馬拉松石油 (MRO) 2003 Q2 法說會逐字稿

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

Thank you. Good afternoon everyone and I too would like to welcome to the second quarter 2003 earnings teleconference for Marathon Oil Corporation. With me on the call from Marathon Oil is Clarence Cazalot, President and CEO, Phil Behrman, Senior VP of Worldwide Exploration, Steve Hinchman, Senior Vice President of Production Operations, and John Mills, Chief Financial Officer. Also with me from Marathon Ashland Petroleum is Gary Heminger, our President and Garry Peiffer, Senior Vice President of Finance and Information Technology. I'll take about 25 minutes going over the high points of the second quarter and then we'll open the call for questions. About two hours after this call ends these prepared remarks will be placed on the investor relations portion of our website. They 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, 2002, and in subsequent forms 10-K and 10-Q and 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.

Second quarter of 2002 is a good operating to quarter for the upstream business. Downstream had a good operating quarter and financial performance significantly exceeded the first quarter. Unless otherwise noted, all quarterly comparisons will be second quarter 2003, versus the first quarter 2003. Net income for the second quarter was $248 million or 80 cents per share, that compares to first quarter net income of $307 million or 99 cents per share. Net income adjusted for special items was $263 million in the second quarter, or 85 cents per share. A reconciliation of net income adjusted for special items to net income including an explanation of the reasons for using this non-GAAP measure, is included in our press release issued earlier today, announcing second quarter results. This press release is posted on our website under 'press releases' which is located under the new center tab.

Special items in the quarter included an after tax charge of $77 million related to the dissolution of the MKM partnership and $62 million in after tax gains related to the sale of interest in Plan Petroleum, a number of small interests in the Big Horn Basin of Wyoming, and Marathon's share of maps gain on the sale of its convenience store assets in the southeast. There were no special items in the first quarter.

The upstream segment had second quarter operating income of $321 million, or $8.92 per barrel of oil equivalent. In the first quarter it was $535 million, or $14.37 per BOE. This variance is primarily a result of lower commodity prices in the second quarter. Second quarter upstream segment included a negative $32 million charge for derivative activity, first quarter included a negative impact of $53 million. Domestic upstream operations had second quarter operating income of $237 million, or $11.21 per BOE, versus $355 million or $15.96 per BOE in the first quarter.

Our average domestic realized liquids price excluding derivative activity was $24.87 per barrel, down $5.41 from the first quarter. Prompt NYMEX posting average was $28.91 per barrel versus $33.08 per barrel for the first quarter or a decrease of $4.89 per barrel. Our performance below the NYMEX change was primarily a result of widening sweet and sour grades relative to WTI in the second quarter. Our second quarter average domestic gas price of $4.40 per MCF excluding derivative activity was a decrease of 98 cents from the first quarter level of $5.38. The realized price decline reflects the $1.18 decrease in bid week price averages compared to the first quarter and an 18 cent decline in average daily Henry Hub prices over the quarter. This relative decline is tempered by realized prices from Alaska whose gas price is not related to the Henry Hub price movements.

On a barrel of oil equivalent basis, domestic sales revenues averaged $25.64 in the second quarter, compared with $31.33 in the first quarter. Derivative activity was a negative $21 million, or 99 cents per BOE. Domestic expiration expense was $12 million in the quarter, 58 cents per BOE versus, $38 million or $1.70 per BOE in the first quarter. All other domestic costs in the second quarter totaled $13.22 per BOE, up $1.39 versus the first quarter. This variance is primarily a result of two items. First, field level cost increased by $12 million, or 57 cents per BOE due to normal seasonal work over activity. Second, we had lease cancellations and a property impairment in the Gulf of Mexico that totaled $14 million or 66 cents per BOE in the quarter. For financial reporting this is included in DDA. DD&A, I'm sorry. On a going-forward basis, we expect our field level operating cost average about $2.50 per BOE and DD&A to be about $4.70 per BOE including any FAS-144 property impairments for cancelled and impaired unimproved property.

Domestic liquids production came in at 114,000 barrels of liquids per day compared with the first quarter of 118,000 barrels per day. The decrease was primarily a result of natural declines and dispositions. Natural gas production of 707 million cubic feet per day was down 71 million cubic feet per day. Gas production was down primarily due to seasonal variations in Alaska, delays in the Powder River Basin, plant repair and maintenance, dispositions, and natural declines. In the international upstream, segment income was $84 million, or $5.66 per BOE, compared with $180 million or $11.99 per BOE in the first quarter. Our average international liquids price of $23.76 per barrel was down $6.87 sequentially, $1.41 more than the change in dated [Brent] primarily due to lower realized prices on our Russian production included in the second quarter from our acquisition of KMOC. The average international gas price of $3.05 per MCF was down 40 cents due to seasonally lower prices in Europe, and a decline in North American prices that impacts our Canadian production.

On a barrel of oil equivalent basis, sales revenue averaged $21.20 versus $25.07 in the first quarter. Derivative activity in the quarter was a negative $11 million or 74 cents per BOE, primarily attributable to our long-term gas sales contract in the U.K. The first quarter included a negative impact of $6 million or 40 cents per barrel of oil equivalent. Exploration expense of $18 million was up $2 million, to $1.19 per BOE versus $16 million or $1.06 per BOE in the first quarter. All other international costs totaled $14.81 per BOE, up $2.22 per BOE versus the first quarter. All other costs associated with KMOC accounted for $11 million or about 74 cents per BOE of that increase. In addition, repair and maintenance costs of [BRAY] in the second quarter were $5 million or 34 cents per BOE, and the first quarter reflected a one-time $11 million or 73 cent per BOE credit to foreign royalties related to a King Fisher gas royalty settlement in the U.K.

On a going-forward basis, we expect our field level operating cost to average about $3.15 per BOE, and DD&A to average about $5.75 per BOE, again excluding any FAS-144 property impairments or cancelled and impaired unimproved property. Production came in better than expected. International oil liftings of 87,000 barrels of liquids per day were up 19% compared to the first quarter. The increase was a result of higher lifting in [Gabon] and the addition of KMOC, this was partially offset by lower liftings in the U.K. International gas production came in at 458 million cubic feet per day, down 18% over the first quarter. Majority of this variance was in Ireland, where injection into storage occurred in late May and all of June.

Also in the first quarter, we took the opportunity to accelerate gas sales out of the sage system where capacity was available. Since our annual volume through sage remains fixed, reduced volumes in the second quarter reflect a partial rebalancing of those first quarter volumes. The final rebalancing will occur in the third quarter substantially reducing our U.K. production in the third quarter. World wide production averaged 396,000 barrels of oil equivalent per day in the second quarter, which exceeded the guidance given in the first quarter of 380,000 barrels of oil equivalent per day. Russia contributed 8,000 of barrels oil equivalent per day that was not included in the guidance.

Now turning to Marathon's major upstream projects and events during the second quarter. On May 12 Marathon completed the acquisition of KMOC for an aggregate purchase price of $282 million. We are very pleased with the integration of KMOC, current production is about 15,000 barrels per day and is in line with our expectations. The KMOC employees are well-educated and competent and have demonstrated their ability to execute on the operations. Export and domestic crude oil sales are in line with expectations, the domestic crude oil price for June was $7 per barrel, reflecting an overhang of domestic supply caused by late winter ice breakup. Domestic crude oil prices in July have moved up to over $11 per barrel.

Over the last few months, we have had an opportunity to dig into the assets and are more confident in the resource potential and the ability to grow production volumes to 60,000 barrels per day within the next five years. Marathon expects to book approximately 85 million barrels of proved reserves in 2003 with planned capital spending of approximately $40 million for the remainder of 2003. Marathon has also established itself as a prudent and respected operator in Equatorial Guinea, having now drilled 6 out of 8 planned development wells, Marathon can say with confidence that our resource assessment has been confirmed in terms of size and quantity. The project activities have seen a peak manpower level of over 2,600 personnel, with exemplary safety performance. While expansion project activity levels in Equatorial Guinea are at a very high level, our operating personnel have enhanced our base production performance and improved facility uptime. This has resulted in an increase in our base production of over 15% since taking over the project in January of 2002.

Phase 2A will expand our gas cycling and condensate recovery capacity, this phase is 92% complete with expected start-up in the fourth quarter of 2003. Phase 2B, which will expand onshore LPG capacity is 45%, and on schedule for start-up in the fourth quarter of 2004. Upon completion of Phases 2A and 2B, our net production will increase from the current rate of 22,000 barrels of oil equivalent per day, to approximately 50,000 barrels of oils equivalent per day.

Coal bed natural gas product in the Powder River Basin averaged 80 million cubic per day net in the second quarter compared to 87 million cubic feet per day in the first quarter. The 7 million feet per day reduction was a result of drilling and work-over delays due to an unusually wet spring season, continued delays in issuance of permits on federal acreage, and continued decline in our more mature areas that have not been offset by production inclines in new development areas due to longer than anticipated dewatering time. Plan management issued the record of decision for the environmental impact assessments for federal lands in the Powder River Basin on April 30. This long awaited decision will open the way for drilling on federal lands which have been hindered by delays for over a year. As of mid July, these federal permits were only starting to be issued but it is anticipated that the pace will quicken as BLM works through their backlog of applications. As a result of both the weather and federal permitting delays Marathon now anticipates drilling 350 to 400 wells in the Powder River Basin in 2003 compared to our previous estimate of 400 to 500 wells. In addition, for the reasons mentioned above we're adjusting our 2003 production estimate for the Powder River Basin from 100 million cubic feet per day to 85 million cubic feet per day. Our exploration efforts in the second quarter enjoyed continuing success. In fact, four of our last five exploration wells have been discoveries and we are encouraged about three wells that have not been announced.

Turning to Norway, we have completed drilling three wells in the west Heimdal area and are now analyzing development scenarios for Boa, Kneler and a previously discovered Kameleon field. Our intent, along with our partners, is to have a development plan finalized by early 2004. In addition, Marathon will participate in a fourth exploration in Norway, the Norse [Kedrow] operated Klegg prospect where we have a 47% working interest. Klegg is located about five miles north of Heimdal platform and if successful, plans call for an early tie-in to the Heimdal infrastructure. This well should spud in the third quarter. Presence of nearby infrastructure, shallow water depth and shallow drill depth in the Heimdal area should allow Marathon to rapidly grow production in Norway to over 40,000 barrels of oil equivalent per day by 2006. Marathon is operated the leases of the covering Boa, Kneler and Kameleon with a 65% working interest.

Turning to deep water Angola, as previously reported Marathon participated in the [Jindungo] discovery on block 32, it tested at rates of 7,400 and 5,700 barrels of light oil per day from two separate zones. This discovery is located in the eastern portion of the block 32 about 40 miles from the [Girasal] field. Current plans call for one additional exploration or appraisal well in 2003 on block 32, and Marathon has a 30% interest in block 32.

In other deep water activity offshore Angola, Marathon participated in a well on the Saturno prospect on block 31. Saturno well is located your the Plutao discovery, which tested at maximum flow rates of 5,357 barrels of oil per day and results of the Saturno well should be released in the near future upon governmental approval. In addition, Marathon is participating in a well on the [Markay] prospect, which is currently drilling. Markay is located north of Plutao and Saturno and plans call for the Markay well to reach total depth in the third quarter. Marathon has a 10% working interest in block 31. We continue to be encouraged by the drilling results in deep water Angola and see the opportunity to substantially grow our resource base in 2003.

In Equatorial Guinea a plan 3 well exploration program in the vicinity of our world class Alba field commenced with a spudding of a well in the [Pococo] prospect on June 23. The well is located on block D in 238 feet of water and is adjacent to the Alba field. The Pococo 1 well was drilled to a measured depth of 6,110 feet and encountered 185 feet of net dry gas pay. Plans call for this discovery, along with other dry gas discoveries on block D, to be developed along with the Alba field LNG project on Boiko Island. In deep water Nova Scotia we are currently conducting a proprietary 3-D seismic survey over the Cortland and Empire blocks, this data will help us form the basis for our 2004, 2005 drilling programs. Lastly we are currently drilling the Neptune Number 5 appraisal well in Net Water Valley blocks 574 in the Gulf of Mexico, and have just concluded drilling operations on the Persius prospect adjacent to the Petroneus field, results of these wells will be available in the third quarter.

Turning now to downstream results, the RM&T segment income in the second quarter was $253 million, compared with the first quarter income of $67 million. Chicago 321 crack spreads average $6.64 a barrel in the second quarter, up slightly from the $6.54 per barrel in the first quarter. Second quarter 2002 Gulf Coast crack spreads average $3.56 a barrel, compared with $5.70 a barrel in the first quarter.

Our refining and wholesale marketing margin in the second quarter was 7 cents per gallon, versus the first quarter level of 4.1 cents, a gasoline and [desolate] gross margin for our retail business, Speedway Super America, was 12.3 cents per gallon in the second quarter, compared to 11.7 cents per gallon in the first quarter. Refinery runs average 951,000 barrels a day in the second quarter of 2003, or 102% of rated capacity compared with 853,000 barrels a day or 91% of rated capacity in the first quarter, as we're able to maximize runs to meet increased product demand in the summer driving season. The in-transit crude impact was a negative $5 million versus a $15 million positive in the first quarter, resulting in a $20 million negative change sequentially. Refined product sales excluding buy/sells averaged 1.281 million barrels per day in the second quarter, up about 7% from the first quarter, and up about 1% over a year ago. Merchandise sales and margins continue to be a key focus area for Marathon, merchandise sales were up more than 13% from the first quarter to $590 million, margins improved by nearly 6% over the first quarter, producing a total margin of $141 million in the second quarter.

Cardinal Pipeline project will connect MAP's Cattlesburg, Kentucky refinery with the growing Columbus, Ohio, market. As of the beginning of July, we had laid approximately 80% of the 149 miles of 14-inch pipe required to complete this line. Unfortunately, because of all the rain we experienced in the spring and especially in June, we have faced construction delays and increased challenges to construct the line within the very strict permit restrictions. On July 2, the U.S. Army corps of engineers suspended our construction permit, citing environmental compliance issues. We are currently celebrating on an interim action plan that was approved by the U.S. Army corps of engineers on July 5, that will allow work crews to return to the job on July 7 to conduct limited activities. Comprehensive plan is being developed to ensure future compliance that will need to be approved by the U.S. Army corps of engineers before the construction permit is reinstated. We expect to resume construction of the line later this month, and barring any unforeseen delays, the line should be operational around the end of the third quarter.

Other energy related business segment, income was $39 million in the second quarter, of 2003, compared with $17 million in the second quarter of 2002. The increase was primarily the result of natural gas marketing activities, including the mark-to-market valuation changes and associated derivatives. This increase was partially offset by costs associated with emerging integrated gas projects. Second quarter net equity earnings from our EG methanol operations were $11.8 million, resulting from excellent operating performance and strong market pricing on the back of high natural gas prices and higher than forecasted demand. Realized methanol prices for the second quarter averaged $241 a ton, versus $196 per ton for the first quarter of 2003.

Early last year we announced our integrated gas strategy. This is designed to add value to the development of opportunities created by growing appetite for natural gas, particularly in North America where gas production is increasingly constrained. As part of that strategy, we acquired our significant gas resource in Equatorial Guinea. We were also well along with our plans for the Tijuana Regional Energy Center in the Mexican state of Baja, California which will import LNG to meet the needs of northwest Mexico and Southern California. In the second quarter, we made progress on both of these projects. First on May 13, we signed a letter of understanding under which British gas will purchase long-term liquefied natural gas supply from the LNG project proposed by Marathon and its LNG partner, G-Petrol, the national oil company of Equatorial Guinea. Under the terms of the LOU, British Gas would purchase 3.4 million metric tons per year of LNG for a period of 17 years beginning in 2007 when the proposed Equatorial Guinea plant LNG plant is expected to start up. The LNG will be purchased on an FOB Boiko Island basis with pricing linked to the Henry Hub index. Feed stock gas will be primarily sourced from the Marathon-operated offshore Alba field in which the company holds a 63% interest. Provisions of the LOU are subject to a definitive purchase and sale agreement expected to be concluded by the end of 2003.

On May 27, Marathon, the government of Equatorial Guinea, and GE Petrol announced they signed a heads-up agreement on a package of fiscal terms and conditions for the development of LNG project on Boiko Island. This agreement on the terms and conditions of the Equatorial Guinea LNG project, along with the recently announced LNG off take letter of understanding with BG Group create the framework necessary for us to move forward with a strategically important project, we are on pace to announce project sanction in the first quarter of 2004. In Mexico, Marathon and our joint development partners announced on May 8 that Mexico's energy regulatory commission or CRE, had awarded a gas storage permit for the construction and operation of a liquefied natural gas storage facility to be located near Tijuana/Baja, California/Mexico. Marathon's permit submission, it's the first of its kind accepted and approved by the Mexican government. This gas storage permit gives Marathon and its partners the necessary federal approval to off-load LNG and to re-gasify LNG at the proposed complex, supply clean-burning natural gas to regional markets and is an important milestone in the development of the Tijuana Regional Energy Center. The Marathon-led consortium is now proceeding with additional regulatory reviews and permits as required by federal and local authorities in Mexico. We also announced another significant step on this project today with the signing of a memorandum of understanding for LNG supply from Indonesia.

Moving back to financial results, total segment income in the second quarter was $613 million, flat with the first quarter. Upstream was down 40% while the downstream was up 278%. In the unallocated category, administrative expense was $49 million in the second quarter, compared with a first quarter total of $44 million. As a result of lower return on plan assets and higher than projected payouts of variable pay plans, pension expense is projected to increase $8 million for Marathon this year, and $11 million at MAP. [Opeb] related charges are projected to increase $3 million at Marathon and $1 million at MAP. Both of these increases are in addition to the changes we announced in December. The net pretax impact in the second quarter reflecting these revisions is $9 million, after adjusting for Ashland's 38% minority interest. We now estimate the year on year pension increases to be $26 million for the Marathon plan, and $46 million for the MAP plan. The net pretax impact of Marathon for the full year 2003 over 2002, after adjusting for Ashland's minority interest, is $54 million. For Opeb we now estimate year-over-year increases of $10 million for Marathon and $11 million for MAP, the net pretax impact on Marathon full year 2003 over 2002 after adjusting for Ashland's minority interest is $17 million.

Net interest and other financial costs were $45 million in the second quarter, compared to $65 million in the first quarter. The difference is a result of foreign currency gains of $15 million in the current quarter compared to a loss of $2 million in the first quarter. Actual net interest expense in the current quarter therefore was $3 million less than the first quarter. Capitalized interest was $12 million in the second quarter, versus $6 million in the first quarter. Preliminary cash adjusted debt went up by $150 million during second quarter to $4 billion. The preliminary cash adjusted debt to total capital ratio at June 30, 2003, is 42.4%, up slightly from 42.2% at March 31, reflecting our acquisition of KMOC. Please note that these ratios and total debt include approximately $546 million of debt that is serviced by U.S. Steel. As part of our commitment to maintain financial discipline and high grade our asset portfolio, we announced an asset rationalization program in February to divest of certain upstream and downstream assets determined to be non-core to Marathon's strategy. In May, MAP closed its sale of 190 SSA retail outlets in the southeastern United States Sunoco for approximately $140 million plus store inventory.

This is a continuation of MAP's strategy to focus its company operated business in the Midwest where the company can leverage its critical mass of locations and capitalize on its pipeline and distribution networks. In May, Marathon sold a Burlington Resources its interest in Clam Petroleum for $100 million which included $15 million of working capital. Clam has production from 25 gas fields located offshore the Netherlands, and provided net sales of 25 million cubic feet per day of natural gas in 2002 to Marathon. In the second quarter, we closed the sale of a number of small interests in the Big Horn Basin for $40 million. These properties had net production of 1,700 barrels per day at the time of the sale. And on June 20, we announced a dissolution and distribution agreement with Kinder Morgan Energy Partners to dissolve MKM Partners LP, which has oil and gas production operations in the Permian Basin of Texas. Marathon holds an 85% equity interest in the MKM partnership. Prior to the dissolution of the partnership, MKM Partners, Marathon and Kinder Morgan, signed the following agreements related to other assets in the Permian basin. A purchase and sale agreement under which Kinder Morgan will acquire MKM Partners 12.75% interest in the [Sack Rock] field, a letter agreement under which Kinder Morgan will acquire Marathon's carbon dioxide transportation company, which owns as 65% interest in the Pecos carbon dioxide CO2 pipeline company. And an agreement under which Marathon and Kinder Morgan will explore the potential sale of Marathon's interest in the Yates field to Kinder Morgan. As a result of the dissolution of the partnership agreement Marathon took an after tax charge of $77 million to second quarter earnings.

And finally, we solicited offers for the company's interest in western Canada through a recently completed data room process, we are currently evaluating several offers. Marathon estimates asset sales are likely to exceed $700 million in 2003. Proceeds will be used to strengthen our balance sheet and invest in select business opportunities like KMOC, consistent with Marathon's strategy to create superior long-term value growth. Marathon's pretax income for the second quarter reflecting just Marathon's share of downstream income was $392 million, the tax provision was $144 million, for an effective tax rate of 36.7%. For all of 2003, we still project an effective tax rate of approximately 37%. Second quarter preliminary cash flow from operations was $472 million, preliminary cash flow from operations before working capital changes was $787 million. Capital spending was $475 million in the second quarter.

Finally, I want to make a few observations about the third quarter and full-year 2003. For 2003, we have hedged a significant portion of our anticipated oil and gas production utilizing zero cost collars. We have also sold Ford a part of our anticipated oil product for 2003 and part of our anticipated gas production for 2004. In the second quarter, we hedged an additional 30 million cubic feet a day, for the April to December 2004 period with a floor price of $4.25 and a cap of $7.15. Natural gas hedges cover approximately 285 million cubic feet per day for the remainder of 2003, or about 24% of anticipated production. And 80 million cubic feet a day for 2004, about 7% of anticipated production. Oil hedges for the remainder of 2003 average approximately 61,000 barrels per day, or approximately 31% of anticipated production. The detailed volumes and prices related to these hedges have been disclosed in previous calls and are also included in our first quarter 10-Q on page 25. So I will not repeat them on this call.

On the domestic upstream side, we expect third quarter liquids production to be about 107,000 barrels of liquids per day, taking into consideration 4,000 barrels per day of completed dispositions. Gas production should come in at about 690 million cubic feet per day taking into consideration 6 million cubic feet per day of completed dispositions and domestic exploration expenses anticipated to be about $20 to $40 million. On the international upstream side, liquids production in the third quarter should be about 84,000 barrels of liquids a day, including 15,000-barrels a day from Russia. We expect gas production to be about 360 million cubic feet per day, considering a 24 million cubic feet per day impact as a result of the clam disposition, and final rebalancing of gas production in the U.K. International exploration expense is anticipated to be about $20 to $40 million.

On a barrel of oil equivalent basis, we expect third quarter worldwide production, therefore, to be down sequentially to about 366,000 barrels of oil equivalent per day, which considers 9,000 barrels a day for disposition, and 15,000 barrels a day for the KMOC acquisition. Taking into consideration the acquisitions and dispositions made to date, but excluding the impact of any additional acquisitions or dispositions of producing properties, Marathon estimates its 2003 production will average approximately 395,000 barrels of oil equivalent per day. Downstream we believe that we will be moderate growth and light product sales in both the U.S. as well as in our major market, pad 2. As you know, total light product inventories have fallen below the five-year averages, mainly because of the significant draw of [dissolute] stocks to the about the same level as the summer of 2000. We are cautiously optimistic we will have a relatively good motor fuel market for the remainder of the summer. As for the other energy income line we expect income to be about $20 million, administrative costs should total about $48 million, net interest and other financial costs are expected to be approximately $51 million for the quarter, and for all of 2003, we project net interest and other financial costs of $211 million.

Before opening the call to questions I want to make a few final points. I began the call saying we had a good operating quarter. There were, however, a number of unusual items that had a negative impact on our financial results. Lease write-offs and a property impairment in the Gulf of Mexico totaled nearly $14 million. Pension and post-retirement benefit obligations of both Marathon and MAP increased, and net impact to Marathon in the quarter was $9 million. We also had a mark-to-market loss of $10 million related to our long-term gas sales contract in the U.K., and finally, there were a number of small items, all less that $4 million each that totaled $12 million, such as stock appreciation rights, damages from a fire on a supply boat in EG and a cost recovery settlement in Cabone. Taken together, these items add up to $45 million pretax and none were predictable going into the quarter. Marathon's senior leadership has been fundamentally repositioning the company since 2000. About six months ago we started a business transformation effort and accelerated step in our plan to deliver value to our shareholders. Over the course of the last several months, we have critically examined our cost structure, processes, and the ability to focus and execute our strategy with speed and efficiency. The assessment phase of this project is nearing completion, and we intend to implement a series of enhancements over the course of the next 10 to 12 months with most of the implementation to occur yet this year.

Lastly, I want to remind everybody that Marathon will be holding an analyst meeting on November 4 in New York City. Invitations and details will be sent out soon. Now I'd like to open the call up to questions and remind all of you to please identify yourself and your firm affiliation for the benefit of those who are listening in. Thank you.

Thank you, sir. Today's question and answer session will be conducted electronically. If you'd like to queue up for a question, press "star 1" on your touchtone telephone. Once again, the star key followed by the digit one for a question. If you're on a speaker phone please be sure the mute button is off so we can reach your signal. The first question is from David Wheeler with J.P. Morgan.

A couple of questions for you on costs. You mentioned in the U.S. field level costs at $2.50 a barrel going forward. That compares to about $2.20 a barrel over the past three years. Did you address what's going on there?

Steve, you want to talk about that?

Yeah, Dave, most of that really is the continuing decline in the Gulf of Mexico production volumes which typically have [inaudible] cost on the order of less than $1 per barrel, and declining production in general in the U.S. business against a fixed cost structure. So that really is the principal reasons for the increase in field level control.

Okay. And on the international front, Ken, I didn't quite get the guidance there. Did you 315 or 350 for field level costs?

It's 315.

Okay. And that's coming now because Russia is lower cost?

Russia is lower cost, David, and so is the barrels coming out of EG as well.

Right. And one last question for you on the Powder River gas, this kind of ramped down in expectations for '03, we've obviously got a growing profile here going out through '04 and '05 as well. Should we see a similar type of basically delay in the ramp-up in those years as well? Or is there any kind of catch-up period here?

I think there will be an impact out in 2004 as well and we're working through that. David, what's really happening here is that our mature areas are declining, and as we stepped out deeper into the basin, our response times for that even though they're growing are currently just offsetting. As that kind of that balance in mature wells and the new development wells begins to pull more in the balance of the new development, we'll begin to see the ramp-up. We'll expect this year will be relatively flat and next year we'll see an increasing production profile. But at this time I'm still trying to get my arms around that profile for next year. And we'll be putting that out later this year.

Okay. Thanks, Steve.

We'll take our next question from Mark Flannery with Credit Suisse First Boston.

I wonder if you could characterize for us the general parameters of the KMOC production. David just mentioned the lower costs there and you have mentioned the lower realizations perhaps you could sum it up for us and give us an idea of expected changes in volumes for the rest of the year and for next year, if there are any?

The production volumes are pretty much on expectations, in fact, as we have looked at the operations, our confidence is higher in our ability to achieve the growth that we presented earlier this year. During the second quarter, and principally really the second half of May and June, our production volumes, exports were around 30, 35% and the domestic was 60 to 65% of the volumes again, pretty much along the expectations that we had set out. And as Ken mentioned in his discussion, the biggest factor in Russia was lower domestic price as a result of a supply overhang due to a longer winter. All in all, Russia looks very good to us and is meeting or exceeding our expectations.

And will you be updating guidance for expectations for Russia in November, I assume?

Yes. The long-term output but again probably at this point the guidance we gave on our web cast earlier in the year is still, I think, in line.

Okay. Thank you very much.

We'll take our next question from Steve Pfeifer with Merrill Lynch.

You're to be commended on the detail in the packet that you sent out, I almost feel guilty asking you this really detailed question on page 6. You show on the international E&P all the unit cost figures there. Going 1Q to 2Q, total costs went from 1365 to 16 with the biggest change being the "other. And I want to get a sense for what the total number is that you expect. I think you referenced that you had higher non-repeatable cost as a result of the KMOC. I'm just trying to get a sense for kind of the run rate for the total there.

We're still here, we're flipping through pages.

We're trying to find the investor packet that you have, Steve. You're talking the international side, aren't you, Steve?

Exactly, international E&P.

Correct. Why don't we go on to the next question and we'll come back on that.

If I could, just throwing in there, I'm trying to get a sense for if there were any impacts of the currencies that dollar weakened, how that might have impacted that number as well? Unit costs and international E&P.

Steve, why don't we get back to you on that, we're still looking at that number.

Steve, on the international, let's go to the cost side for a minute, we talked about field level control being up, we had work-over expense for $5 million, we talked about in Bray. One of the big swings in the 'other' category, you have to remember we had an $11 million royalty adjustment in the first quarter which makes the difference between the first quarter and second quarter. That's over 70 cents a barrel right there. Those are the two largest contributing factors there.

Okay. Thanks a lot.

Next we'll go to Jay Saunders at Deutsche Bank.

Thanks. Few questions, couple of them are pretty quick. On KMOC, you said 85 million barrels, I think, this year I'm wondering how much of the rest of the 250 will be booked next year? And second question, on the U.K., gas volumes and realization, I assume there was a drop there for seasonal reasons with the winter over, but I'm wondering with the inter-connector being up and down, what percentage of sales are term and what are spot? And finally, the last one. On the Powder River Basin, I was under the impression that you guys weren't producing from any federal lands. Can you break down the portion of the downgrade that came from response times and permit problems?

Let me see if I can -- I'll take these ask you ask them. On KMOC, again we're very confident about being able to book what we've set out the 85 million in 2003. Again, we remain very confident about the overall resource base. But it would be premature for me at this time to give a potential reserve booking in 2004. At least to say that we continue to look at the properties. We actually see greater upside than what we presented during the web cast. So we see perhaps even more potential than what we talked with you before about.

Okay.

Regarding the U.K. gas volumes, most of our Q1 to Q2 variance on gas in the U.K. was a result of turning our [kintal] head production into storage rather than sales. That made up over 60 million of the variance. The rest of it really was a starting of balancing. If you recall, we got significantly -- we took advantage of high prices in the first quarter, and sage capacity that was available and we sold the majority of our gas really in the first quarter and the first two months of the second quarter. And we're currently in a process of balancing. So those two items really are the biggest deviations from second quarter to the first quarter. And moving on into the third quarter, most all of that will be primarily balancing. And then we start a new gas year in the U.K. Bray beginning in October. So again we can crank up the volumes there, we have the capacity to do that, and take advantage of the winter price season at that time.

Okay.

I don't know off the top of my head, I don't know the split between long-term contracts and spot sales. I apologize, I just don't have that information at my fingertips at this time. And regarding the Powder, I'm trying to remember your questions, so if I --

It was just on the permits, the federal permits.

Yes. I was just wanted to make sure I didn't miss something in the U.K. On the Powder, there's little of our reduction in rate for this year. There's really little that's impacted specifically by federal permits. We have seen some permit delays in getting APDs for wells and getting our water discharge permits, perhaps somewhat associated with the increased federal permitting going on at this time with the approval of the EIS, but as we've said before in 2003, and for the majority of 2004, our drilling program wasn't absolutely dependent upon federal permits. So the permitting was not a big issue, it played a relatively small part, most of them, again, is really about higher decline in our mature development areas, and delayed ramp-ups principally due to longer dewatering times in our new development area. And again we remain very confident on the resource base in the Powder River.

For those wells that have dewatered, can you give us a feel for what the response looks like after that, the volumes which you'd expect after the water's gone?

The big problem has been the time to dewater and the time to first gas, once we start ramping up on gas we are approaching the peak rate that we had anticipated in the new development areas. And just taking a little longer to get the peak rate and longer to get the first gas.

All right. Thank you.

Jay, this is Clarence, just to give you a little more insight on the KMOC question, we had shown a slide when we had the KMOC presentation on future development capital and if you look back at that it showed 2004 about $90 million of capital, '05 was about $120 million and '06 was about $80 million. I think with that you can see that the remaining 165 million barrels would for the most part be booked '04 - '05 time frame with some carry-over into '06. I think come November 4 at our detailed analyst meeting we will be able to give you greater detail around that.

Okay, right. Thank you.

Our next question comes from Mark Gilman with First Albany.

Guys, good afternoon. A couple of things. Any impact on the U.S. DD&A rate of the dissolution of the MKM partnership?

No. No, there shouldn't be any DD&A rate impact.

Okay.

Very modest.

And the lifting position in Gabon and the U.K. as of June 30, if you could, please, over-lifted, under-lifted, in balance?

In what countries?

Gabon and the U.K.

In the U.K., through the year, we're about 337,000 barrels under-lifted but we entered the year in an over-lift position. So our net lift position would be just slightly over-lifted at 160,000 barrels in the U.K. In Gabon for the year, we're 437,000 barrels under-lifted, we entered the year at a slight positive over-lift of 100,000, so we're roughly about 330,000 barrels under-lifted as of June 30, 2003.

Okay. Can we quantify the mark-to-market impact in the other energy and related business segment, Ken?

Yes, Mark, it was the mark-to-market impact was eight million and they also had $11 million of realized gains from hedging activity that backs up purchase for resale activity.

Okay. Could Phil comment at all on whether the Pococo well was stratographically and otherwise in line with expectations?

Mark, the well was stratographically in line with expectations, net pay pretty much met expectations.

If you would, just one final one on the MAP side. Refresh my memory to the specifics at Cattlesburg and what units are being revamped or replaced?

We are taking the RCC unit and we're changing that around to make it a much more efficient FCC unit. So it was a resid-cracker before and we're changing it all around, going to make it a food catalytic cracker and some of the big changes in that will be a reduction in operating expenses and efficiencies on running the unit. Some other key elements are expanding the vacuum distillation capacity to match the crude capacity so we can enhance some of the crude preheat processes. We have expanded our gas/oil hydro-treating capacity in order to match the new FCC capacity, and we're going to convert the atmospheric residue cat cracker from 45,000 barrels a day to 95,000 barrels a day. And in so doing, we're retiring an existing 58,000-barrel a day gas/oil cat cracker.

That's great, thank you.

You're welcome.

I would like to remind everyone that it is star one for a question at this time. Our next question comes from Steve Enger with Petrie Parkman.

Hi guys.

Hi, Steve.

Steve, I just wanted to clarify in the Powder River Basin, have you guys actually received some new permits for federal land?

I don't believe we've actually received them, we put permits in, but as you know, the BLM is still understaffed and so there's a flood of permits and it takes time to get them through the mix. And so we've made applications and I don't recall off the top of my head just exactly how many. But we have not officially received any permits returned today.

Still some concerns about drainage into Montana, I guess?

Well, I mean, the EIS was approved in Montana, but Montana is, I'll say, a bit more challenging overall.

Yeah. And then I wanted to clarify, I think you mentioned on some of the mature wells that you're seeing somewhat higher rates of decline? Did I hear that correctly?

You know, it's a matter of, they're not higher than what we expected with the guidance we had before, as much as it is really just the mix. We have about an equal number of wells on decline as we have wells trying to incline and dewater. So it tends to flatten out the profile until we can turn our mix of mature versus immature production around a bit.

Right. So no implications on per-well recoveries?

No, per-well recoveries are good, reserves are good and we feel confident about the potential resource that also exist, it's just lower than we expected.

Okay, great. Thanks.

Our next question comes from Paul Cheng with Lehman Brothers.

Hi guys. Ken, I just want to clarify, you say that the mark-to- market related to the U.K. gas pipeline is $8 million or $11 million?

No, it was $10 million.

$10 million.

In the U.K., you're talking the U.K. gas contract?

That's correct.

$10 million.

The $10 million charges, is that being recorded in international E&P?

Yes it is, Paul.

What's the $8 million, in the other energy?

They have derivative activity around all their gas sales activity, some of it gets realized and some of it gets mark-to-market.

The $8 million is unrealized and $11 million is realized?

The $11 is realized and $8 --

So all together is $19 million?

That's why it was up so much, almost twice what it is in a normal quarter.

That's perfect. Also maybe this one is going to be for Phil Behrman. Gulf of Mexico, I think you took a pause several months ago in looking at the position and see that, why you do not have a better success over there, at this point, I don't know if you're already finished that evaluation, and what is the role of dewater Gulf of Mexico going to be for the remaining in your overall exploration program going forward? And then lastly, is that wondering if you guys have any changes to your capital spending program, given the very strong commodity prices for this year?

Paul, this is Clarence, no change to the capital spending program for this year. Phil will answer your Gulf of Mexico question.

At this point in time, we're doing a technical evaluation assessing what lessons learned we have with all of the exploration results in the deep water Gulf of Mexico. That being said, our focus is not only on evaluating our lessons learned but we have the [Ozona] discovery and the Neptune discovery and we'll continue to move towards a potential commercialization of those projects at the same time. It will probably take us somewhere around 12 months to finish our Gulf of Mexico technical work and make a decision as to how to proceed with exploration in the Gulf of Mexico.

I think part of it depends as well on some of the offset drilling that is going to take place, the eastern Gulf of Mexico, for example, where we picked up leases and sale 181 on prospects. We think there's an ability here to sort of watch some of the other industry drilling without putting the risk dollars down ourselves.

I see. Excellent. Thank you.

Our next question comes from Greg Kuczynski with Robert W. Baird.

I had an additional question about the other energy. Is there any additional upside going forward based on the ethanol in Equatorial Guinea or was that upside in the second quarter all the mark-to-market?

No, actually the methanol earnings first quarter over second quarter were very, very close, all the upside between the first quarter and the second quarter in OERB was a result of the gas marketing activities.

And so looking forward 15 to 25 is a safe range?

Yes, 20 is the guidance we've given out on a going-forward basis.

Okay, great. Thank you.

And we'll go back to David Wheeler with J.P. Morgan.

On Baja LNG, you mentioned the government, or rather the regulator approval. You guys are now waiting land use permit, that's supposed to come in right around now, right? And what's the timing around the environmental permit?

Well, I think we're working the two pretty simultaneously, David. With respect to both land use and I put that as the highest priority one for us initially followed by the environmental permit. And of course the third element that we're working simultaneously is the LNG supply. So those are the three components that to come together and obviously we're pushing to have the permitting done by the end of this year and have that come together at the same time with LNG supply, be it from Indonesia as per the MOU we announced today, or perhaps Latin American Supplies.

Okay, and in terms of the gas price I know it was your desire to push the gas risk onto the supplier. In terms of the discussions with the Indonesians. Are you going to be able to do that, do you think?

Of as much as those discussions are still underway I just as soon not discuss specific negotiations. But I do think that in the changing word, Steve Louden has discussed with you, in the changing world of LNG I certainly think the pricing risk in general is moving from the market to the producer of the LNG.

Okay. Fair enough. Thanks, Clarence.

Okay.

As a reminder, it is star one for a question at this time. Next to William Ferer (ph) with WH Reids and Company

Good afternoon and thank you for a very thorough exposition of the company. I have just, I guess two broader questions. One relates to the acknowledgement of additional asset sale opportunities, but by the same token, are other people's asset sales coming up on your radar screen for potential acquisition, separately, given the very full capital requirements that you have in front of you for the next few years? Do you have an appetite to participate in future Saudi ventures that might be available? Thank you very much.

I guess two comments with respect to sales and acquisitions. I think we are taking advantage of what is a very strong market today for selling properties. And we're doing that at a time we believe well in advance of what is going to be a multitude of properties being brought to the market later this year and into next year. At the same time, we are open to additional opportunities and we look at many things, but I would have to say that in general, much of the stuff that we see being brought to market is not what we would be interested in. Again, you look at the kinds of acquisition we made, we look for opportunities that are largely underdeveloped where we can buy at a reasonable price, and then achieve the growth and create value ourselves. Rather than buying a fairly mature developed property and sort of bet on the price curve. I'd say with respect to Saudi Arabia, we are open to opportunities there, we had representatives at the London meeting two days ago that Minister Ali Manini (ph) had, we remain open to those opportunities, but again, I think as we've said before in our previous involvement in core venture too, they'll have to stack up against other things we see around the world.

Clarence, since your last foray into Saudi Arabia participation, your world changed perhaps more definitively, that is, you brought some larger projects from the concept stage to the reality stage. And does that financially preclude you from participating in future Saudi opportunities, at least to the extent that you might have before? Just trying to get size for scope.

No, I don't think so. I think it would, again, depends upon the kind of project and the level of interest that we would take in it. I think if you look at what's happened in Saudi Arabia, some of the projects originally contemplated in the three core ventures that were fully integrated from exploration to development to petro chemicals, to power generation to desalinization, those are pretty clear they're not going to work. I think what's being talked about over there now are upstream projects. And certainly I think if they fit our criteria and stacked up against other things, we would have the capacity to do it.

Thanks very much.

We have no further questions in queue at this time so I'd like to turn the conference back over to Mr. Matheny for any additional or closing remarks.

I'd just like to thank everybody for participating. That's all. Good-bye.

This does conclude today's conference call and you may now disconnect. We do appreciate your participation.