn't move production until on shore facilities were up and ready to receive it.

Okay. Just one final one if I could. I notice that in tracking the margins on the marketing side of the business in the downstream, there seems to be some degree of deterioration at least versus the indicators that were tracking suggesting that potentially, there's been some change in pricing strategy? I wonder if one of the MAP guys could perhaps comment on what's going on there and whether in fact you might have become more aggressive in the market place on pricing.

And Mark, you are referring to the SSA margins, I take it?

Yeah, that's right, Ken

Okay, Gary.

Mark, we have not changed our pricing strategy at all in the marketplace. It's just the result of competition. You know, volume-wise, we have seen good increases in volume but a very competitive landscape trying to grab that new market share. But we have not changed our pricing policies.

And no other explanation for what that deterioration we're observing versus indicators might be?

The hyper marketers kind of continue to build out in certain markets. And and I would say that some of the major -- you know, some of the super major marketers have been a bit more aggressive in '02 versus '01 but probably the former, the hypermarket of buildout was probably a bigger effect.

Okay. Guys, thanks a lot. Appreciate it.

At this time we are getting short of time. We have time, I think, for two more questions. So why don't we go ahead and move on.

We'll take a follow-up question from David Wheeler.

Thank you. At one point you talked about the Atwater full belt play as having 600 million barrels of reserve potential for y'all. Given the dry holes at Kansas and Neptune number 4 or the disappointment in Neptune number 4 the question is do you care to give us a revised reserve potential for that area? And secondly, is Neptune big enough to be a commercial standalone development?

David, this is Phil Behrman. I'll answer your question. It's a little too premature to give it a reassessment of the overall resource potential. Nonetheless, we are disappointed in particular on the Kansas well on the results. However, a significant portion of that prospect still remains untested.

I think key to Marathon is to complete drilling on the Kamoto (phonetic) well, look at the results at that well and then we'll make a reassessment in the overall area in terms of Neptune's stand alone capability we'll make that decision at the same time after we get the results of the Kamoto well and the decision-making will be proceeding forward on the Neptune 5 well and we'll make that decision by midyear.

And if the Kamoto well, is there tie back opportunities to nearby platforms if Neptune isn't big enough to do stand alone?

Those are possibilities. We just have to look at the financial attractiveness of those possibilities.

Okay. Thank you.

And our final question today will come from Jay Saunders with Deutsche Banc.

Thank you. Two quick ones. The EIS and the Rockies, if you have looked over that, can you give us a hint of what that might mean for costs in the region? And if it goes through in its current form? Second question, on the Dow stream, can you tell us what the maintenance program -- planned maintenance program for the last three quarters of '03?

Steve, you want to go first on the EIS?

Sure, Jay, first of all, we're still gleaning through the EIS. It's about three volumes stacked on top of each our about 2 1/2-foot-tall. But we've been through it enough to know that there is no material change from what we have seen in the past on the eis, probably most if you wantable to your question is that EIS won't allow direct discharge into the Powder River. They will require more of some retention ponds, that will allow some drainage into the Louvreian so that the water can get back into the natural aquifers but not directly into the river. And that might have some impact on others but as far as Marathon, we have never directly discharged into the Powder in that mode of operation has been pretty much our standard for water handling.

Great, thanks.

Okay. And Jay, on -- we never comment on our maintenance and turnaround schedules prospectively. But I will say that our plan is that we will run at a higher through-put rate '03 versus '02 from a mechanical standpoint and a run-day standpoint but then it's all dependent on, you know, where economics go day to day. But mechanically, we expect to be higher in '03 than '02

Right. Okay. Thank you.

Mm-hm. Okay. That ends our call. I'd like to thank everybody for their participation.

That concludes today's conference call. I'd like to thank all of you for your participation and have a wonderful day. Thank you.