馬拉松石油 (MRO) 2004 Q2 法說會逐字稿

Good day, everyone and welcome to the Marathon Oil corporation second quarter 2004 earnings conference call. Today's call is being recorded. For opening remarks and introductions I would like to turn the conference over to Mr. Ken Matheny, Vice President of Investor Relations. Please go ahead.

Thank you, operator. And I'd like to welcome everybody to the second quarter 2004 earnings teleconference for Marathon Oil Corporation. With me on the call today from Marathon Oil are Clarence Cazalot, our President and CEO; Phil Behrman, Senior Vice President of Worldwide Exploration; Steve Hinchman, Senior Vice President of Worldwide Production; and Janet Clark, Senior Vice President and Chief Financial Officer. Also with me from Marathon Oil-Ashland Petroleum are Gary Heminger, President; and Garry Peiffer, Senior Vice President of Finance and Information and Technology. I will spend about 30 minutes reviewing second quarter results and then we will open the call up to questions. And about two hours after this call ends, these remarks will be placed on the Investor Relations portion of our website. They will remain on the site for one year.

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, 2003, form 10-Q for the quarter ended March 31, 2004, and in subsequent forms 8-K cautionary language identifying important factors, but not necessarily all factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

In addition, Ashland Inc. has filed a preliminary proxy statement prospectus with the U.S. Securities and Exchange Commission in connection with a proposed transfer to Marathon Oil Corporation by Ashland of its interest in Ashland Petroleum LLC and other related businesses. Marathon, Ashland, New EXM Inc and ATB Holding, Inc. will file a definitive proxy statement prospectus with the SEC in connection with the transaction. Investors and security holders are urged to read the preliminary proxy statement prospectus, which is available now, and a definitive proxy statement prospectus, when it becomes available, because it contains and will contain important information. Investors and security holders may obtain a free copy of the preliminary proxy statement prospectus and the definitive proxy statement prospectus when that becomes available and other documents filed by Marathon, Ashland, New EXM Inc. and ATB Holdings Inc. with the SEC at the SEC's website at www.SEC.gov. The definitive proxy statement prospectus and other documents filed by Marathon may also be obtained for free from Marathon by calling Investor Relations at 713-296-4171.

Now, on to the quarterly results. The second quarter of 2004 was a good financial quarter for the upstream business as commodity prices continued at high levels. Upstream results would have been significantly better had it not been for mark-to-market losses on two long-term gas contracts in the United Kingdom totaling $95 million, or 17 cents per share. The downstream had an outstanding quarter with record crude oil runs at our refineries and high refining margins in both the Gulf Coast and Chicago. Reported net income for the second quarter 2004 was $352 million, or $1.02 per share. Income from continuing operations aftertax for the quarter was $348 million, or $1.01 per share. And this was an increase of $90 million, or 35%, when compared to the first quarter 2004 net income of $258 million, or 83 cents per share. Second quarter income from continuing operations exceeded first quarter net income primarily because of the strong downstream performance.

Looking at the upstream segment, second quarter operating income totaled $343 million, that's $11.12 per barrel of oil equivalent. In the first quarter, that was $478 million, or $14.08 per barrel of oil equivalent. Lower income in the second quarter was attributable to significantly higher mark-to-market derivative losses, and lower volumes which were partially offset by higher prices and lower costs. The second quarter upstream segment included a negative $126 million derivative-related impact, including a $95 million mark-to-market loss on two long-term gas sales contracts related to Brae. In the first quarter, the derivative-related impact was a negative $8 million, including $14 million of mark-to-market gains on these same Brae contracts. Focusing on domestic upstream operations, second quarter operating income was $285 million, or $16.09 per BOE; versus $306 million, or $16.14 per BOE in the first quarter. Lower second quarter income was primarily attributable to lower volumes, higher exploration expenses, and higher derivative-related losses and operating expenses partially offset by higher prices.

Our average domestic realized liquids price, excluding derivative activity, was $31.74 per barrel; $2 greater than the first quarter level of $29.74, but $1.03 less than the increase in spot WTI of $3.03, primarily due to widening sweet and sour differentials as our domestic crude mix is about 55% sour grades. Our second quarter average domestic gas price of $5.02 per MCF excluding derivative activity was up 31 cents from the first quarter level of 4.71. Looking at just our lower 48 gas sales, our realized price was $5.78, or 27 cents above the first quarter lower 48 prices, in line with the 29 cent increase in average bid week prices for the quarter. Derivative-related activity was a negative 23 million, or $1.28 per BOE, compared to a negative $17 million in the first quarter; primarily a result of our crude oil hedges. Exploration expense was $15 million in the quarter, that's 83 cents a barrel of oil equivalent, up from the first quarter level of $8 million driven by higher dry hole expense.

DD&A in the quarter was 5.95 per BOE versus 5.25 in the first quarter, primarily the result of an asset impairment of $7 million related to the cancellation of a deep water Gulf of Mexico exploration license, and the timing of capital and reserve bookings. All other domestic costs in the first quarter totalled $7.47 per BOE, up 20 cents from the 7.27 per BOE level in the first quarter. The increase is primarily a result of increased production taxes related to higher prices and a positive legal settlement that was booked in the first quarter. Domestic liquids production came in slightly lower than expected at 87,000 barrels of liquids per day, down 5% versus the first quarter primarily due to an unplanned shut down for approximately two weeks at the Indian Basin Gas Plant in New Mexico. Natural gas production came in slightly better than expected at 641 million cubic feet per day. That was down 9% from the first quarter, primarily due to lower seasonal sales in Alaska.

Turning to the international upstream, segment income was $58 million, or $4.45 per BOE, compared with $172 million, or $11.46 per BOE in the first quarter. Lower income in the second quarter was a result of significantly higher mark-to-market derivative and hedging losses, lower volumes; partially offset by higher prices, lower DD&A, and lower operating costs. Our average foreign liquids price of $30.91 per barrel was up $2.69 sequentially. That was less than the $3.29 increase in dated Brent, primarily because of lower price realizations in Russia which do not track dated Brent. All other international crude realizations met or exceeded dated Brent and 40s increases. The average gas price of $3.07 per MCF was down 39 cents as a result of seasonally lower volumes and prices in the United Kingdom. Derivative-related activity was a negative $104 million, or $7.88 per BOE, including $95 million of mark-to-market losses on two long-term gas sales contracts related to Brae. Derivative-related activity in the first quarter was a positive 9 million, or 63 cents per BOE, including $14 million of mark-to-market gains on the previously mentioned long-term sales contracts.

Earlier this month, on July 7, we put out guidance on the significant mark-to-market losses we experienced in our U.K. gas sales contracts. Because there was some confusion as to the nature of these losses, I want to take this opportunity to provide more information on the contracts, and the nature of the losses. These U.K. gas sales contracts were executed in the early 90s, and cover the sale on average of just under 100 million cubic feet of gas per day, and they run into 2009. The pricing terms are confidential, and are linked to a basket of energy and U.K. inflation factors. In addition, these contracts reprice annually in October, based on the previous 12 months market basket prices. Consequently, the prices under these contracts do not track forward gas prices. Financial Accounting Standard 133 became effective in 2002, long after these contracts were signed. Nonetheless, the provisions of FAS 133 require at the end of each quarter we mark these gas sales contracts to market. The fair value is determined by applying the difference between the contract price and the U.K. forward gas drip price to the expected sales volumes for the next 18 months; 18 months is used because the forward market and the U.K. is relatively illiquid beyond 18 months.

These mark-to-market adjustments are very unpredictable. For example, in 2002, we recorded gains of $18 million. In 2003, we recorded losses of $66 million. And so far in 2004, we recorded a gain of $14 million in the first quarter, and a loss of $95 million here in the second quarter. All of these gains and losses are noncash, and are not related to current gas sales or price realization. In fact, our overall U.K. gas sales in the second quarter were in the range of $4 per million BTU. Because of the volatility in the forward market, and the potential for large movements affecting our quarterly earnings, we will begin in August posting to our website each month the mark-to-market gain or loss for the month. Providing investors the information they need to better estimate our quarterly earnings.

International exploration expense was $12 million, 98 cents per BOE, and that was down $5 million from the first quarter. DD&A was $6.82 per BOE in the second quarter, that's up 28 cents per BOE over the first quarter, primarily as a result of seasonal variations in Ireland with gas injection beginning in late April and assets that are depreciated on a fixed basis. All other costs were nearly flat at $7.74 per BOE versus the first quarter. Production came in lower than expected. International oil liftings were 91,000 barrels of liquids per day, that was flat with the first quarter. The decrease, compared to our guidance, was primarily a result of a delay in the phase 2-A condensate expansion project in Equatorial Guinea. It was anticipated the production ramp-up would begin around the end of May and reach facility -- reach facility capacity in July. Due to mechanical difficulties during commission, production ramp-up will begin in July, and reach final capacity of 54,000 barrels per day in September. Phase 2-B, the LPG Gas Plant expansion will reach full capacity in the first half of 2005. The total combined liquid production in 2-A and 2-B will reach peak capacity of 79,000 barrels of liquids per day. That would be 44.5 thousand barrels per day net to Marathon in the first half of 2005.

Gas production came in as planned at 324 million cubic feet per day, down 26% over the first quarter level, due to the Kinsale Head Field in Ireland initiating gas storage injection in late April, and lower seasonal gas sales in the United Kingdom. Our production on a worldwide basis for the quarter just ended was 339,000 barrels of equivalent per day, that compares to 396,000 barrels of equivalent per day for the same quarter last year. Three components make up this difference. First, asset divestitures reduced production approximately 39,000 barrels of oil equivalent per day. Second, we continue to see around an 8% decline rate in our base assets or about 30,000 barrels of oil equivalent per day. And third, new production from Russia and Equatorial Guinea added incremental production of around 12,000 barrels of oil equivalent per day.

Turning now to the downstream results, Marathon's refining, marketing and transportation reportable segment income in the second quarter was $577 million, up significantly when compared with the first quarter level of $49 million, and more than double the second quarter 2003 level of $258 million. Because of the seasonality in the downstream business, I will compare the second quarter 2004 results against the second quarter in 2003. Refining and wholesale marketing margins have been strong, initially due to the markets' concerns about refiners ability to supply the new tier 2 low sulfur gasolines which were required effective January 1, 2004, and more recently due to concerns about the adequacy of distillate supplies heading into winter. Chicago 321 crack spreads averaged over $11 per barrel last quarter, up from about $6.60 per barrel in the 2003 quarter. On a two-thirds Chicago, one-third U.S. Gulf Coast basis, the 321 crack spread increased from about $5.60 per barrel in the June, 2003 quarter, to about $10.50 per barrel in the June, 2004 quarter, or about a $5 per barrel increase. This was obviously a huge incentive for refiners to maximize production and MAP was no exception.

Because of the strong refining margins and all the work MAP has done recently to increase the capacity and improve the reliability of our seven plant refinery system, we processed record volumes of crude oil and total refinery inputs in the current quarter. MAP averaged 1,013,000 barrels per day of crude oil throughputs and an additional 142,000 barrels per day of other charge and blend stocks through our plants, for an average total refinery input of 1,155,000 barrels per day. In fact, we set nine throughput records in our refinery system in the month of June. Our total refinery throughputs were almost 7% higher this year compared to the same quarter last year. Partially offsetting these improvements, crude oil prices increased from $35.76 at the end of March, to $37.05 at the end of June, which represents about a 3.5% increase. However WTI averaged about $38.30 cents for the quarter and that's the highest quarterly average WTI price since petroleum prices were decontrolled in the early 1980s. Thus crude oil prices averaged about $9 per barrel, or 33% higher in the current quarter, compared to the same quarter of 2003.

Due to these high raw material prices, our wholesale margins, especially on our non-gasoline and non-distillate refined products, were compressed compared to the same quarter last year, versus what the WTI based 321 crack spread metric would indicate. This is primarily due to the fact that the prices for other refined products do not change as quickly or as frequently as spot gasoline and distillate prices. In fact, the 6321 crack spread, where 3% residual fuel oil is the number one in this calculation, has increased much less than the 321 crack spread. On a two-thirds Chicago, one-third U.S. Gulf Coast basis, the 6321 crack spread has only increased about $3 per barrel in the current quarter, compared to the 2003 quarter, versus the almost $5 per barrel increase in the traditional 321 crack spread. This $2 per barrel difference times the almost 100 million barrels of total inputs we processed in the June, 2004 quarter equates to a reduction in earnings versus the standard 321 metric of about $200 million.

Late last year and this year, MAP sold crack spreads forward through the third quarter of 2004 at values higher we anticipated they would be in the actual months these contracts would expire. Due to the continued run-up in crack spreads during the June, 2004 quarter we recorded a $29 million loss in the forward crack spreads closed during the quarter, and I we also recorded a mark-to-market loss of about $11 million on the forward crack spreads we've sold that will expire during the September, 2004 quarter. For a net loss of about $40 million during the quarter. We also experienced higher manufacturing costs this quarter, primarily due to higher purchased energy costs. And, finally, the crude oil in transit effect was a negative $12 million last quarter compared to a negative $5 million in the same quarter last year. The result of all these factors is the refining and wholesale gross margin increase from 7 cents a gallon in the June, 2003 quarter to about 12.5 cents per gallon in the current quarter. MAP's overall consolidated refined product sales excluding buy/sell volumes totalled about 5.2 billion gallons, or 6.7%, more than the same quarter last year.

Looking at SSA, same store gasoline sales, were up less than 1% quarter-to-quarter, due to the high prices that we were forced to try to recover at retail throughout the quarter. However, SSA's total gasoline and distillate sales were down about 80 million gallons quarter-to-quarter. And this reduction was primarily due to the fact that SSA operated fewer stores during the quarter, compared to the same quarter last year, primarily because of our sale of 190 locations in the southeast in the June, 2003 quarter. At the end of June -- at end of June, 2004, we operated 1,746 Speedway SuperAmerica stores, compared to 1,802 stores at the end of the June, 2003 quarter. SSA's merchandise sales on a same store basis increased about 12% last quarter. Even though SSA operated fewer stores compared to the same quarter last year, SSA's total merchandise sales were up slightly quarter-to-quarter, primarily due to these strong same store sales increases. SSA's gasoline and distillate gross margin was down quarter-to-quarter from 12.3 cent per gallon in the June, 2003 quarter to 11.9 cents per gallon last quarter, reflecting the impact of trying to recover the higher costs at the retail level.

Turning now to the integrated gas business segment, operating income was a loss of $8 million in the second quarter 2004 compared with income of $15 million in the first quarter of 2004. The primary reason for the decrease was the recognition of $18 million in gross start-up costs associated with our LNG project in Equatorial Guinea. You will also note a new line on our income statement reflecting GEPetrol's 25% minority interest in the EG LNG plant. For the second quarter, this line reflects GEPetrol's share of the $18 million start up cost. Now that we have reached final investment decision, we expect nearly all spending on EG LNG during the construction period to be capital in nature. Included within the integrated gas segment is income from our 45% equity interest in the Amco methanol plant in Equatorial Guinea. Operating income for the second quarter was $17 million, and totals $29.5 million year-to-date. Amco is one of the newest methanol plants in the world, having started operations in 2001. It is a world scale methanol plant, and is a low cost producer, and plant operations this year have been outstanding, operating at 93% on -- at a 93% onstream factor.

Methanol prices have remained strong in 2004, averaging nearly $213 per ton through June. And we expect them to remain relatively strong for the remainder of the year. We estimate operating income and cash flow for the full year 2004 to exceed $50 million. Moving back to overall financial results, total segment income in the second quarter of 2004 was $912 million, that's up 68% from the $542 million in the first quarter. Upstream declined by 28 cents -- 28%, while the downstream improved by nearly 1100%. In the unallocated administrative category, administrative expense was $84 million in the second quarter. The increase over the first quarter level of $64 million was primarily due to stock-based compensation expense of $24 million, and up front costs of $7 million incurred to outsource portions of the Marathon accounting and IT functions. This $7 million includes a $3 million noncash pension curtailment loss.

Marathon has expensed all stock-based compensation granted since January 1, 2003. Stock-based compensation granted before that date continues to be accounted for under previous accounting standards. Under those standards, Marathon must recognize an expense for the difference between grant price and the current market price of Marathon stock for certain types of grants. Similar to marking derivative instruments to mark-to-market, we must recognize a noncash charge or credit for the change in the market value of unexercised grants each quarter. When the value of Marathon stock increases, as it did by nearly $4 per share in the second quarter, we record an expense. If the stock price falls, we reverse the accrual, and record income. When we give guidance on estimates of unallocated administrative expense, we do not include this impact because we cannot predict our stock price. The quarterly sensitivity to our earnings is approximately 4 to $5 million for every $1 change in our stock price, based on options outstanding at June 30, 2004.

With respect to both the Marathon and MAP outsourcing programs for both accounting and IT undertaken during the second quarter, remaining upfront cash costs are estimated at $10 million, and will be completed in 2004. In addition, Marathon will likely pass the threshold at which a pension settlement loss must be recognized sometime in the second half of the year. The cost savings from outsourcing will provide a pay back on the estimated $15 million total upfront cash costs in less than two years. Moving on down the income statement, net income and other financial costs were $51 million in the second quarter, higher than our guidance of 45 million as a result of foreign exchange losses, and lower-than-anticipated capitalized interest. Cash-adjusted debt went down by $266 million during the second quarter to $1.858 billion, as a result of strong cash flow in the quarter. The cash-adjusted debt to capital ratio at June 30, 2004, is just under 20%, down from 23% on March 31, and a peak of 48% less than two years ago. I remind everybody, these are preliminary numbers.

Marathon's pre-tax income for the second quarter, reflecting just Marathon's share of downstream income, was $562 million, and the tax provision was $214 million; for a 38% effective rate. Second quarter preliminary cash flow from operations was $1.230 billion. And preliminary cash flow from operations before working capital changes was 1.499 billion.

Finally, I want to make a few observations about the third quarter and full-year 2004. For 2004, we have hedged a portion of our anticipated oil and gas production utilizing zero cost collars. We have also swapped a part of our anticipated gas production for 2004. There have been no changes to our hedge volumes since last quarter. The detailed volumes and prices are included on page 23 and 24 of our March 31, 2004 10-Q, so I will not repeat had them here. On the domestic upstream side, we expect third quarter liquids production to be flat versus the second quarter, at about 87,000 barrels of liquids per day. Gas production should increase to about 680 million cubic feet per day, due to expected additional sales late in the third quarter in Alaska, and gas development activity. Domestic exploration expense is anticipated to be approximately 10 million to $20 million.

On the international upstream side, liquids production in the third quarter should be about 85,000 barrels of liquids per day, down from the second quarter due to the timing of liftings. We expect gas production to be about 309 million cubic feet per day, down compared to the second quarter, due to a full quarter of storage injection in Kinsale Head in Ireland. International exploration expense is anticipated to be approximately 30 to $65 million. On a barrel of oil equivalent basis, we expect third quarter worldwide production to be flat, at approximately 337,000 barrels of oil equivalent per day. And for all of 2004, we expect production to average about 360,000 barrels of oil equivalent per day, excluding any acquisitions or dispositions.

On the downstream side, there continues to be no shortage of additional issues that could erupt and the physical market appears to be well supplied on most fronts. But the market's attitude is that supply, though adequate, is tentative, issues such as terrorism transcend the conventional notions of risk premium, since these acts could involve multiple supply targets. Combined with an accelerating world economic recovery and increasing investor interest in the relative value of commodities, price premiums on oil are likely to continue to be in the $8 to $10 per barrel range for the foreseeable future. MAP's refineries operated very well during the quarter as a result of the strong crack spreads and the investments we made recently to improve reliability and increase capacity of our 7 plant system. And even though we had a slow start in the first quarter, because of all of our planned maintenance, we still expect the total crude throughputs for the year will average at or above historical levels. As you know, forward crack spreads have been extremely strong. While we do not expect the crack spread will remain at the most recent level, they should be significantly higher than mid-cycle differentials moving forward.

Finally, gasoline demand has been relatively strong in spite of the high prices we've experienced so far this year. We have observed some deceleration in demand when retail prices exceed $1.80, which is currently the case in most of our markets. However, we expect crude oil prices to moderate somewhat going forward, which should lower retail prices, and help stimulate gasoline demand. In addition, because of the strong economic growth, we expect distillate demand to continue to remain strong, especially in the over-the-road markets. Integrated gas income for the third quarter is forecast at about $10 million. Net interest and other financial costs excluding any exchange rate gains or losses will be approximately $45 million for the third quarter. And for all of 2004, we project net interest and other financial costs of $180 million. Unallocated administrative expenses should be about $60 million in the third quarter. Again, excluding any impact of share price movement, and resulting gains or losses on equity-based compensation. For 2004, we continue to estimate our effective tax rate will be 38%.

In closing, we have made significant progress on our focus and execute goals for the year. We finalized the investment decision on EG LNG train one and continue construction on this important project. We continue to realize significantly improved exploration success. We have a number of additional wells to drill this year. And along with our partners, continue re-entry negotiations with Libyan officials. While we have experienced some delays, we are well along on our liquids expansion project in EG, and are on track to sanction our Norwegian development this year. The acquisition of Ashland's 38% minority interest in MAP continues to move forward. We received early termination of Hart-Scott-Rodino and have submitted our request for a letter ruling to the IRS on the tax-free status of the proposed transaction. Additionally I would remind that you we issued 34.5 million shares of Marathon common stock at the end of March to help facilitate this transaction which, because it is not expected to close until the fourth quarter of this year, diluted our earnings for the quarter; but on a prospective basis, we anticipate this transaction will be accretive to earnings. For example, had we owned 100% of MAP under the terms of the agreement this last quarter, our earnings per share would have increased approximately 35 cents. I will now open the call up to questions, please identify yourself and your firm affiliation for the benefit of all those listening in. Thank you very much.

Thank you. The question-and-answer session will be conducted electronically. [Caller Instructions] We will proceed in the order that you signal us and we will take as many questions as time permits. We'll pause for just a moment to give everybody an opportunity to signal for a question. We will take our first question from Doug Terreson with Morgan Stanley.

Good afternoon, guys.

Hello, Doug.

In refining and marketing productivity seems to be rising at SSA both in terms of same store sales of gasoline and merchandise, and I think Ken talked a little bit about same store merchandise sales trend trends; but I was wondering if you could provide some insight as to how the refined product component of the mix has trended since the year began? Meaning can you relate how sales of gasoline and distillate have changed in Q1 and Q2 in relation to the year-ago period but on a same store sales basis? And also, any company specific or market related factors that you think help may explain some of these trends?

Sure, Doug. This is Gary.

Hi, Gary.

Let me give you first of all, on SSA, the demand side of the equation, the first quarter total gasoline demand was up 2.3% on an adjusted basis for, you know, the extra day of the leap year. In the second quarter, we were basically neutral, up 0.8%, but I will call that neutral. July demand has -- we've started to see, as Ken stated, a deceleration in demand as we go into July. We've gone about 70 days or so now with prices above $1.75 to $1.80. And we've started to see a pull-back in gasoline demand. It's a little different on the distillate side in that distillates continues to remain very strong. I think -- I will ask Garry here quickly, he has some same store numbers on gasoline demand and then I'll come back and talk about the merchandise a little bit.

Okay.

Okay. As Gary said, you know, in the second quarter this year, compared to the second quarter last year, we're up about 0.8%, and in terms of the merchandise sales, it is about a 12% --

I was talking about the same store gas -- the same store gas volume.

Volume? I don't have volume. I only have the percentages.

Okay. That's all we have is on the--are percentages, Doug. On merchandise sales, they continued to be very strong. We're up 12% this quarter. We had a double-digit increase in the first quarter as well. And we really bring that down into what we call our elite categories of -- which if you take cigarettes out, we've continued to grow all of our beverage categories, food categories, and what we call other merchandise- phone cards, so on, so forth.

Those numbers look great. And so, just to close the loop, the Q1 same store sales number of 2.3% with gasoline only -- do you have the number for gasoline and distillate through those stores on a same store basis?

Distillate is such a small number.

Okay.

We put our Speedway Truck Stops over into Pilot now, distillate is de minimus.

Okay. Gary, while we have you here, I wanted to ask you one more question, too. The sweet sour differential has obviously been very positive and while, I think that there are a couple of reasons why it should be, I wanted to see if we could get you to comment on some of the things that you guys are seeing in the market which you think may justify the strength, and any views that you'd be willing to share with us as to sustainability would be appreciated as well.

Okay. The sweet sour, you know, continues to widen just at the -- at the end of last week, and comparing the sweet sour on a MARS basis, it widened out last week, this is market data; it widened out last week on a MARS basis to 5.87, which is a big improvement. And you look at, you know, all of the sour cargos that have been available in the Gulf Coast, has continued to widen that out, but the sweet barrel has gotten a little expensive which has widened it out as well.

Sure.

You know, there is continued demand in Asia and in Japan, for -- for barrels, which -- for a sweeter barrel, which continues to, you know, put pressure on the sour--sour barrel. So that is really how we're seeing it, you know, widening out to 5.87 here, is very positive for us when we run about, you know, 60 to 62% sour.

Sure. Great. Thanks a lot, guys.

We'll take our next question from Paul Ting with UBS.

Good afternoon. A couple of questions, please. First of all, the -- your debt is very low at about 20%. CapEx appeared to be somewhat conservative, both in the first quarter and second quarter, I'm talking about upstream specifically. Is your guidance for upstream CapEx still around a billion dollars? And why are you not more aggressive with your upstream capital expense given your low debt and the relatively high strength of prices in the commodities.

Well, Paul, I'll start that and Clarence will probably jump in. You know, we don't basically plan on having $40 oil. A lot of our projects are very large, and long lead time. And so we're not going to be increasing a lot of capital just in terms of near-term price improvement.

Yeah Paul, this is Clarence. I'd just add to that, you know, we have seen the opportunity to reallocate some of our money to nearer term opportunities, and Steve Hinchman has done that probably on the order of 40 to $50 million of reallocation from what might have been a little bit longer term into some short-term opportunities that can take advantage of the current high prices. But as you and I recognize, the current high prices really shouldn't drive your investment activity on mid-term, longer-term projects, which is really what a good deal of our portfolio contains. So as Janet said, I think we're holding the discipline here and, frankly, letting the additional cash flow improve our overall balance sheet which Janet wants to comment on as well.

Right, I'll just remind you that, you know, we are looking forward to closing the minority interest acquisition, you know, hopefully by year-end, and of course, that will be about $1.9 billion of debt we'll assume and then very shortly repay and also $800 million worth of cash and receivables. So, you know, we're not really just sitting on that cash for long-term. We have a near-term use for it you know, by year-end.

I guess part of my question, also, is that your capital expenditure into upstream appeared to be conservative. Does that imply any kind of possibilities into acquisition, in upstream, not just downstream?

No, I don't think it does. And I don't see it as conservative. I think the -- we tend to look at our total program and I think when you look at the upstream, the integrated gas piece, of course, now with the sanction of our LNG project, that expenditure is ramping up, and a full program, an $800 million program in our R & M business; you know our capital program for 2004 is rather robust and when you put on top of that roughly the $3 billion minority interest acquisition and MAP, as Janet's talked about, I'd say we have a rather full capital program this year. I think as you've seen from some of our presentations going forward, next year, 2005, we continue to see a high level of expenditure in MAP, again, around $800 million. We indeed see our upstream expenditures go up, because even as some of our EG investments begin to diminish, we've got major investments in Norway and elsewhere. So our capital program we think is both appropriate and the right size for the projects we have, Paul.

Clarence, that's very helpful. I appreciate it. If I can just ask the second and last question, the guidance for '04 production was 360,000 barrels per day. Given your production increase expected from Equatorial Guinea, do we -- are we still sticking to the 3% long-term production growth over time? And can you give us any flavor as far as to what's going to happen on the '05 production at this point?

Yeah, we're sticking to that, Paul. Let me let Steve Hinchman talk to you about the longer term.

Yeah, Paul, I think that the guidance that we've given in the past has been that, post-dispositions that occurred in 2003, that we'd see a relatively flat production in '04 and '05 and then begin to see a ramp-up as we bring on some of these major projects that we're in the midst of developing now. Such that over a five-year period, ending in 2008, that we would average around a 3% calculated annual growth rate. And that's still true and I think that's what we're seeing in our production volumes this year, and out into the future.

Paul, the production chart we have out there, I don't know if it's on our website, but it's been in all of our presentations and Ken or Howard can get you a copy of it, but it shows precisely that. The flat production in the near term which is basically where our base decline is being offset in the growth primarily in Asia and Russia and it's really in 2006 that you begin to see the impact of the new projects coming in 2006, 2007, 2008; and those really being driven by continued increases in EG and Russia, but also seeing the impact of the Alfheim Cleg development Norway and the Gulf of Mexico developments from Neptune and Percy. So that projection that we have out there is what we see as our forward plan.

And Clarence, you're exactly right, if you go to -- anybody goes to the presentation, section of the Investor Relations site, we have recent presentations posted will have that in there.

Okay. I just wanted to make sure there's no revisions as of now.

No revisions.

Thank you very much, appreciate it.

We'll take our next question from Jeff Dietert with Simmons & Company.

Good afternoon. My question involves the refining and marketing. I was wondering if you could compare and contrast the unit operating expenses first quarter, second quarter? Is that where you're expecting to see some of the benefit from the capital you spent?

Jeff, we don't -- for this, break things down on a unit by unit operating expense basis but I would say where we're really seeing the improvement is on the conversion side of the business. You know, our volume, our total volume of throughputs, both through the crude oil towers, and then the other conversion unit throughputs were up for the quarter. And that's where the benefits were.

Okay. What -- you know, you operated at over 100% utilization. What do you expect to run on a run rate, third quarter, with pretty strong margins?

Well, as Ken said in his statement, for the entire year, we expect to be able to run at historical levels. We had tremendous amount of maintenance and turn-around in the first quarter. Second quarter, we ran more than full out. And if I were good enough to know what the third and fourth quarter cracks are, I could maybe forecast that but we're going to run as hard as we can, and be able to -- we believe we'll be able to run at or a little bit better than historical levels.

Thanks for your comments.

Okay.

And Jeff, just so you know, that for example, in the 2003 -- our crude throughputs averaged about 918,000 barrels per day, to give you an example of where we normally run.

Right. Pretty close to what it was at 98% utilization, third quarter last year?

That sounds right.

Actually, it was a little over 100% third quarter last year, as well. Okay. Thanks for your comments.

And we'll take our next question from Ben Dell with Sanford Bernstein.

Hi, Ken, it's Ben Dell from Sanford Bernstein here.

Good, Ben.

I wonder if I can just touch on three areas. First of all, I wonder if you could give us an update on the Corrib project in Ireland. That seems to have gone on the back burner and I was just wondering where the current progress is on that. Secondly on Angola, in the deep water can you give us an indication of the sort of field size you're seeing and whether you see this as a stand-alone development or a tie-back, given what your understanding of the geology at the moment. And maybe, just lastly, on Russia, can you tell us, do you think access to refining is now a requirement for your projects in Russia? And do you believe that the strength in domestic prices will be sustained going forward?

Phil, why don't you you take Angola and then we can move to production questions.

Sure. Ben, in Angola, we haven't given individual field statistics in terms of sizes. What we're doing is on block 31 in the northern area, which is much more mature or advanced in terms of drilling, the plan is to co-develop all of the four discoveries that we have in the northern area. We do that to optimize the development as-- capital efficiency, as well as the production offtake. So it would be -- at this point in time, it would probably be one production facility, and some optimization of all of the fields coming in at one point in time or various points in time.

This is Steve Hinchman. I will address Corrib. You know, Corrib is comprised of an offshore development- about six sub-sea wells, but it's processing the fluids onshore. And we have just recently, in April, received approval from the Mayo County council granting us access to build a terminal site there. Now, this Mayo county council decision was appealed by the planning board, which will have entertained written submissions, and will likely render decision for us in September or October. And we're pretty positive about getting final approval to move forward with this project sometime towards the end of this year. We would expect then development to proceed in '05, and have first production sometime in early '07, reaching peak production rates of about 8,000 barrels per day. So we are pretty confident at this time about Corrib moving forward.

And I guess on Russia I'd say you really had two questions. One, will the current strong domestic prices maintain themselves, and I guess that obviously is going to be, in part, dependent upon what happens to world oil prices which will help drive that, but I think there are factors that say we should see higher domestic prices than we have in the past. Really around I think the increased export capacity that has been put into place this year, and perhaps a little bit more next year. But, also, I think overall demand in Russia for refined products has gone up. Which again helps strengthen the domestic price.

Your second point was around whether or not access to refineries is now or is becoming a requirement for producers. And there is no question that if you put your domestic allocation of crude through your own refinery and are then able to export product, at world prices without the export duties that you've got on crude, and the export limitations you have on crude, that is a huge advantage. Having said that, I'm not sure that owning refineries in Russia is necessarily the only solution. And I think what we certainly are exploring is what other options there are to ensure that independent-type producers, like Marathon in Russia, and there are a number of smaller Russian companies in the same situation we are. That, indeed, there is adequate incentive for those producers to continue to grow their production and provide the diversification of supply that that country needs. So it certainly is an issue. We think that there are a number of solutions out there. Owning a refinery is one solution. We don't necessarily see that as the best solution.

Great. Thanks very much.

We will take our next question from Gene Gillespie with Howard, Weil.

Good afternoon. Just one question. And that relates to can you bring us up to date, Clarence, on progress or where you stand related to the potential sale of your assets in the Powder River Basin.

Gene, there's really, at this point, nothing to update on. We are going through the sale process as we have earlier stated. The data rooms are open. I think there are companies in the data room this week as we speak here, and it is our expectation we'll have bids -- August 26, I was going to say the end of August, but there's a specific date. So I would just say stay tuned, Gene.

All right. Thank you.

We'll take our next question from Mark Gillem with Benchmark Company.

Guys, good afternoon I had a couple of specific things and then a few general ones. I wonder if you had a number for the hedging gains or losses in the integrated gas segment.

I have that, if you would like. It was $2.3 million this last quarter. And 1.3 of -- pardon me 1.5 of that was mark-to-market.

Is that a gain or a loss, Ken?

Gain on the mark-to-market and a gain of 2.3 overall.

And the foreign exchange gain or loss buried in the interest number?

Just under $2 million.

Gain or loss?

Loss.

And that's pre-tax.

All those numbers are pre-tax, yes, Mark.

Although more slightly more general in nature, I wonder if you could update me just a little bit on the Gulf of Mexico drilling plans and program for the rest of the year and also with respect to KMOC activities in Russia.

Yeah, Mark this is Phil Behrman. To give you an update on the Gulf of Mexico plans right now. Near term, we don't see any deep water wells going. We have one well that we won't put any money into but others are going to pay for, which will spud in the late third quarter, and then we have some consideration for some shelf wells at the fourth quarter of this year.

And regarding Russia, Mark, we've drilled about 40 wells so far this year. We will drill a total of a little over -- around 60 wells total for the year. And we've had some very encouraging results over on the Camanoy Field where we've seen 60% more sand than what we expected. And we're just launching out a -- off a frac program, we're going to frac around 25 wells in this first package over there, where we're putting in some new design-- new frac design, a little more modern equipment and the early results we're seeing from those frac programs are very encouraging where we're bringing on wells between 300 and 600 barrels a day. So-so far, we're pretty much on track to the expectations that we've set in being able to produce around 18, 19,000 barrels a day out of Russia this year.

Okay. Could I just follow up with Phil for a sec. I didn't hear a Neptune appraisal as part of the drilling program.

Neptune appraisal is also under consideration. But really nothing's been determined at this point in time with the partners. They're looking really at development scenarios, but an appraisal well is also a factor.

Okay, thanks a lot, guys.

And we will take our next question from Jennifer Rowland with J.P. Morgan.

Good afternoon. I have two questions for you. First, on the European gas realizations, it looks like your differential widened a bit this quarter, had roughly a little bit over $1 last quarter, widening out to over $2 this quarter. I was wondering if you could just comment a bit on what might be causing that widening.

We have Pat Kunz is on the line as well and he's our Vice President for Crude Oil and Natural Gas Marketing. Pat can address that question.

One of the things going on in the second quarter, we do have lower volumes as well as lower prices in the U.K., and that's a function of seasonality. When you mentioned differential, I assume you're referring to the previous quarter?

I'm just looking at basic differentials putting Brent on a gas equivalent then taking a differential to that. The last quarter, I had $1.08 and this quarter the implied difference is $2.02.

I guess I'm struggling to see the differential, but perhaps we can get offline and I can get with you to more specifically deal with your question.

Okay. I will follow-up on that one later. My second question, relates to CapEx on the downstream. It looks like the second half of this year will be pretty heavy spending relative to what we saw in the first half. Yet we've talked -- I heard you say that the run rate should be pretty solid and I don't think have you any major turn-arounds planned for the second half of this year, so I'm just wondering where that heavy capital spending -- where is that going to be occurring, and is it not going to be impacting operations?

Jennifer, the balance of the spending for the year, the majority would be on the clean fuel side, finishing up a little work on the gasoline, but the predominant piece being on the clean diesel; that needs to be ready by July 1, 2005. Plus we are working on the Detroit expansion project, which is moving forward very strongly, and lastly, is our Speedway SuperAmerica CapEx. We generally will do our remodels, rebuilds in the summer time frame, because of better weather conditions. So you'll see a little pickup in the SSA CapEx here, second and third quarter.

Okay.

Excuse me, third, early fourth quarter.

Great. Thank you.

Uh-huh.

[Caller Instructions] And we'll go next to Jay Saunders with Deutsche Bank.

Thanks. Just a couple of questions. First on EG liquids, run rate the rest of the year from that 15, I guess part of that means -- part of that question is -- is 2=B, the timing of 2-B? And also the second question is exploration expense on the international side, the 30 to 60 million, where is that coming from, is there any detail that you can add on that?

This is Steve Hinchman. On -- regarding EG, you know, we have two distinct projects, one is a condensate expansion and the other is a new gas plant for processing LPG liquids. And the condensate expansion is-- we're turning the first compressor on this weekend into injection and we would expect, then, to have the second compressor which is really the final link in this, in this first phase project, by the end of August. At that particular time we'll ramp up our condensate production to around 54,000 barrels a day gross and then our LPG production will remain constant around 3,000 barrels a day. And then in the first half of next year, we will complete our phase 2-B project, and then we'll ramp-up that project, sometime in the first half of next year to around 16,000 barrels -- or 20,000 barrels a day of LPG product; and then that'll also extract another 4,000 barrels a day of condensate. So when you add the two of those together, we will produce around 79,000 barrels a day at the completion of phase 2-B.

Gross.

Gross.

Okay. What did you say, mid-August, though on the second compressor?

Yeah, mid to late August, we'll have the second compressor turned to injection.

Great. Okay. Thanks.

Jay, this is Phil Behrman. To give you a little bit more color on the exploration expense. As you know, we're currently drilling the Crimson well in the international area. We're also currently drilling the Cola well -- pardon me the Crimson well is in Nova Scotia. We're currently drilling the Cola well in Angola, block 32. We plan spuds in 3Q. And those will both reach TD in 3Q. Additional spuds in third quarter will be the Gardenia well in Equatorial Guinea, an exploration well on block 31, as well as a potential additional exploration well on block 32. And because of the uncertainties on the timings of when these wells may TD is why we gave, number one, the size and number of wells and the uncertainty in the timing is why we gave the range of exploration expense as you saw, 30 to 65 million.

So you may see three in Angola, block 31 and 32?

That's possible.

Okay. All right. Thanks.

And we'll take our next question from Paul Cheng with Lehman Brothers.

Hey, guys. Several quick questions. Russia, the excise tax is going to increase pretty sharply in August, what kind of impact may be on you guys, in a dollar amount?

The impact really-- I'm sorry, this is Steve Hinchman. The impact really above $25 per barrel Euros price becomes pretty minimal, Paul. Because it really gets taken out with the mineral extractions tax. So there's not much impact above 25. I don't have a strict percentage. But we don't see that as -- we see it as relatively minimal impact on our nets.

Remember, Paul, we only export 35%, and it is not -- it is the export duty I think you're referring to that goes up, so as Steve says, it's already pretty onerous, above, I'm trying to remember, it's $25 Euros; it's a pretty onerous hit already. But the one that is I think the most impactful is the mineral extraction tax that really is calculated on the full Euros export price, and yet is applied to all the barrels, and if 65% of the barrels are being sold at the domestic price, that is the -- that is the issue that obviously we're most interested in.

Uh-huh. And you don't see from a dollar amount that it's going to have any meaningful impact on you guys?

It will have some impact, Paul, but it's not a major impact.

Okay. Ken, sorry, I think I missed it, what is the third quarter financing charge that you are projecting now?

That interest and other financial cost, 45.

45? Okay. I'm wondering, maybe Ken or Steve, do you guys have a full-year target in both U.S. and international for the unit lifting cost and the DD&A?

Yeah, for total, total worldwide production, Paul, I didn't quite hear.

No, I'm saying that for the -- in terms of the unique costs, the costs have been up in the second quarter pretty substantially on both the lifting costs and the DD&A. I'm wondering, -- in some of them there may be a one time usually due to the higher energy cost or the impairment charge and all that. I'm wondering, do you have an expectation or a target for the full-year cash lifting costs and the DD&A charge in both U.S. and international?

Yeah, we -- the domestic price is averaged for the first half of the year, on cash lifting cost, it's averaged around $2.69. And we had given guidance earlier that that would -- it would average for the year around $2.80, and we think that's -- that's a very achievable expectation there. On international, our cash lifting cost, and this is the field level controllable cost is seeing a little pressure, primarily driven by the weakening dollar, and the foreign exchange, and due to some extra pension costs in our U.K. operations. And so we expected that to be probably on the order of $2.80 and we'd expect now that that is going to about 18 cents higher, around $3 per barrel. On the lifting cost side.

On the DD&A, and this would be the real -- the equity DD&A, so it would exclude asset retirement obligations, FAS 144s, or canceled or impaired unproved properties, in domestic we see an average DD&A for the year of about $5.03 through the first half of the year, and we expected the DD&A domestically to be around $5 per barrel. And on international side, our average through the first half of the year is about $5.60. Now, we expected the international DD&A to be around $5.40 and we expect now that that'll probably run a little higher, probably around this $5.65 for the year, which will bring our worldwide production DD&A to around $5.25 to $5.30.

Again, this would exclude ARO, and it would exclude FAS 144s canceled and impaired, unproved property. On the field level controllable side, we would expect that our total worldwide production would average around $2.90 a barrel.

And Ken, on the -- if we assume the oil and gas prices stay where they are for the remainder of the quarter, as far as the refined -- the refined product margins, can you give us that as of the -- based on this price, what the hedging loss may be on the oil and gas side, as well as in MAP?

I will just -- Paul, I will just -- haven't ran the numbers. On the upstream side we have 44,000 barrels of crude oil, 29 domestic, 15 international, with a collar that peaks at about 29.67 or 29.70 a barrel. So I just have to do the math on that and I don't have that off the top of my head. But we can do that. And --

And Ken, I'll take the MAP side. As you had stated in your presentation, we get the majority of the cracks we sold forward were in the first two quarters. We just have a little on that's in the queue. So we would probably say it would be flat to a million or two dollars negative, but I'd call it flat. Gary, I've got 5 million barrels at 7.24 remaining.

Right. Correct. But we've already written-- this is Gary Peiffer. We've already mark-to-market most of that to the end of the June 30 date anyhow so the extent there has been very little change from June 30 to now or the end of the quarter, that'ss the real key of how much we'll book.

You know, if anything right now, it would be a little bit positive, based on what we've already mark-to-market. But that's why I say it is pretty much flat based on today's numbers.

Perfect. Thank you, guys.

And we'll take our next question from Fred Lueffer with Bear Stearns.

Good afternoon. Just a quick question. What quantity of reserves in Equatorial Guinea do you expect to book this year with the final investment decision on LNG?

This is Steve Hinchman. Yeah, with the FID for the LNG project we book around 84 million barrels equivalent. But we also see some additional performance adds in EG, too that we'd expect to book. So I think we will exceed that amount for -- in 2004. And we also have the Alfheim project that we expect to get PDO approval on this year. So I think we had given some guidance of around 244 million barrels of total reserve bookings in 2004. And I think we feel real solid about around 227 million of them -- of those reserves today, and the ones that are sort of on the bubble for us right now are Corrib and Cleg because we expect PDO approval on those either in the fourth quarter or the first quarter; so one of those could roll over into the second quarter, but we'll still be -- we'll still be very close to the 244 million barrels of reserves.

Uh-huh. And Steve, you get -- you will book more LNG reserves I guess as we go through the next two years, right?

No, we're looking at -- we're booking basically-- the contract quantity is what we will book initially. In terms of reserves for the LNG. Now, we are aggressively looking for additional LNG opportunities in order to both fill up train one and look to build a train two. So -- but the 84 million would represent the contractual obligation on the gas.

Yeah --

Fred, the other thing is, we take the conservative approach here to the extent that there is future compression required to meet the contract needs, we don't book those reserves until sometime in the future when we appropriate that compression. So I think we've taken a conservative approach here in terms of the bookings.

All right. Great. Thank you.

And we'll take our final question from Mark Gilman with Benchmark and Company.

Guys, do you have a capitalized interest number for the quarter?

We do, Mark. Give me just one second here and I'll get that for you.

Maybe while you're looking, did you adjust at all your expectations regarding the Alfheim project and the 50,000 a day to include the incorporation of Cleg?

The 50,000 number is our best estimate of the combined production from the two right now, Mark, and capitalized interest in the quarter was right at $7 million.

Okay. And just to check my arithmetic, which is probably faulty, but to get to 360 for the full year on a worldwide production basis, you need about 380, 385 in the fourth quarter? Is that what you're looking for?

Yeah, around 389, your math is pretty good.

Alrighty. Thanks a lot, guys.

Operator?

It appears there are no further questions at this time. I would like to turn the conference back over to our speakers for any additional or closing remarks.

Okay no, operator, I'd just like to say thanks to everybody for listening in. And we will be with you again next quarter, thank you very much.

That does conclude today's conference. We thank you for your participation. And you may disconnect at this time.