馬拉松石油 (MRO) 2002 Q2 法說會逐字稿

Thank you for holding, ladies and gentlemen, and welcome to the Marathon Oil Corporation Q2 earnings conference call. At this time, all lines are on a listen-only mode. There will be an opportunity to ask questions at the end of today's conference and instructions for asking questions will be given at that time. I thank you for your attention and turn the conference over to our host, Mr. Ken Matheny.

Thank you, and good morning, everybody. I, too, would like to welcome you to the second quarter, 2002, earnings review teleconference of Marathon Oil Corporation. Available with me on this call today from Marathon Oil are Philip Behrman, Senior Vice President of Worldwide Exploration, Steve Lauden, Senior Vice President of Business Development and John Mills, Chief Financial Officer. Also with me from Marathon Ashland and Petroleum are Gary Heminger, President, and Gary Piper, Senior Vice President of Finance and Information Technology. As usual, I will cover the high points of Marathon's second quarter and we'll open the line up for questions.

Before I start, I would like to make you aware of a few improvements we made. When you go to our website and access our investor relations package, you will see we reformatted it to provide additional production costs data and production by company we think will be helpful by all of you, and continuing the trend from last quarter, our earnings release contains average sales prices, excluding and including the derivative gains and losses. Also, shortly after this call ends, we will place these prepared remarks on the investor's 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 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 10K for the year end of December 31, 2001. And in subsequent forms, 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 was a good operating and financial quarter for Marathon's upstream business. The downstream had a good operating quarter and the financial performance was significantly improved over the first quarter as remaining and marketing margins improved significantly from the low levels experienced in the first quarter. Net income adjusted for special items as $193 million or 62 cents per share. This compares to a -- adjusted net income of $27 million or 9 cents per share in the first quarter. Special items in the second quarter totaled a negative $25 million after-tax and consisted of $26 million in losses on a yearly retirement of death and a $1 million positive inventory market valuation reserve adjustment. Looking at the upstream segment, second quarter 2002 operating income totaled $262 million or $6.79 per DOE. In the first quarter, that was $165 million or $4.32 for DOE.

Focusing on our domestic upstream operations, second quarter operating income was $189 million or $8.32 per BOE, versus $82 million or $3.48 for DOE in the first quarter. The increased in income is a result of higher prices, reduced expiration expanse, and derivative gains partially offset by lower volumes. Our average domestic realized liquids price was $22.49 a barrel, up $4.37 from the first quarter, compared to the $4.64 increase in the posting average. Our domestic crude oil realizations were in line with the WTI change, while NGL prices underperformed WTI in the third quarter due to weak seasonal demand.

Our second quarter average domestic gas price of $2.99 per million per MCF, increased 64 cents from the first quarter, compared to the 93 cents increase in the average. Average bid week pricing improved by $1.04 per MCF over the first quarter. Our price realizations lagged the movement reflecting Alaskan gas pricing as well as a significant widening of basis differentials for rocky mountain gas production during the quarter. On a barrel of oil equipment basis, domestic revenue averaged $20.26 in the second quarter compared with $16.11 in the first quarter. The market -- pardon me, the derivatives related to hedges and mark-to market impact in the second quarter was a positive $24 million or $1.06 per BOE, primarily reflecting gains on a powered river gains activity. Domestic expiration expense was down to $32 million, or $1.40 per BOE, compared to $49 million or $2.09 per BOE in the first quarter. All other course costs -- all other costs in the second quarter totaled $11.50 per BOE, up $1.42 versus the first quarter.

The increase is due to workovers in the gulf of Mexico and Alaska and reallocation of administrative costs and additional transportation costs related to the Power River Basin. Domestics liquid product came in at 127,000 barrels of liquids per day, down 4,000 a day versus the first quarter, and natural gas production 734 million cubic feet a day was down 53 million cubic feet a day for seasonal reasons primarily in Alaska. On a BOE basis, overall first quarter daily domestic production was down 12,000 barrels of oil equivalent per day compared with the first quarter average, and 5,000 barrels a day above the guidance we gave in April. Turning to the international upstream sector, segment income was $73 million or $4.60 of BOE, compared with $83 million or $5.69 of BOE in the first quarter. Our average foreign liquids price of $23.59 a barrel was up $322 sequentially, reflecting an improvement in the crude market, serving as a pricing reference for much of our international production. The average gas price of $2.35 per MCF was down 15 cents from the first quarter, reflecting seasonal price movements in Europe.

On a BOE basis, revenue averaged $19.19 versus $17.35 in the first quarter. Expiration expense of $12 million was up $4 million compared to the first quarter to 76 cents per BOE, derivative losses were $4 million or 27 cents per BOE. These losses were entirely related to two long-term gas sales contracts in the UK that we reviewed in the first quarter. All other costs total $14.39 per BOE, up $1.16 or about $35 million in absolute terms versus the first quarter. The increase is primarily due to an impairment of property in Canada, and DDNA expense was also higher because of a change of production mix, predominantly in the UK north sea.

International liftings for the second quarter came in greater than expected at 95.5 thousand barrels of liquids a day, 20,000 barrels a day higher compared to the first quarter. That primarily reflects high liftings in the UK which corrected an underlifting position from the first quarter. Gas production came in at 474 million cubic feet per day, down 48 million cubic feet per day in the first quarter. Lower gas sales were the result of additional [INAUDIBLE] in Ireland, combined with reduced seasonal demand of the UK and Ireland, partially offset by the commencement of gas delivery during the second quarter. The reduction is also the result of unexpected downtime at the methanol plant in equatorial Guinea.

From the first quarter to the second quarter, worldwide production was level at 424,000 barrels of oil equivalent per day, up 14,000 barrels of oil equivalent per day versus the guidance we gave in April. Looking at Marathon's domestic development projects, [PETRONEUK] averaged a net 22,000 barrels of liquids a day, and 36 million cubic feet of gas per day in the second quarter, leveled about 34% respectively versus the first quarter. For the full year, [PETRONEUS] should average 27,000 barrel of oil equivalent per day for all of 2002. Production from the Powder River Basin unit is currently averaging 85 million cubic feet per day net, compared to the first quarter average of 59 million cubic feet per day net. As a result of the trade with XTO Energy for the recently acquired CMS Energy Properties in the Powder River Basin -- Marathon added approximately 24 million cubic feet per day of production. This traded, I remind you, closed on May 1st.

We continue to be encouraged by the performance of our [Avlada] and House Creek areas which have increased in production by 11 million cubic feet a day gross this year. These areas were the main focus of our 2001 capital program, and the House Creek area alone, we're now producing approximately five million cubic feet a day gross from the big George Coal, which continues to ramp up. The total resource that will be developed from our current holdings of 1.6 trillion cubic feet will have an average finding and development cost expected to be in the $1 per BOE range.

In addition to our Powder River Gas Hedging Program, which I'll detail later in my remarks, Marathon has acquired additional 125 million cubic feet a day of long-term gas transportation capacity for transport of gas out of rocky mountain region into more attractively priced midcontinent gas market hubs. The basis differential for local sales of gas into the Rockies market has widened to $1.50 or more below the Henry hub prices, primarily in transportation constraints for moving gas out of the Rockies. The acquisition of this additional firm transportation provides protection against such wide negative local differentials.

In summary, Marathon is very well positioned in the Powder River Basin. Our gas hedging position combined with our long term gas transportation capacity provides us the opportunity to receive full price for our gas. We also have all permits necessary to complete our 2002 and 2003 drilling program. We're not pulling back, we're aggressively moving forward. The first production well at Camden Hills holds a record for the deepest water depth completion in more than 7200 feet of water. The start of production will be delayed until early in the fourth quarter due to slow progress on laying the Canyon Express pipeline system that will serve Camden Hills and two other fields. Plateau production of more than 45 million cubic feet a day net from Camden Hills probably won't be reached until the second quarter of next year. The Valla field in Norway, a timeback to the [Heimdel] platform began production on June 23rd, two weeks ahead of schedule.

The well hasn't reached fully stable production due to a combination of facility problems on the [Heimdel] platform that has only allowed the well to be produced intermittently and an apparent buildup of liquids in the reservoirs near the well. Net production from Valla is now expected to average about 4.8 million cubic feet a day of gas, and 850 barrels per condensate for the year. The UK Atlantic margin [INAUDIBLE] developments continue to exceed expectations following commencement of East Point Haven oil production last September. Total Point Haven field liftings for the second quarter, 2002, was just over 32,300 net barrels of liquids per day. Gas deliveries began in the second quarter and averaged 11,300 million cubic feet per day, and net production for all of 2002 is projected to be approximately 31,800 barrel equivalent per day.

On January 3rd, Marathon completed the acquisition of interests in equatorial Guinea West Africa from CMS, for total cash consideration including working capital, just over $1 billion. On June 26th, we increased our interest in equatorial Guinea through the acquisition of Globex energy for $148 million. These acquisitions established a profitable new core of business area for Marathon, and is expected to add more than 18,000 barrel of oil a day to our 2002 production. Following the expected approval of expansion projects later this year, Marathon's equatorial Guinea net reserves are anticipated a 300 million barrel of oil equivalent. The full cycle finding and development cost of these reserves, including the liquefied petroleum processing plant and its associated expansion is estimated to be $4.20 per BOE. Further more, the upside potential presents an opportunity for Marathon to become a significant regional player in West Africa. We regard this acquisition as an important step in growing in integrated gas business for the application of gas commercialization technologies and to deliver value-added products for local, U.S., and European markets.

An aggressive plan to boost gas production and expand the common state production has been approved by the partners and submitted to the government, and we expect approval within 60 days. By the third quarter of next year, this expansion is expected to boost gas production from 250 million cubic feet a day to 800 million cubic feet a day, and increased condensate production such the condensate and LPG exports total nearly 50,000 barrels a day of liquids gross.

We're also nearing completion of a plan to increase LPG production. This expansion should be commissioned in mid 2004 and condensate and LPG exports will increase to 70,000 gross barrels of liquids per day. The design work has also begun in a process for monetizing Marathon's 1.7 trillion cubic feet of reinjected drygas from Alba, as well as other stranded and player gas located within 100 kilometers of [Beoka] Island. On February 28th, we announced plans for major liquefied natural gas regassification and power generation complex near Tijuana and the Mexican state of Baja, California. The proposed complex would consistent of an LMG Marine terminal, an offloading terminal, onshore LMG gassification facilities, and pipeline infrastructure necessary to transport the natural gas.

In addition, 1,000 megawatt natural gas by power generation plant would be constructed on the site. The complex would supply natural gas and electricity for local use as well as for export to Southern California. Since our initial announcement, we have progressed discussions with [PERGAMINA] and other parties for LMG supply and associated upstream developments and have secured land access in Baja. On February 28th, we announced plans to lead an initiative for New North C National gas pipeline designed to provide additional gas for the UK market. The proposed 675 mile natural gas pipeline would connect the Norwegian on the North Sea backend of the Southeast Coast of UK. The pipeline would pass through the [Brea] complex and pass adjacent to other gas processing and transportation facilities in the UK north sea and terminate at or near the existing back line pipelines, existing backing terminal. The pipeline would allow gas to be aggregated from numerous UK and Norwegian North Sea producers for transportation to the backend into where it would be sold to commercial, and residential customers.

We commence the open season nomination process for gas transportation on May 14th, and based upon input from prospective shippers, Marathon is considering increasing the design capacity of the pipeline beyond 1 billion cubic feet a day. Open season will conclude in mid-October. Earlier this month, we announced the acquisition of the North Sea interest in Norwegian production licenses 150 and 203 following recent approval by the Norwegian Ministry of Petroleum. The ministry also approved Marathon as operator of PL 203, Marathon's first operatorship on a Norwegian continental shell. The PL203 block, which the company has a 65% interest is located in the west of [Heimdel], and includes the Camel Line Oil Gas and the Gecko Gas Discoveries. The adjacent license, PL 150, in which Marathon had a 50% interest, is located southwest of the Heimdel, close to the UK border and includes the Greek Oil Discover. This marks Marathon's fifth acquisition in the Norwegian shelf in the past year, including the state direct financial interest transaction within the Norwegian government.

In total, all the region production licenses is currently held by Marathon, are estimated to contain net risk resources of approximately 135 million barrels of oil equivalent, including both the discovery fields and similar prospects nearby. We're reviewing joint development scenarios, which would build upon existing infrastructures to develop the resources. The first production is expected in 2005. Marathon has interest in Norwegian petroleum licenses, 25, 36, 88, 102, 150, 187, 203, 204, and 249. Expiration and appraisal activities are planned for 2002, and 2003. With development work likely to begin in 2003. The plan of development has also been approved for the [Totale] and [FINA] [INAUDIBLE] and Skirna fields. Marathon has a 20% interest in each. The first production of these fields is anticipated in early 2004, and should provide more than 5,100 oil barrel equivalent per day of net production.

In Ireland, preparatory work continues for developing the core field, first production is expected in late 2005 with peak rates of 65 million cubic feet a day net anticipated. Looking at expiration, we completed two deep water wells in the gulf of Mexico the deep appraisal well, while delineating the discovery, also confirmed that the reservoir's more complex than anticipated, and our estimated block's reserve potential has been reduced. Pending further analysis, we will look at development options to determine commerciality. We also complete an appraisal well on a DHP operating Neptune prospect where we have a 30% interest and the results are encouraging. We will drill another well late this year to fully evaluate the potential of this discovery. The Neptune prospect is in the Mississippi fan full belt. In the fourth quarter Marathon will operate at 33 1/3 interest at the Kansas prospect, the next structure on trend with Neptune.

Offshore Nova Scotia, we're near completion of the Annapolis well and should be prepared to announce the results shortly. On BP operator block 31offshore in Angola, we're nearing target death on the tail well and Marathon has a 10% interest in this block and deep water Angola, we plan this year to drill one additional on block 31, and one well on block 32, looking similar to nearby discoveries. To summarize, Marathon's upstream business is in the best position it's been in for years. A receipt acquisitions and equatorial Guinea, the Powder River Basin in Norway will provide steady worldwide production over the next few years, expected to be in the 430,000 to 435,000 barrel equivalent per day range in 2004, while at the same time, providing anticipated reserve growth to 40% to more than 1.47 billion barrel of oil equivalent by year 2004.

Turning to downstream results, the reportable RMP segment income in the second quarter was 211 million dollars compared with the first quarter loss of $51 million. Chicago 321 crack spread averaged $5.39 per barrel in the second quarter versus $3.70 a barrel in the first quarter. The second quarter 2002 gulf coast crack spreads averaged $3.66 a barrel, compared with $2.97 a barrel in the first quarter. Our refining and wholesale marketing margin in the second quarter was 5.2 cents per gallon, versus the first quarter level of 1.6 cents. The gross product margin for our retail business, speedway SuperAmerica, was 11.2 cents per gallon in the second quarter, as compared to 8.3 cents per gallon in the first quarter. Refinery runs average 973,000 barrels per day in the second quarter 2002, or 104% of rate of capacity compared with 891,000 barrels a day, or 95% of rated capacity in the first quarter. As we maximize runs to meet increased product demand in the summer driving season. The $250 million swing in downstream incomes sequentially from the first quarter is attributable to a number of factors.

Refining and marketing gross margins increased nearly $200 million over the first quarter, primarily to a combination of an improvement and 3-2-1 crack spread in Chicago and the gulf coast, improved wholesale margins realized over the spot market prices used in the 3-2-1 calculations and increased throughput. In addition, the transit crude impact was a negative $2 million in the second quarter, versus a $20 million negative in the first quarter, resulting in an $18 million positive change sequentially. Light product margins improved at Speedway SuperAmerica. In addition, merchandise sales and margins have been a key focus for the past several years and the results are outstanding. Merchandise sales were up 7% year over year and wrought more than 13% from the first quarter. Margins on the increased sales improved by nearly 1 1/2% over the first quarter, producing a total margin increase of $26 million versus the first quarter.

Total refined product sales averaged 1.35 million barrels a day in the second quarter, up 10% from the first quarter and up 4% from a year ago. Merchandise sales were up over 13% to $612 million in line with seasonal patterns and were up nearly 7% over the second quarter 2001. Map improved its logistics network and its operator on the Centennial pipeline owned jointly about Panhandle Eastern, [MAP], and TE Products Pipeline Company. The new pipeline which connects gulf coast refineries with the Midwest markets is fully operational with the first product deliveries on April 5th. The line's initial capacity is 210,000 barrels per day. Throughput averaged approximately 70,000 barrels a day for the second quarter. MAP also plans to build a pipeline from [INAUDIBLE] Virginia to Columbus, Ohio. The pipeline will be called Cardinal Products Pipeline and will have a designed capacity of 80,000 barrels per day and is expected to initially move 50,000 barrels a day of refined petroleum in Central Ohio. We expect approval from the army core of engineers soon, and assuming we receive the necessary approvals shortly, the line is expected to be fully operational in the first half of 2003.

Marathon's other energy-related business had operating income of $20 million in the second quarter versus $25 million in the first quarter. The decrease was primarily related to a loss from our 45% equity interest in the Amoco methanol plant. The plant was down for repairs for more than 60 days during the quarter, and outside supplies were purchased to meet customer commitments. Repairs have been completed and a plant has been operating over 100% since mid-June. In addition, methanol prices have recovered and current prices are only 60 cents per gallon range, or about $2.00 per ton. That brings total segment income in the second quarter of 2002 to $485 million, up nearly 350% from the $139 million in the first quarter. Upstream rose 55% while the downstream rose over 500% from a loss in the first quarter. In the unallocated category, administrative expense of $41 million in the second quarter, compared with the first quarter total of $44 million. That interest expense was 27 million in the second quarter, versus 64 million in the second quarter. The increase is a result of low cost variable debt and fixed-rate debt and approximately $7 million in foreign exchange losses.

Cash adjusted debt rose by 220 million in the second quarter to $4.55 billion and the cash adjusted debt capital ratio of June 30th, 2002 is 48%. I will caution you that these are preliminary numbers. Marathon's tax provision was $105 million for the second quarter reflecting an effective tax rate of approximately 35%. This is a reduction from the first quarter effective tax rate of approximately 38%, and primarily results from the lower projected tax provision associated with foreign operations. As discussed last quarter, the United Kingdom announced in mid-April a proposed supplementary 10% tax on profits from UK oil and gas production. Our projections indicate this tax increase with the act that is proposed would add 2% to Marathon's annual effective tax rate, excluding any one-time noncash deferred tax catch-up required. Assuming an accurate proposed UK supplementary tax, we project a 2002 annual tax rate of approximately 38%.

First quarter preliminary cash flow from operations excluding working capital changes was $603 million, or $1.95 per share. Capital spending was $349 million in the second quarter for all of 2002, excluding acquisitions our capital and acquisition spending, including 100% of MAP is projected to be $1.8 billion. The mix would be 51% upstream and 45% downstream. Adjusting our capital spending to include only Marathon's 62% ownership of math, capital spending would be 61% upstream and 34% downstream.

Total mark-to-market and derivative -- pardon me, total mark-to-market derivative and hedging activity for the upstream contributed to the net gain of $20 million pretax in the second quarter, primarily consisting of gains on the Powder River Basin hedges offset by a mark-to-market loss on two of our long term gas contracts in the UK. Our approach to hedging is opportunistic and highly selective and geared toward minimizing downside risk. For example, we hedged the first two years of [Penecos] production when we acquired them to lock in high gas prices at the time, and mitigate the upfront risk associated with buying the assets. The 2002 hedge related to the Powder River Basin averaged to 152 million cubic feet a day at average prices of $4.36 per NCF. Approximately 80 million cubic feet a day currently qualifies for hedging treatment and the remaining 72 million cubic feet per day is mark-to-market each quarter. We have entered into additional zero cost strategies on natural gas production during 2002. We currently have 2 million cubic feet per day for June through December where we sold the upside above $4.48 to lock in a minimum price of $3.19 per NCF. We receive market price when is prices are between $3.19 and $4.48.

Liquid side, we hedged 59,000 barrels per day of 2002 equity crude production through December using a zero-cost caller option strategy. This represents about 32% of our total worldwide crude production. These hedges have been structured in such a manner that on average we will receive market plus $4 per barrel when prices are below $19.34, $23.34, when prices are between $19.34 $23.34, market price when is prices are between 2334 and 2935, and have traded away any upside above $29.35. This position does not qualify per hedge accounting and has mark to market each quarter.

Looking to 2003, we took the opportunity in the second quarter to hedge a substantial portion of our anticipated 2003 Powder River Basin production and other gas productions utilizing zero cost callers with an average core price of $3.64 per million cubic feet, and an average price of $4.64 per million cubic feet. These contracts cover 145 million cubic feet a day and should qualify for hedge accounting. We have also been active in the financial markets during the -- during the second quarter. We continued to improve and strengthen our capital structure through the issuance of new long term debt and the early retirement of high cost long debt. We issued $450 million of five year notes with the coupon of 5 3/8%, yielding investors 5.48%, and $400 million for the tenure notes for the 6% coupon yielding investors 6.11%.

Additionally, we repurchased and retired a face amount of $193 million of high-cost public debt with coupons ranging from 8 1/8% to 9 3/8%. This resulted in an extraordinary loss of the extinguishable debt of $26 million after-tax in the second quarter. We also gave prepayment notice on $144 million private debt with a coupon of 9.05% during the second quarter. This prepayment was completed in July and will result in a third quarter extraordinary loss of approximately $7 million after-tax. Not 70, seven. I repeat that. As a result of all these transactions, Marathon's overall average debt costs has been reduced by approximately 100 basis points.

Finally, I want to make a few observations about the third quarter and the full year 2002. On the domestic upstream upstream side, we expect liquids production to be down slightly versus the second quarter to about 120 to 125,000 barrels of liquid per day. Gas production should come in at 700 million cubic feet a day. IMex pumped average price so far in July is up 50 cents for barrel, versus the second quarter average, while Henry Hud gas prices are down nearly 50 cents per million cubic feet. Domestic exploration expense is estimated to be approximately $15 million.

On the international upstream side, liquids production in the third quarter should be down relative to the second quarter to about 80,000 barrels of liquids per day, primarily due to normal liftings in the UK. We expect gas production to be 490 million cubic feet a day, due primarily to increased sales in equatorial Guinea, offset by seasonal changes in the UK. Based on what we have seen in July, foreign oil prices seems to be following the domestic pattern, and international expiration expense is anticipated to be approximately 15 to $25 million. On a barrel of oil equivalent basis, we expect third quarter worldwide production there fore to be down sequentially to approximately 400 to 405,000 barrels of oil equivalent per day.

For all of 2002, we expect production to remain flat with the average 2001 production at approximately 420,000 barrels of oil equivalent per day. On the downstream side, cracks spreads in July have averaged over $6.30 a barrel in Chicago, and $3.40 a barrel in the golf coast. We expect crude oil costs to continue to be up as a result of the continued tightness and sweet sour spreads, but the pattern we have seen today while easing is not significantly different than what we have experienced in the second quarter. As far as the other energy income line, we expect third quarter income to be consistent with prior quarters at approximately $20 million. Administrative costs should be about $45 million and net interest expense will be about $77 million.

In closing, I want to add one last comment. Marathon welcomes and commends the efforts of the New York Stock Exchange and its originally proposed use for changes in corporate governance practices and the Securities and Exchange Commission and its requirement of financial statement certification by chief executive officers and chief financial officers. As required by the SEC's order, Clarence Cazalot and John Mills will be certified under the SEC under oath the accuracy of Marathon's financial statements and their consultation with Marathon's audit committee by August 14, 2002. I will now open the call up to questions. I remind you to please identify yourself and your firm affiliation for the benefit of all of us listening in. Thank you.

Thank you, our first question is from Mr. Tyler Dann.

Hi, everybody, how are you.

Morning, Tyler.

Ken, I have looked on the website and tried to find the operating costs that you talked about, or the guidance on operating costs, but it doesn't look like it's up there yet posted. Would you be able to go into some detail on EMT production costs for the second quarter, how it compared to the first, and how it compared to last year by region?

I really don't have the detail right now to get down to it by region, Tyler. I can certainly cover it at a higher level, and we will have -- we will have that information on the website likely late this afternoon, I would expect.

Okay, that's fine.

If you look at production -- if you look at production costs -- if you look at total product costs in the first quarter over the -- the second quarter over the first quarter fairly exploration expense was down about -- was down $17 million. We had a swing in derivative activities of $33 million since we had gains of 24 and the loss of it 9 million last quarter. DDNA was only up a couple million dollars. We had additional transportation and shipping costs of about $8 million, production taxes were up about $3 million, um, the workovers, et cetera, that I mentioned earlier, would add $4 million over the first quarter.

And in addition, we had a reallocation of general administrative expense, um, in the $8 million range that doesn't have any impact total corporate level, but it did have an impact on the domestic ENP. Internationally, um, there was a $4 million difference in expiration expense from 8 to 12 and a $21 million swing in derivatives activity, we had a $17 million gain in the first quarter, and a $4 million loss in the second quarter. DDNA was up by about $12 million primarily due to production mix and most or that is liftings in the United Kingdom. We had a property impairment on unoperated property in Canada, which we didn't have in the first quarter, which added $12 million to our expenses.

Okay, um, and I -- I had one other question, then I'm finished, um, the -- could -- in a recent presentation you guided to end 2004 approved reserves increasing to 1.47 billion barrels and wondered if you might give us a sense for, um, I mean looks as if with the Globex acquisition, um, and, of course, the other EG acquisition, um, plus the risk to resources associated with Norway, um, that looked like about 435 million barrels equivalent of resources that, um, are added. I wanted to just figure out, um, whether you're going to be increasing that target or, you know, increasing your SND cost assumptions for the END portion, I suppose, of that reserve.

The two things, Tyler, I'll try -- hopefully if I don't cover this, I'll let -- let me know, but I'll start at the end. Our total FND costs will be something less than $5.50 per barrel oil equivalent. We won't be revising that target, the 1.47 billion barrel oil equivalent proven at the end of 2004 includes everything we talked about, including the acquisition of the resource in Norway.

Okay.

So, that includes -- I remind you, that includes what is we have right now. It doesn't include anything in the future or any other exploration excess. It's what we have in hand right now.

Okay. That's important. Thank you.

I would like to remind everybody to ask a question, please press a one followed by a 4 on your telephone keypad. If you would like to retract the question, you can do so with a one followed by a 3. Our next question is from Paul Ting from Solomon Smith Barney

Hey, Ken, how are you doing?

Hey, Paul.

Question on the acquisitions that you made, as you mentioned you made fairly significant acquisition in Powder River, Norway, and Globex. Um, totally consistent with your analyst presentation. Do you have any can be taught as far as getting out of the acquisitions? What are you target -- what your targeted return might be?

This is John Mills.

Hi, John.

How are you?

Good, thanks.

Um, you know, the initial startup of those projects, um, returns in 2002 were going to be modest, you know, what -- if all those projects, though, have, I guess with the exception of some of the smaller Norwegian license acquisitions, but, certainly Globex and the, um, Powder River Basin, um, incremental acquisition required from XTO, you know, will have a positive return, a positive but modest return initially, but with our efforts at ramping up productions, you know, both in the Powder River Basin and at the -- at the EG, those returns will come into the, you know, kind of cost of capital type returns on capital employed within the next couple of years, and then we have a significant upside on those projects as we go forward.

But you can't quantify that right now?

Well, it's, um -- you know, I'll say they're positive but modest. And we recognize that.

Sure.

And -- and -- I know it's probably early to tell, but based on this type of acquisition, did does that alter your perspective of 3% long term production growth rate, if I remember the number correctly? Let me just continue. As you point out, we do have a, um, 3% -- we think a responsible kind of achievable long term production growth target of a compound 3%, but -- but that is a target, and we're not going to -- we could have easily retained some of the properties we traded away or sold over the last, um, couple of years and --

or buy.

Or go out on a market and buy some now if we were just seeking production growth, we're obviously looking for valued growth, not just barrels growth, so the -- we believe that the -- the 3% is achievable, as Ken mentioned, the reserve growth and the production growth by '04 into the 430 to 435 range is just based on the things we have on the table right now that does not depend on further acquisitions or any explorations other than the things we have already talked about.

And, Paul, let me just amplify that a bit. We have in the past communicated our production targets including activity such as business development that we didn't have in hand. The numbers, as John pointed out here, that we, based on what we have right now, being able to grow from 430 to 435 a day in 2004 is what we can confidently estimate based on what we have in hand right now, so we're not going to communicate based on the target, we're communicating estimates we can deliver on.

Very good. Thank you, Ken and John. I appreciate it.

Next, we have Mr. Frederick Lueffer of Bear Stearns.

Good morning, gentlemen. Ken, you gave us 2002, 2004 production estimates, can you fill in the blank and give us 2003?

We don't -- we'll do that toward the end of the year when we get our budgets and everything lined up for next year, Fred. We don't want to put out a number there right now.

Um, well, you know, okay.

I mean if you look, it will be somewhere between 420 and 430 I would suspect, not to be cavalier about it, but I would suspect it will fall in that range.

Okay, that's obviously why -- what I'm trying to get at, if there is a dip or something.

Sure.

Or something that gets you off trend between the two years that you have just given us.

We don't expect to differ it. I will clarify that. Okay.

Um, on U.S. Natural Gas, do you have a split between Alaska and the lower 48?

Yeah, I do, um, give me a second here and I'll pull that out for you. Pardon me, stay there -- Alaska was 147 million cubic feet a day in the second quarter.

Okay. That's pretty good, what happened there? I know there's seasonality, but

There is significant seasonality, Fred. That's all it is, is seasonality.

How much do you think, um, your lower 48 production was effected by these transportation issues in the Powder River?

I have Steve on here. Steve, do you have anything you want to add?

Really we didn't have any impact, Fred, from transportation issues. We have our own transportation route through Trailblazer, which gets us around any bottlenecks and otherwise -- that may otherwise exist.

Steve, the extent we didn't have that for part of the quarter, we had basis hedges in place.

Um. Are you in the overlift position in Europe, I know you said you underlifted in the first quarter you made up in the second, but where are you now?

We're just about flat right now, Fred. And -- in Europe.

All right. And the ozone and deep dry hole, um, how much is this gonna, how much is this going to change the reserve estimate?

We have Phil here. Phil can address that.

Fred, at this point in time, we have given you guidance before that we thought the ozone could be in the 50 to 100 million barrel range. We really haven't incorporated the results of the two wells, we believe it's clearly below the 50 million barrel range. That's why it's smaller than anticipated.

And you believe it still might be commercial even at that level.

It could be. Tied back to the existing infrastructure in the area that. Has a potential to be commercial in that respect.

Okay, um, in the release, Ken, just lastly, in the release you gave fourth quarter exploration activity, what do you have going on in the third quarter other than the well up in Nova Scotia?

This is, Phil again, we're continuing -- we'll TD the Annapolis well the next several weeks and probably by August sometime, we will TD the Plutal well and go to block 31. And roughly, end of third quarter, early fourth quarter, we'll spud Neptune and later in the fourth quarter -- pardon me, we'll spud the Kansas well at the end of the third quarter, early fourth quarter, and the Neptune appraisal will be clearly in the fourth quarter.

All right, Phil, thanks a lot.

And, also, we'll -- Phil also we'll be doing one more well on block 31 Angola and block 32 Angola.

All right, thanks.

Next is Mr. Steven Pfeifer of Merrill Lynch.

Hi, guys, I want to follow up on the U.S. gas volumes in the lower 48, that you pointed out after adjusting for Alaska were roughly flat. The other thing that changed there was the swap cross timbers. Can you say, obviously your rocky production went up as you gave the things up. Could you just give us the net impact of your U.S. gas production as a result of that swap, um, and I think it was effective in May, just kind of walk us through how that particular change effected U.S. gas production, 1Q, and 2Q.

I don't think there was very much of an impact on that. I have somebody -- we have people checking on that right now, Steve.

Do you think net on net, the net volume impacting you is roughly zero?

I think we would be relatively flat. I don't think it's going to be anything material.

Okay, excellent. And, um, tax rate going forward is at 38% on average for this year, that's a good number for '03 and beyond, you think?

Well, I would say, yeah, for '03 and beyond, I would use that for '03 and beyond. We don't have a better number than that now, and it's in the range of before. We advised earlier we would be closer to 40. We think we're going to be closer to 38 for the year. I would use 38%.

Okay, very good. Thank you.

Next is Mr. Steve Inger.

Hi, guys.

Hi, Steve.

A couple of things, Ken, you mentioned in the five acquisitions in the [Brae Heimdel] area. You added net risk resources of 135 million BOE?

Only in the Heimdel.

What is the cost associated with those acquisitions, roughly?

It's something in the $100 million range. There are some competitive issues. We don't want to get broken down further than that, if you recall we announced our capital budget this year, we set $1.1 billion related in acquisitions to EG and Norway. EG was a variance, so it would be a hundred-million.

Okay, good, thank.

Steve, this is John Mills. That is 135 million -- barrels of oil equivalent, the net risk resource, so there is certainly development costs to be incurred to bring those reserves -- to bring that resource into the reserve category and production.

Right. Okay. And on Annapolis, um, Phil, it seems to be drilling a little slower than you guys had expected. Is -- what's going on there?

Um, well, as we mentioned before, we obviously took the kick early, and that caused us to redrill the well. That was one issue. Secondly, we had a number of rig repairs, that's been an issue. Thirdly, it's taken longer than we would have guessed it based on the forepressures you were seeing. When you add all those issues together, it's taken us long. In the next several weeks, we'll be at TD and make an announcement on that.

You have enough hole left that you are gonna be able to get down as you see it at this point?

Yes.

Okay with.

I think we were just somewhere within 600 to a thousand feet, um last week. Actually, we were 400 feet lest to get.

Okay, and then finally, um, Phil, if you could maybe help us a little bit, it looks like you have characterize Kansas as being on trend with Neptune, then you see it as similarly geologically. Is it also maybe of a similar size to Neptune as you see it or what's the range there?

Um, well let me go back and characterize the trend. The trend consistencies now of the mad dog discovery, the Atlantis discovery and the Neptune field discovery also. These discoveries also vary in size as reported by the individual operators. What I can tell you is the Kansas opportunity of prospect looked similar to the three other discoveries I just mentioned. The key to the size of it will obviously be the amount of sand that is present over the structure.

Okay, and does Kimoto fit into the same trend or is that a bit of a different play?

It's very close to Neptune. It's in a similar trend, but slightly different in terms of it's a thrust-builder orientation

Okay, thanks a lot.

Our next question is from Mr. Mark Flannery of CS First Boston.

I have an upstream and downstream question.

Why don't you ask the downstream first.

Very well.

How are you doing, Mark?

Well, thanks. The retail environment right now, I know we have had ups and downs in terms of competitive environments all over the country, particularly in the Midwest. Where are we ranked now in terms of how competitive the retails fuel market is?

Well, on a gasoline volume basis, um, the second quarter, when I looked at things on the same-store basis, so second quarter of this year, um, we're up about 1.6% on gasoline volume and here going into, um, the first few weeks of July, um, and that's coming off -- June was a strong month on gasoline volume, and going into July, we continue to see strength in our speedway supermarket gasoline volume. And coupled with that, on a competitive basis, we not only look at the gasoline sale size, but the merchandise sale side, we have had strong growth in our merchandise sales. Again, we had a 7% increase in the merchandise sales and about a 14% increase in merchandise margins, so very, very strong, um, performance, which means we're still dragging the customers into our locations.

Right. So nothing -- nothing like a -- an outbreak of what happened in the first quarter seems to be on the cards right now.

Um, no, in the first quarter I would say was -- was driven -- I did not recognize the first quarter being driven by the hypermarket or, um, you know, the independence. It was really driven more by the majors and some certain big, um, big markets and -- and while margins are still gasoline margins are still soft in comparison to where our plant had been, we're starting to see our volume grow, which is saying we're starting to see some demand pickup, um, in transportation fields.

Right. Okay, thanks. Um, maybe the upstream question is really on the Annapolis well of costs. I mean where -- in terms of once we get to TD, what will that well have cost, do we think, versus what the original plan was. What kind of costs overrun are we looking on that well?

Um, Mark, this is Phil. At this point in time, we're not releasing the cost information of the well; however, let talk about a few issues. Number one, all of the rig repairs that occurred, all the costs were born by the rig owner, a majority of the rig costs were born by the rig owner, not by Marathon and the partnership group. Nonetheless, the cost of the well has taken longer, and, therefore, the well has cost more than we originally anticipated.

Will you be, when you announced, when you make an announcement in a few weeks, will we get cost numbers then, do you think or --

We were not planning on that at this point in time.

Thanks.

Next is Mr. Paul Cheng of Lehman Brothers.

Hey, guys.

Hi, Paul.

A couple of quick questions. Do we have a talk of production number for the power with the -- [ Indiscernible ] Over the next two years? 85 million cubic feet a day, what does that number look like in 2003 and 2004?

We have a -- we've got in presentations we put out before, we have given a range say in the 90-100 range for this year increasing into the -- that.

And that's before you make the receipt acquisition so --

No, Paul, those numbers include the trade for the CMS interest. That's all in right now, yes. And next year that could be up in the 115 to 125 range.

Okay. Um, how much of the reserve you going to book from that area for this year excluding the recent acquisition?

Paul, you're asking how much beyond the initial acquisition might we be book in the powder basin this year?

That's correct.

It's really too early in the year, John, you know, to try to give an estimate on, that Paul, we don't do that until the end of the year. It's a fourth quarter item.

Okay. Um, Ken, you mentioned early, I think, you had an impairment charge in Canada?

Yes.

Can you elaborate a little bit, how big is that, and what is that relation.

Paul, what that relation is -- is I think you and a lot of other people are aware, we have had significant asset rationalization in Canada over the last two years, and this is really just kind of a cleanup and looking at some of the remaining property there, and we had property that we felt was overvalued on the books and wrote it down by $12 million.

Is that relate to any reserve writedown also?

Not at all, Paul. It's totally out of the unoperated property area.

Um, okay, maybe this is for John, when I looking at your pension plan, the current assumptions for the rate of return is 9.5%, given the market's condition right now, is there any intention, um, from the company perhaps to change that and if so, what kind of impact have you made to the future earnings?

Well, Paul as you know, as the, um, the Marathon plan has historically been a well-funded plan. We have a very high, um, equity allocation, and we're convince even given the last couple of years of the market, over the long term equities will our perform the debt obligations, um, we have experienced a long-term earnings performance for the Marathon MAP plan assets, um, it's about equal to 75% equity mix and the 25% Lehman corporate and government bond index mix.

That number is, um, say over the last 10 years, significantly above the 9 1/2% earnings assumption that we're using for, um, our return -- expected return on plan assets going forward. But I will also tell you that, um, in the fourth quarter and early next year as we're looking at that plan, earnings rate assumption that we'll be taking a close look at the recent performance, and if we have to adjust it, it will be down obviously, not up. But, um, it's a rate that historically, we have felt comfortable with because we have had planned performance, um, you know, looking back over longer periods of time that have been, um, comfortably above that 9 1/2% effective return assumption.

Okay, thank you.

Next is Mr. Michael Young with Gerard Klauer Mattison & Co..

Good morning. It's a strategic question regarding Norway. What I wanted to ask was what's really changed about that particular country that's now made it such a core operation for Marathon, particularly in light of, you know, just several years ago, Marathon's strategy was to exit all operations in that particular area.

This is Phil. I'll go ahead and answer for Ken.

Yeah.

Um, first of all, we indeed, do have the infrastructure in and around the Heimdel area, when which we want to leverage off. Secondly, we had past tax advantages which Marathon could leverage off of those advantages. Thirdly, we had some number of opportunities for acquisitions, which we were able to take advantage of at a low price. When you add all that up together, we saw the opportunity to codevelop a significant resource base in the Heimdel and particularly in the west of the Heimdel, area, which would be very material to Marathon. It also fits in very well with our integrated gas strategy from moving more gas from Norway to the UK area. When you add them all up together, causes them to move on the acquisitions early.

Got you. Okay, thank you.

Next is Fadel Gheit with Fahnestock & Co..

Hi, I have a couple of questions. The first, what is the potential liability exposure that you might have from newer steel going under?

We'll -- we'll let John Mills handle that one.

Fadel, as you know, at the time of separation, um, January 1 from U.S. Steel, um, we maintained responsibility for a number of balance sheet items, as well as nonbalance sheet items that were historically the obligations of USX parent company in the prior structure, and we have on our Marathon balance sheet $554 million of total items that are characterized as long term debt, and they're made up of, um, industrial revenue bonds of about $470 million and about $84 million cap release, so we have the balance sheet debt of $554 and, again, the bulk of that shows up from the -- both on the right-hand side of our balance sheet lumped in with our long debt, and then on the left-hand side of our balance sheet, we see a receivable from U.S. Steel of a longterm receivable of $551 million, part of that short term to make up the 554 total. Um, then beyond that, we have a number of items, um, contingent to obligations on leases and several tax liabilities for federal and state income tax returns that we have filed jointly for prior years, so when you look at total, um, obligations in the $800 million range.

And this is likely to remain on your books for, what, for years or --

We have -- under the separation agreement documents and the, um, financial matters agreement with -- between now Marathon and U.S. Steel that obligation will remain with Marathon for a 10-year period.

Okay, and then I have a couple of minor question. It looks like the current trend rate, um, you will have the cash flow short fall if you keep up with capital spending. That is barring any additional asset purchase, um, it looks like you have to cut your spending, you have to sell assets to bridge this gap. What is the current strategy?

Well, I'm not -- I'm not sure I totally agree with the premise of your question, you know, we have, um, announced a, um, a self-imposed cap of 50% of cash adjusted debt to equity. We recognize at the end of the second quarter, we're approximately 48%, um, of -- so that, um, you know, we -- we are, you know, the current run rate, I'll call them, we're generating significant positive cash flow, um, sufficient to fund our -- the balance of our capital program, both upstream and downstream for the balance of 2002. We will be negative cash for the year reflecting the significant acquisitions that we have made in the first half of the year, but we have factored those into our, um, our cash-adjusted debt for total capital projections and believe we're going to say, um, below, again, that's 50% self-imposed target. Not -- now to the extent we have other opportunities come along that are more attractive and things that we have in our current portfolio, we'll be looking hard at trades or selling assets, um, I'll say from the bottom of the portfolio in order to avail ourselves with those kinds of opportunities.

Finally on the Mexico plant, I understand the contractor is not -- or doesn't want to pay the bill. Is that something that is -- that is confusion or it's a small bill?

I guess, um, somebody here wants to correct me, but I think the state of the claims on that are set that they're probably not something that we should talk about right now.

Okay, no, I just want to know, I know the magnitude was that it was an extensive proposition or like a couple of million dollars?

It would be relatively, relatively small.

Okay, thank you.

The next question is from Mr. David Neuheiser.

Hi gentlemen, my question is for Stephen. Regarding EG, I know you were making a decision on which technology you were going to use to distract the gas there, either gas liquid or LNG. Any time frame on what when that determination will be made?

David, before the end of the year.

Before the end of the year. My other question is are there any other -- are there -- I think the question was answered, anymore impairment charges or, on the year or no?

We don't anticipate -- this is John Mills. We don't anticipate any -- nothing else on the forecast reserved in the second half.

All right, thank you very much.

Next is Mr. Mark Gilman of First Albany Corporation.

A couple of things. Was Centennial Pipeline profitable in the second quarter?

Gary, um, Gary, -- are you still on the phone? Gary Henning is no longer here. I am here. The second quarter was not profitable, it started up early this year, we expect to become profitable shortly.

Okay, what was the amount of overlest in the UK in the second quarter?

Just a second -- Let me pull up something here. We're doing some quick -- we're doing some quick math here. It was about three million barrels in total.

Three million in the quarter?

Yes.

Okay, I guess that sounds about right. Let me be sure I understand something. With respect to the Powder River Basin volumes, um, the 24 million you captured with XTO, does that basically mean exclusive of the train that the basic pass-go asset was still doing about 60?

That's correct, Mark.

Is that right?

That's correct. It's still ramping up.

Okay.

Meaning there has been a lot of wells drilled there and we just, you know, it's going to increase but it's taking more time than we hoped.

Okay, Ken, you indicated that third-quarter interest expense about 77 million, flat was second, but then you also indicated the second had 700 million foreign exchange laws and you have done the significant amount of favorable refinancing. I don't quite understand what you're getting at in terms of why it doesn't go down.

Mark, John Mills. Part of the impact is that during the second -- during the early part of the second quarter, we had a fair amount of -- of revolver and other short term borrowings that are in today's marketplace, are very inexpensive that we have, um, that, as you're aware of, have done the two significant borrowings on the 5 year deal and 10-year deal. And while we think we're locking in very attractive long-term interest rates, those rates are higher than -- than, um, -- than the very short-term rates that you can get on either the revolver or the commercial paper. So that when you do that all blends of -- on a debt balance that say little over 200 million higher at the end of the second quarter than it was at the first, um, you end up with something in that 75, we'll say to $77 million range that Ken mentioned.

Okay, I wonder if Phil could talk about what kind of net pay was observed in the first two Neptune wells and specifically, what you guys are seeing on this one that you think BP missed.

Yeah, Mark, it's Phil. Um, let me just get back a little context for this. The Neptune structure is about nine miles long by about, oh, 2 1/2 miles wide. There has been three wells drilled on the structure. Um, the first well in 1995, the second well in 1998, and the recent well which just reached TD. Those wells are about two miles apart. All of those are on the south side of the feature, so it's significantly large structure really is, to a large extent untested -- in other words, only a small portion of the structure was tested previously. In the previous first two wells, they found about a hundred to 125 feet of pipe, um, as we have known in the press release, Marathon -- Marathon found roughly 150 feet in the third well, the second appraisal well. In addition to that, what we encountered was the fluid quality was better than the first two wells. And secondly, um, the reservoir rock itself, the quality of it was significantly higher. When you add the improved flood quality along with the improved reservoir rock qualities, the flowability of the hydrocarbon from the rock has been improved substantially, increasing the attractiveness of the overall discovery. That's what's different.

And you think BP missed this?

Well, the first two wells did not indicate. Not that BP missed it, the first two wells were clearly different than the third well.

Are -- are you convinced we're on the same structure, Phil?

Yes, we're on the same feature. There is a significant amount of feature that remains to be tested, the focus of the additional appraisal drilling for later this year.

All three are within a 2 mile --

No.

Distance.

No, not within a two mile distance. There are three wells, virtually all of them in a line, each one roughly two miles apart, so they span four miles in length between them

Okay, thanks a lot, Phil.

Okay.

Our final question this morning comes from Mr. Matthew Warburton of UBS Warburg.

A couple of quick questions, are one on math and business development. First of all, Ken, can you quantify the impact on the MAP and the Gariville COCA specifically in the third quarter, and specifically a question for Steve on business developments. I noted in Ken's remarks the power plant associated with the Baja Regas went up from 400 megawatts to a gigawatt of capacity. Has the 750 million of gas a day you increase or is it a mix in the change of the power elements of that project?

Well, why don't we -- Gary Piper, why don't you go ahead and take the first question there.

Okay, um, comparing to the second quarter of last year, um, we have seen our costs of crude go up about $2.40 a barrel, we call the sweet-sour differential of narrowing, which given the number of barrels, it runs $200 million negative effect quarter to quarter, um, sequentially, it was relatively minor, both quarters were fairly similar but narrow, obviously, compared to last year, and on the coker, because of the arrangement we had for the supply of crude oil, we do have some guarantees in that contract that allow us to sufficiently still be on target with our prediction that that, plus pilot travel centers and even with the small loss at the, um, the centennial we spoke about earlier, we're still expecting about a $100 million improvement in our income year to year. So the coker is still doing well for us.

Good.

And Matthew, as far as your question on Baja goes, it's early days for the project -- project, but you're correct in saying we have increased the power mix against the gas mix and we will slightly increase the LNG crude oil mix.

Is it because of the assessment of the markets for the gas in terms of the U.S. giving will turmoil or the energy markets, what's behind that decision to increase the power mix?

Two things. We wanted the local increase in power demand in the Tijuana region. Certainly the electricity in that region was greater than we expected, so having done our market analysis from -- in considerable detail -- detail, we found the power amount was greater than expected, and the gas amount was lower than expected, the reason for the change in the mix.

Right, in terms of the 750. How has that changed if at all?

We're going to increase the capacity of up a B a day. so it's a slight increase in overall capacity.

Okay, thank you very much.

Thank you very much.

We have no further questions.

Okay, having no further questions, we'll go ahead and end the call. I once again thank everybody for your participation, and we'll be talking to you again sometime in October. Thank you.