馬拉松石油 (MRO) 2002 Q3 法說會逐字稿

Thank you for holding, ladies and gentlemen, and welcome to the Marathon Oil Corporation third quarter earnings conference call. During the presentation, all lines will be on listen-only mode. There will be an opportunity to ask questions and instructions will be given at that time. I thank you for your attention and I now turn the conference time over to your host, Mr. Ken Matheny.

Good morning, everyone. I, too, would like to welcome you to the third quarter 2002 earnings review teleconference for Marathon Oil Corporation. Available with me on this call today from Marathon Oil are: Phil Behrman, Senior VR of Worldwide Exploration; Steve Hinchman, Senior VP of Worldwide Production Operations; and John Mills, Chief Financial Officer. Also with me from Marathon Ashland Petroleum are Gary Heminger, President and Gary Peiffer, Senior Vice President of Finance and Information Technology.

I will cover the high points of Marathon’s third quarter and provide guidance for the fourth quarter. Steve Hinchman will address portions of production operations. Phil Behrman will provide an overview of our exploration program. And then we will open the call up to questions.

Approximately two hours after this call ends, these prepared remarks will be placed on the investor relations’ portion of our website. They will be in a downloadable format and remain on the site for two weeks.

Our remarks today will contact certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2001, and in subsequent Forms 10-K 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.

The third quarter of 2002 was a good operating and financial quarter for Marathon’s upstream business. Downstream had a good operating quarter, but its financial performance was significantly below the second quarter as refining and marketing margins declined from second quarter levels.

Net income adjusted for special items with $149 million or 48 cents per share. This compares to adjusted net income of $193 million or 62 cents per share in the second quarter. Special items in the third quarter totaled a negative $62 million after-tax and consisted of a $7 million loss on the early retirement of debt, a $61 million one-time retroactive adjustment related to the supplemental United Kingdom tax, and a $9 million loss for a contract settlement. These were offset by a $15 million gain on the disposition of production properties, primarily in the San Juan Basin of New Mexico.

Looking at our upstream segment, third quarter 2002 operating income totaled $250 million or $7.08 per barrel of oil equivalent. In the second quarter, it was $262 million, or $6.79 per boe. Third quarter income of $250 million was negatively impacted by derivative mark-to-market losses of $18 million versus gains of nearly $19 million in the prior quarter and $6 million in the third quarter of 2001.

Now focusing on domestic upstream operations. Third quarter operating income was $187 million. That’s $8.45 per boe versus $189 million or $8.33 per boe in the second quarter. The decrease is a result of lower derivative gains, lower gas prices, and lower liquid hydrocarbon and gas volumes, mostly offset by reduced exploration expense and higher liquid hydrocarbon prices.

Our average domestic realized price was $24.01 per barrel, up $1.52 from the second quarter compared to the $1.98 per barrel increase in the prompt NYMEX posting average. Our domestic crude oil realizations were in line with the WTI change, while NGL prices under performed WTI in the quarter due to weak seasonable demand.

Our third quarter average domestic gas price of $2.75 per million cubic feet increased 24 cents from the second quarter in line with the 23 cent decrease in NYMEX Henry Hub average. And the average bid week price decline of 22 cents per MCF in the second quarter.

On a barrel of oil equivalent basis, domestic revenue averaged $20.30 in the third quarter, slightly above the $20.25 in the second quarter. Derivatives related hedges and mark-to-market impact in the third quarter was a positive $3 million or 14 cents per boe, compared to a gain of $24 million or $1.04 per boe in the second quarter. Gains in both periods were primarily related to our Powder River Basin derivative activity.

Domestic exploration expense was $4 million or 20 cents per barrel of oil equivalent. And that compares to $32 million or $1.39 per boe in the second quarter.

All other costs in the third quarter totaled $11.85 per boe up to 28 cents per boe versus the second quarter. And that is all a direct result of lower volumes. In absolute terms, all other costs were flat with the second quarter.

Domestic liquids production came in at 122,000 barrels of liquids a day, down 5,000 barrels a day versus the second quarter, nearly all in the Gulf of Mexico as a result of weather-related downtime.

Natural gas production of 710 million cubic feet a day was down 24 million cubic feet a day, almost evenly split between weather-related problems in the Gulf of Mexico and the disposition of properties in the San Juan Basin.

On a barrel of oil equivalent basis, overall third quarter daily domestic production was down about 9,000 barrels of oil equivalent per day compared with the second quarter average. We’re pretty much right on the guidance that we gave on this call in July.

Turning to the international upstream sector, segment income was $63 million or $4.70 per boe compared with $73 million or $4.56 per boe in the second quarter.

Our discussion regarding international price changes includes a restatement of second quarter 2002 prices to exclude certain costs, primarily shipping and handling to allow reporting of gross revenues.

Our average foreign liquids price of $26.20 per barrel was up $2.38 sequentially, reflecting an improvement in the data Brent and [indiscernible] markets which serve as a pricing reference for much of our international production.

The average gas price of $2.37 per MCF was down 12 cents from the second quarter, primarily a result of normal seasonal price declines in the UK for most of the quarter. On a barrel of oil equivalent basis, revenue averaged $19.85 versus $19.80 in the second quarter. Exploration expense of $25 million was up $13 million compared to the second quarter to $1.90 per boe. Derivative related mark-to-market valuation losses were $21 million or $1.60 per barrel of oil equivalent. These losses were entirely related to two long-term gas sales contracts related to Brae that were reviewed in the first quarter. This compares to a loss of $4 million or 27 cents per boe in the second quarter.

All other costs total $12.93 per boe, down $2.16 per boe versus the second quarter. Operating expenses and BD&A were substantially lower primarily as a result of lower liftings at Brae and abandonment expense was $12 million lower, reflecting the Canadian abandonment charge that we took in the second quarter.

International liftings for the third quarter came in less than expected at 67,000 barrels of liquids per day. That’s 29,000 barrels a day lower compared to the second quarter, primarily reflecting lower than expected liftings at Brae and Gabone.

Gas sales came in at 458 million cubic feet per day, down 16 million cubic feet per day over the second quarter and lower than our guidance for the quarter. The variance was primarily due to seasonally lower gas sales in the United Kingdom, increased gas injection into storage in Ireland, partially offset by increased production at Equatorial Guinea.

Worldwide oil and gas sales were 384,000 barrels of oil equivalent per day, down 16,000 barrels of oil equivalent per day versus the guidance we gave in July. Again, primarily a result of lower than expected liftings in the United Kingdom and severe weather in the Gulf of Mexico.

I will now turn the call over to Steve Hinchman to address some of our more significant production activities.

Thank you, Ken, and good morning. As Ken discussed, worldwide production sales for the third quarter were down from the second quarter primarily due to the lower than expected liftings in Brae and Gabone. Actual production available for sale was only slightly below the second quarter due to tropical storm Hanna and Hurricane Isabel in the Gulf of Mexico. Hurricane Lilly’s impact will be felt in the fourth quarter. Although, we do consider weather-related downtime in our production forecast, this year’s activity was unusually high.

Now, turning to Marathon’s development projects in the United States. In the Gulf of Mexico, Petronius averaged a net 20,000 barrels of liquid per day and 31 million cubic feet of gas a day in the third quarter, down from the second quarter and again, primarily to tropical weather in the Gulf. Petronius continues to exceed our expectations. Additional well locations have been identified and drilling activity will continue to the middle of 2003. Petronius should average about 27,000 barrels per day annualized for 2002.

Also in the Gulf of Mexico, Marathon 50 percent owns the Camden Hills project came on production on October 11. It is currently producing 50 million cubic feet of gas a day gross from the first of two wells and is expected to reach a peak production of 11 million a day gross later this month.

Camden Hills sets the record for production from ultra-deep water at a depth of 7,209 feet. It’s an outstanding technological achievement in such a new industry benchmark in ultra-deep water.

Cobed natural gas production in the Powder River Basin averaged 90 million cubic feet per day net in the third quarter compared to 75 million cubic feet per day net in the second quarter.

We continue to be encouraged by the performance in the House Creek area, Big George coal development, which is increased by 9 million a day gross this year. We also are encouraged by performance in Nevada area development focused on Anderson Coal, where we’ve increased gross production by 9 million a day this year.

In the Powder River Basin, we’re focused both on production growth and margins. Since the beginning of the year, we have reduced our controllable production costs per well by 50 percent and reduced our development cost per well by 25 percent.

We also -- to protect the revenue side, through our head strategy and transportation capacity on the Trail Blazer pipeline. The head strategy assures the minimum price without giving away much upside. And our firm transportation on Trail Blazer provides protection against the Rockies volatile basis differential.

Although we expect the EIS records of decision to be issued in February of next year, Marathon is in a position to fully implement its 2003 drilling plans without the federal acreage depended upon the EIS.

The Powder River Basin has exposed Marathon to 1.6 net TCS of natural gas, with both cycle finding and development costs of about $1 per MCF.

Turning now to international operations, the UK Atlantic Margin [indiscernible] Development continues to exceed expectations. Total [indiscernible] production available for sale in the third quarter was 30,000 barrels a day. Gas deliveries averaged around 10 million cubic feet per day. For 2002, we’re projecting 32,000 barrels of oil equivalent per day.

Key factors to this success include gas exports from [indiscernible] to [indiscernible]. These sales not only provide us an additional source of revenue, but also improve production reliability by reducing dependency on gas re-injection. And our [SPSO] vessel reliability has been outstanding, averaging over 97 percent uptime. And we continue to discover additional near-field development opportunity. We’ll have a three to four well development program in 2003.

In Equatorial Guinea, we have settled in since taking over operations earlier this year of the Alba Field and associated condensate and LPG processing facilities.

Our operations are currently producing record high liquid hydrocarbons at a gross rate of nearly 22,000 barrels per day. And gas sales to the methanol plant of around 130 million cubic feet per day. Net sales for the year are projected to average 16,000 barrels of oil equivalent per day.

An aggressive expansion plan to increase gas recycling and expand condensate and LPG production has been approved by partners and submitted to the government. The government has approved the first phase of the expansion, which will increase gross gas production from 250 million cubic feet per day to 800 million cubic feet per day, an increase condensate production from 17,000 barrels a day to 46,000 barrels per day.

Gross gas sales to the methanol plant will remain at about 120 to 130 million cubic feet per day with remaining dry gas being re-injected into the formation for future monitorization. This phase will be completed in the fourth quarter of 2003.

The second phase of the expansion will increase gross LPG recovery from 2,700 barrels per day to 16,000 barrels per day and it will be completed in mid 2004. We expect governmental approval of this phase before the end of the year. Upon approval of this expansion, thereupon net proven reserves in Equatorial Guinea will total approximately 300 million barrels of oil [indiscernible]. The full cycle finding and development cost for these reserves is estimated to be $4.60 per boe.

Feasibility studies are currently underway to [indiscernible] the three TCF of re-injected dry gas from Alba Field, as well as, other stranded forecasts within 100 kilometers of [indiscernible] Island.

I’ll now turn it over to Phil Behrman, our Senior Vice President of Exploration.

Thank you, Steve. Turning to exploration, Marathon participated in the recently announced Plutao Well in about 6,600 feet of water on Block 31, which is our first deep water discovery in offshore Angola. We hold a 10 percent interest in this block. The next well to be drilled on Block 31 is a [indiscernible] prospect which is expected to spud in late fourth quarter and is in about 6,000 feet of water. This prospect is adjacent to the Plutao discovery. Current plans call for an additional prospect to be drilled in the first half of 2003 on this block.

The first wildcat on Angola Block 32 is on an [indiscernible] prospect. This well is located in a water depth of 4,760 feet was spud early this week and should reach total depth around year end. We have recently increased our working interest in Block 32 from 10 to 30 percent.

Turning to offshore Nova Scotia, we recently announced that we encountered approximately 100 feet of gas a day in the Annapolis G24 well. We operate and hold a 30 percent working interest in the Annapolis block. This initial discovery well is located in about 5,500 feet of water, was drilled to a total depth of 20,282 feet, and was suspended for possible re-entry at a later date. The results from this well are encouraging and prove this deep water gas system works. To prove a commercial development, however, more drilling will be required. We will be reprocessing seismic data shortly and have 2003 drilling plans for the Annapolis Block. We will also be acquiring new seismic data over the Empire and Portland Blocks in 2003.

Last quarter, we announced the Neptune numbers to reappraisal well results in Atwater Valley Block 617 within the deepwater Gulf of Mexico. As a follow up to this success, we are currently drilling the Kansas prospect on Atwater Valley Block number 489, which is on the same structural trend about nine miles northeast of Neptune and located in approximately 4,500 feet of water. This well should reach total depth in the fourth quarter, the hold 33 percent working interest and operator of the Kansas prospect.

In addition, we will participate in a Neptune number 4 appraisal well on Atwater Valley Block 473, which will test the northern part of the structural trap. This well is expected to spud in later November or early December.

Lastly, at the end of fourth quarter, we will commence drilling on the [Kimoto] prospect on Atwater Valley Block number 529. This prospect is five miles northwest from the Neptune discovery. We also operate [Kimoto] and will hold a 33 percent working interest in this prospect.

In addition to drilling on the Atwater [indiscernible] belt, Marathon will spud the Barracuda prospect on DeSoto Canyon Block 927. This will be the first modern deep-water well in the eastern Gulf of Mexico and is expected to spud in December. The well is located in about 8,500 feet of water and Marathon has a 50 percent working interest and is operator. Marathon plans to drill or participate in three additional wells in the eastern Gulf of Mexico in the 2003 through 2004 timeframe.

Lastly, Marathon has participated or drilled three significant discoveries in the Anadarko Basin core area. The Snowball 1-28, [Irwin] 2-5, and [Della] 4-9 wells have been tested at initial rates of 35 to 40 million cubic feet of gas per day and are currently on production. Marathon holds a working interest between 25 and 38 percent in these wells.

Including development activity, Marathon has drilled 23 wells to date in our Anadarko program with an overall success rate of over 90 percent. A key to Marathon’s success is our proprietary depth migration seismic data. We plan to drill five to six more wells in this trend during the remainder of 2002. In 2003, we plan to keep activity levels relatively constant.

Turning back to worldwide exploration, Marathon plans to increase exploration drilling activity from 14 wells in 2002 to 26 wells in 2003, while keeping our total spending relatively flat. We will maintain activities in our deep water trends with the majority of the increase in drilling activity expected to occur in the [indiscernible] area in Norway, in around the Alba field in Equatorial Guinea.

I will now turn the call back to Ken Matheny.

Thank you, Phil. We’ll move on to progress on our integrated gas strategy. On February 28, we announced plans for a liquefied natural gas -- regasification plant near Tijuana in the Mexican state of Baja, California. The complex would supply natural gas and electricity for local use, as well as, for export to Southern California. In August, we submitted our permit application for the term loan which received technical support from the CRE and has now proceeded to the pre-defined period for public consultation.

On February 28, we also announced plans to lead an initiative for a new North Sea natural gas pipeline called Symphony designed to provide Norwegian gas for the UK market and optimize the use of our existing Brae infrastructure.

We commenced the open season nomination process for gas transportation on May 14 and closed on October 16. The positive feedback and the results of the open season validate the need for new pipeline infrastructure in the North Sea. And based upon market support and interest shown during the open season, Marathon will continue discussion with parties in evaluating the best transportation alternatives to bring Norwegian gas to the UK utilizing the Brae infrastructure.

During the third quarter, Marathon acquired long-term L&G delivery rights at Alba Island, Georgia. Under terms of the agreement, Marathon can supply up to 58 BCF of natural gas as L&G per year for a minimum of 17 years at the Alba Island L&G re-gasification terminal. The agreement enables Marathon to capture value from the expected growth in L&G imports in the United States, while also providing options to commercialize significant natural gas resources in Equatorial Guinea.

Now, let’s talk about downstream results. Reportable R&P segment income in the third quarter was $108 million compared with the second quarter’s $211 million. The reduction in segment income was primarily attributable to three items. First, the Chicago 321 crack spread averaged $5.02 per barrel in the third quarter versus $5.39 per barrel in the second quarter. And third quarter 2002 Gulf Coast crack spreads averaged $2.98 per barrel compared with $3.66 per barrel in the second quarter. Secondly, lower crack spreads combined with rising crude oil costs in a relatively weak demand environment compressed wholesale margins compared to stock prices in the quarter. And lastly, refinery runs were down 42,000 barrels per day from the second quarter.

Our refining and wholesale marketing margin in the third quarter was 3.9 cents per gallon versus the second quarter level of 5.2 cents. The gross light product margin for our retail business, Speedway Super America, was 10.6 cents per gallon in the third quarter as compared to 11.2 cents per gallon in the second quarter.

Refinery runs averaged 931,000 barrels per day in the third quarter, just under 100 of weighted capacity compared with 973,000 barrels per a day or 104 percent of weighted capacity in the second quarter.

The in transit [indiscernible] impact was a negative $15 million in the third versus a $2 million negative in the second quarter.

Merchandise sales and margins have been a key focus for MAP the past several years and the results have been outstanding. Merchandise sales were up 6.3 percent year-over-year and were up more than 5 percent from the second quarter. Margins increased slightly over the third quarter last year, resulting in gross merchandise margins of a little over 23.26 percent, or $150 million for the quarter.

Total refined product sales averaged 1.387 million barrels per day in the third quarter, up about 3 percent from both the second quarter and from a year ago.

In the third quarter, MAP received final approval and began construction on the Cardinal Products Pipeline. The line will extend from Kenova, West Virginia, to Columbus, Ohio. It will have a design capacity of 80,000 barrels per day, is expected to move -- initially move about 50,000 barrels per day over [indiscernible] petroleum into central Ohio. And the line is expected to be fully operational in the first half of 2003.

Marathon’s other energy-related business had operating income of $29 million in the third quarter versus $20 million in the second quarter. The primary reason for the improvement was the [indiscernible] Methanol Plant which was fully operational in the third quarter and average methanol prices were up nearly 24 percent, over $185 per ton.

That brings total segment income in the third quarter of 2002 to $387 million, down 22 percent in the $493 million in the second quarter, primarily a result of weak refining and marketing margins versus the second quarter.

In the unallocated category, administrative expense was $42 million in the third quarter and that compares with a second quarter total of $39 million. Net interest expense was $75 million in the third quarter versus $76 million in the second quarter.

Our preliminary cash adjusted debt decreased by $190 million during the third quarter to $4.4 billion. Our cash adjust to debt to capital ratio at September 30 is 46.5 percent, and that’s down from 48 percent at the end of June.

As expected, the UK formally enacted a 10 percent supplemental corporation tax on profits from oil and gas production. A one-time non-cash deferred tax charge of $61 million was taken during the quarter that was treated as a special item.

Marathon’s tax provision, excluding the deferred tax charge, was $84 million for the third quarter reflecting an effective tax rate of 35 percent, lower than the guidance we gave last quarter primarily as a result of lower state taxes associated with downstream operations. For the fourth quarter, we again anticipate our effective tax rate should be about 38 percent.

Third quarter preliminary cash flow from operations, excluding working capital changes, was $503 million or $1.62 per share. Capital spending was $383 million in the third quarter. And for all of 2002, excluding acquisition, our capital and exploration spending budget, including 100 percent of MAP, is projected to be $1.8 billion. The mix is 51 percent upstream and 45 percent downstream. If you adjust that 2002 capital spending to include only Marathon 62 percent ownership share of MAP, capital spending would be 61 percent upstream and 34 percent downstream.

Total mark-to-market derivative and hedging activity for the upstream and other energy related business was a net loss of $16 million pre-tax in the third quarter, consisting of $3 million of gains in the Powder River Basin and other natural gas and crude oil hedges offset by a mark-to-market loss of $21 million on two of our long-term L&G -- pardon me -- on two of our long-term gas contracts related to Brea, and 2 million of gains in other energy related business.

Our approach to hedging is both opportunistic and highly selected and geared toward minimizing downside risk. 2002 hedge related to the Powder River Basin remaining in the fourth quarter is an average of 163 million cubic feet per day and an average price of $4.36 per annum. Approximately 63 million cubic feet per day currently qualifies for hedge accounting treatment and the remaining 100 million cubic feet per day is mark-to-market.

Earlier this year, we entered into zero cost collar strategies on natural gas production during 2002. We currently have remaining 200 million cubic feet per day for October through December, where we sold the upside about $4.48, a lock in of minimum price of $3.19 per million cubic feet. Again, this position is mark-to-market each quarter.

On the liquid side, we have hedges of approximately 59,000 barrels per day of 2002 equity crude production through December. Again, using the zero cost collar option strategy. This represents about 30 percent of our total worldwide crude production. Pardon me. These hedges have been structured such 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 and $23.34. Market price when prices are between $23.34 and $29.35 and we [indiscernible] upside above $29.35. Again, this position does not qualify for hedge accounting and is mark-to-market each quarter.

Looking to 2003, we’ve hedge a substantial portion of our anticipated 2003 Powder River Basin and other gas production, utilizing zero cost collars with an average floor price of $3.64 per MCF and an average ceiling price of $4.64. These contracts cover approximately 147 million cubic feet a day and should qualify for hedge accounting.

On the liquid side, we have entered into a number of contracts on 2003 equity crude oil production, again using the zero cost collar option strategy. To date, we have hedged on average approximately 25,000 barrels per day with an average floor price of approximately $23.35 and an average ceiling price of approximately $28.90. Like our 2003 gas contracts, these should qualify for hedge accounting, eliminating most of the mark-to-market volatility we have experienced during 2002.

Finally, I want to make a few observations about the fourth quarter and the full year 2002. On the domestic upstream side, we expect liquids production to be down slightly versus the third quarter to about 115,000 barrels of liquids per day. Gas production should be up to about 775 million cubic feet a day. The NYMEX prompt average price so far in October is up $1.27 per barrel versus the third quarter average, while Henry Hub gas prices are up nearly 85 cents per MCF. Domestic exploration expense is anticipated approximately $25 to $35 million.

On the international upstream side, liquids production in the fourth quarter should be up relative to the third quarter to about 85,000 barrels of liquids a day primarily due to balancing our lifting positions. We expect gas production to be up to about 520 million cubic feet per day primarily due to seasonal changes in the UK.

Based on what we’ve seen so far in October, foreign oil pricing seems to be following the domestic pattern and international exploration expense is anticipated to be approximately $15 to $25 million.

On a barrel of oil equivalent basis, we expect fourth quarter worldwide production therefore to be up sequentially to approximately 415,000 barrels of oil equivalent per day. For all of 2002, we expect production to be down from our average 2001 production to approximately 410,000 barrels of oil equivalent per day. Reduction from our previous guidance of 420,000 barrels per day is primarily the result of an unusual amount of severe weather in the Gulf of Mexico and start-up and performance delays at the [indiscernible] Development in Norway.

On the downstream, [indiscernible] in October have averaged over $8.25 per barrel in Chicago and $5.50 per barrel in the Gulf Coast. We expect crude oil costs to continue to be up as a result of the continued tightness in sweet and sour spreads. And the pattern we have seen to date, while easing, is not significantly different than what we experienced in the third quarter.

As far as the other energy income line, we expect fourth quarter income to be approximately $25 million, administrative costs should be about $40 million, and net interest expense should be about $76 million.

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

To ask a question, please press a 1 followed by a 4 on your touchtone phone. To retract your questions, press a 1 followed by a 3. All questions will be taken in the order they are received and you’ll be placed back into the conference following your question. Once again, that’s a 1 followed by a 4.

And the first question comes from Mr. Doug Terreson from Morgan Stanley. Go ahead please.

Hey, Ken. How are you?

Good morning.

Excuse me. I have a couple of questions. First is a clarification. In international E&P, was the $21 million contract at Brae included in the $63 million of operating income or was it the pre-tax amount related to the $9 million after-tax number that you disclosed on the first page. Is that the same thing?

No, no. They’re different items. The $21 million, Doug, is the mark-to-market adjustment on those two gas sales contracts in the UK.

Right.

They are included 100 percent on the pre-tax basis in the $63 million segment income.

Okay. Another clarification. Can you repeat those wholesale refine margins that you just gave us. Look at the quarter-to-date numbers and also, your wholesale numbers for Q2.

I’ll repeat what I had and then, Doug, I’ll ask you to repeat the second part of it after I do it. I didn’t quite hear it.

The average that we’ve seen so far in October, you mean?

Yes.

Chicago, 8 and a quarter; and 554 in the Gulf Coast. Those are through October 22.

And the comparable numbers in Q2 were?

Comparable numbers in Q2 -- bear with me for a second. 502 and 298.

Okay. Let me just ask you one other question, and these are more of a strategic nature. The question has to do with Alba Island and also with Nova Scotia. Can you spend just a second on the specific next steps there, specifically would you guys be able to run product through Alba Island at some point in 2003 with spot cargos and on Nova Scotia. And this question may be preliminary, but could you talk about the commercialization strategy there, specifically to my knowledge the Sable Island facilities that are approximate or capacity constrained through 2010. Have you guys had discussions with the -- you know, the guys that operate that facility? Have you not -- it that a maybe -- and not a maybe, is all this too preliminary to even talk about?

Okay, guys. I’m going to let Phil take the exploration question second. But I’ll start out with the Alba Island. Clearly, we don’t have any L&G of our own to move to Alba Island right now. You know that --

Right.

-- and just for the benefit of others in the call, we don’t -- we’re in the process right now of lining up spot cargos for next year to move through there. Our strategy will be to do that up until we have our own L&G or other -- any other sources of L&G to move there.

Okay.

It really gives us some -- a lot of optionality, particularly in Equatorial Guinea and you know our position on the Atlantic Basin. We expect there to be L&G to go on the market.

Sure.

It’s nice to have the market. That’s what we were seeking.

Okay. Thanks.

All right, Doug. In regards to Nova Scotia, our primary focus next phase is to continue on with our phrasal activities or our exploration testing that we’ll be doing as we mentioned, acquiring additional seismic and have additional plans for drilling activity. In regards to the Sable complex, I think it’s fairly well know that if the performance has not met original expectations there. We haven’t had any formal discussions with disabled interest owners --

Okay.

-- about those opportunities, we see those as natural consequence of the results of our drilling activities to date. So we’ll be holding preliminary discussions. But all in all, it’s still too preliminary. The focus is on really assessing what the exploration opportunity is at this point in time.

Great. Thanks a lot, guys.

Okay. The next question comes from Mr. Tyler Dann from Banc of America.

Hi. Good morning, gentlemen. How are you?

Good morning.

A couple of questions here. Actually, I have a lot, but I’ll only ask a few first. Would you please revisit your 2004 guidance for equivalent production of roughly 430 to 435,000 barrels equivalent per day in light of what you’re talking about for ’02. And I guess what was somewhat intriguing on the ’02 was the [indiscernible] development, some of the disappointing performance. I want to try and center in on that and how that may relate to the ’04 guidance.

And second question would be to what extent is the exploration activity in the Cement Field embedded into your future growth plans?

Let Steve take the first question and Phil can handle the Cement Field.

Tyler, you know, we’re still in the process of working through our plans for production volumes in 2003 and 2004. So it’s premature for us to probably comment on that at this time.

Regarding the 2002 production, we’re looking to average somewhere between -- around 410 to 415 for the year. My best guess is probably around 413. That’s primarily due to more weather-related downtime in the Gulf of Mexico. You know, we typically forecast about six days of downtime. And with the three storms that impacted our operations, we’ll average about 14 days of downtime. And so that has an impact that we weren’t forecasting. And statistically, this year has been a tough year.

[Vola] has been disappointing. It’s been disappointing primarily for the operations of topside facilities. So it came on late in 2002 and it continues to struggle with the processing facilities on the [indiscernible]. And, of course, the operator there, in [indiscernible] is working diligently to try to resolve those problems, but at this point, it still has had a significant impact on the expected performance that we have this year. And we’re a little hesitant to make guesses as to what it would be next year.

Well, okay. Well, that’s good qualitative. I guess I’m trying to get a little more to the numbers and how each of those two elements would contribute to the shortfall relative to previous guidance.

[Vola] is probably impacting us to the tune of about 5,000 barrels a day equivalent. Weather in the Gulf this year impacted us on the order of around 2,000 to 3,000 barrels a day over and above what we forecast for weather.

Okay, that’s great. Thank you for that. And then, I guess, a comment on Cement.

Yeah, in regards to the Cement area. The results to date have been very, very encouraging. It would appear, based on the results to date, that we’ll add more resource than we’re actually producing in the Anadarko Basin. Those are reserves and risk resources. We’ll continue to refocus our Anadarko Basin activity based on these results, but it does take time to implement a program. It simply takes time to go through the corporation commission and the normal processes to drill wells out there. So we indeed see some increased activity, but it’s going to be moderated by the pace that we can perceive through the natural permitting processes and drilling processes.

Okay. I guess, the question though was to what extent, I mean, you know, this sounds like it’s a fairly new mention of this and, you know, obviously has had some very good success to date. To what extent was that embedded into your longer term forecasting for production?

Those were not -- these results are very new for this year. They were not embedded in those higher rate wells. They were not embedded in their longer term forecast. And that’s the sort of activity that we’re going to be ongoing right now.

And your co-operators in the projects -- are they varied?

They’re varied.

Okay. Thank you.

The next question comes from Mr. Paul Ting from Salomon Smith Barney.

Good morning, gentlemen.

Paul.

A couple questions. First of all, on the upstream. I want to make sure I’ve got my -- the numbers straight for the third quarter. Can you isolate the total impact of the weather effect and under-lifting effect. It looks to me like it should be in the 40, 45 [MBD] range. Or can you give me some more clarification on that.

In the third quarter -- at least relative to the second quarter -- the weather-related down time was relatively minimal because we typically forecast, as I said, about six days. We do about three days in the second quarter and three days in the fourth quarter -- or third quarter and three days in the fourth quarter. Basically, September, October, which is the high intensity weather timeframe in the Gulf.

For the most part, Paul, in the third quarter, there wasn’t that much impact in weather because we had forecast it. It sort of carries on then and has a little bit more of an impact on the fourth quarter. But most of the difference in the third quarter was due to timing of liftings. Actually, production available for sale was relatively flat through the second quarter.

Okay. Ken, I know you gave some numbers on the fourth quarter expected production number. Does that consider -- takes into consideration of the total reversal of the under-lifting effect in the third quarter?

That would get us effectively a balance at the end of the year is what we plan -- at least, that’s what we always plan on, Paul.

Okay.

Basically, Paul, the second quarter was in a over-lift, the third quarter was in an under-lift, so it tends to spread that differential out.

Right.

We go into the fourth quarter now, we’re about 540,000 barrels under-lifted. And we would expect to be balanced by the end of the year.

Okay.

Something better than our forecast.

Okay. That makes a lot of sense. Last question. On the downstream, I notice the fact that your Q3 versus Q2 refinery runs come down a little bit again. I’m just curious whether that’s a weather effect or did you have any voluntary run cuts. If so, do you still have one cut in place right now?

Gary, you can obviously handle that one.

Yes, the only would be weather related. When we look at what has happened here recently was when we had to take a couple plants down because of the hurricanes that came through and then the balance would just be kind of light versus light turnaround activity.

So there’s no voluntary run cuts as such because of the economic environment.

And we never announced any voluntary run cuts to the marketplace.

All right.

Hello, this is Gary Peiffer. Were you comparing to last year’s same quarter?

That’s right.

Okay. Well, last year -- as you recall -- was an extremely high margin quarter. We were running high out at all of our facilities. So this, obviously, this year same quarter was not as big a crack spread. So we weren’t running quite as hard this year given the lack of -- or relative lack of profitability versus last year.

Sure. That’s what I’m trying to quantify. What’s the impact of the economically driven lower run rates?

Well, even this year, you know, we’ve got a rate of capacity of 935 and we were pretty close to that already. So we were pushing the system pretty hard last year. We were running, you know, still pretty good this year.

Okay. All right.

Paul, last year -- and Gary -- we ran 961 in the third quarter 2001.

Right, and --

961?

961.

Okay. All right. Hey, thanks a lot, guys. I appreciate it.

Our next question comes from Mr. Arjun Murti from Goldman Sachs.

All right. Thanks. Ken, just so that I fully understand the Symphony pipelines economics. Will you be running any of your own gas through that pipeline or should we just think about the economics since your spending capital will get the tariff on the volumes that go through the pipeline and perhaps some other fees for people using the Brae infrastructure.

Arjun, I guess I’d have to say, you know, the exact sourcing the gases is certainly not been worked out. It clearly -- whatever line is built there to the extent we can move gas through it, we would do that. But the real driver there is to get the line -- a line built, utilize the Brae infrastructure, which we think is obviously important to us and we think it’s important even for the UK to be able to do that. So it will be a combination of tariff revenue and processing fees from Brae.

I guess in terms of [indiscernible] I would think as sort of a tariff pipeline return as being some sort of cost of capital kind of return. You didn’t get something from them for the processing fees of Brae and I guess that gets you a little better. But, I would think the real upside here would be if you could provide your own gas through the infrastructure to benefit from any higher UK gas prices if that market does turn out to be a short gas market.

Yeah, Arjun. A key to our strategy with Symphony is to drive it through the Brae infrastructure. And by driving it through the Brae infrastructure, it provides optionality. We currently deliver gas into St. [Fergus] by having another outlet of gas out of Brae, then we are able to move gas to the more profitable markets, depending on where they exist at the time.

But another key factor is that it would make us even more attractive to collect even other third party business because it gives those people options and terms to market their gas. So, you know, you’re right. There’s a processing and tariff fees, but there’s also the ability for us to attract additional third-party business. It also provides opportunity to extend the field life of our existing operations. So it’s a combination of both things that provide the economics for the Symphony pipeline.

That’s actually helpful. To actually fully benefit from the optionality, do you then take title to the gas or is it just sharing in the benefits from the person who owns the gas to any upsides from, you know, selling to the best market and so forth?

We don’t really have that level of detail on it at this time. But, you know, it would certainly depend on the relationships that we enter into which we -- as we develop that optionality.

That’s great. Thank you very much. Any estimate on Powder River gas production for ’03?

Powder River -- we’re expecting Powder River to probably end up to somewhere around 110 to 120 million a day next year.

Okay. Appreciate it. Thank you very much.

Next question comes from Mr. Steve [Anger] from [Deitre Parkman].

Hi, guys.

Good morning.

A couple of things. For Steve, I wanted to just make sure I had some of the numbers right. It sounded like your Powder River Basin CBM controllable production costs are down 50 percent in ’02?

That’s correct.

Development costs down 25 percent; is that correct?

That’s correct.

And did you say the F&D cost is $1 in [MCFE]?

The full cycle F&D cost would be around $1 in MCF.

You previously had quoted F&D cost at 50 to 80 cents and in the context of some big reductions, help me understand what the difference is there.

Well, I mean, basically our development costs are probably on the order of 40 to 50 cents [indiscernible] So the $1 includes all the acquisition expenses involved as well.

I got you. That includes --

[indiscernible] includes all the purchase price, everything went into the [technical difficulty].

Ongoing capital expenditures, etc.

Yeah. So, that’s an IRS call.

I’m with you. Okay. And then can you give us just some of the highlights as to how you’ve made those drastic reductions in both controllable and development costs?

You know, we’ve been producing in Wyoming for almost over 70 years. And one thing we do very well as a company, I believe, is work and control our costs. And as we took over the operations, detail of the cost control was not practiced. And so most of what we’ve been able to do is just through our experience, is to be able to pay costs out. A lot of it came in terms of labor. A lot of it came in terms of better procurement in leveraging our corporate buying power in order to see those changes.

You know, at this time -- beginning the year, Steve, we were just not competitive in those areas. And we made a strong focus to get competitive. And our goal is to be best in class in terms of delivering the highest possible margins out of the Powder River.

Okay, great. Two quick things for Phil. Nova Scotia work commitment, can you review for us what you actually are going to be required to spend. There were some big dollars committed, I know. And then secondly, I know there’s been some concerns raised on target sizes offshore Angola that may be with an unsuccessful result on the first well. There’s been more focus on some smaller targets. Can you talk to that as well?

Yeah, let me talk about Nova Scotia first. There really is no requirement to spend money next year in Nova Scotia or, for that matter, the year after. As you are probably aware, these leases have a work commitment associated with them. You’re not required to actually spend that work commitment. And if you want to, you have an opportunity to simply pay 25 percent of that commitment at the end of the lease term. And that is that your minimum work commitment that you would have. So at our present time, we’ve largely completed work commitment on the Annapolis area. We are beginning the process of spending money -- which we want to do -- on the Portland and Empire Blocks in the terms of our seismic spend. And, of course, based on the information that we get from our seismic, we’ll be looking at 2004 drilling opportunities on Portland and Empire Blocks, which are the -- what you call the bigger bid blocks out there.

Okay.

Now, in regards to Angola. That’s correct. The initial well was targeted at a very large size opportunity, which was higher risk. The majority of opportunities that have been found in Angola are -- we call it the mid-size opportunities -- say the 2 to 400 [technical difficulty] size pools. There are some bigger pools, as you’re well aware, on Block 15, as well as on Block 17. And what we see is a number of these mid-size pools present in Block 31, the first of which we’ve drilled. And we’ll be targeting several more on Block 31 and similar kinds of opportunities on Block 32.

Very good. Thank you.

You’re welcome.

Next question comes from Mr. Fred Lueffer from Bear Stearns.

Good morning. I have a couple questions. First, I’m a little surprised that you don’t have an oil and gas production forecast for three. What are you waiting for before you put that forecast out or firm that forecast up?

Fred, we’re just -- we’ve just collected all the information and really, we just need time as a management team to sit down and discuss it and make sure that we’re comfortable with that forecast. And so, you know, I mean, quite honestly, I certainly have a very good idea of what that’s going to be; but, until we have an opportunity to visit it as a management team, it would be premature for us to discuss it publicly.

Is it up or not?

Again, you’re asking me to discuss it and I really just have to defer that question. We will be getting back with you before the end of the year on what our forecast is.

I wish we had that luxury, Steve. We have to forecast that now.

One quick one on the upstream and that is, can you share with us the cost of the additional interest in Block 32?

This is Phil, Fred. We can’t talk the contract terms on Block 32. That’s proprietary information. What I can tell you is the terms were fairly similar to what we went in on Block 32 originally.

And just two on the downstream. I don’t know if I heard these two comments correctly, Ken, when you went through them. But, you gave us the margins for October in Chicago and the Gulf. And I think those margins are stronger than the third quarter and I thought you made some kind of comment to the effect that you didn’t expect the fourth Q would be different from third Q. Are you talking financially or --

Fred, I think the comment you’re referring to, we said -- I’m sorry, I didn’t make it clear. We were referring to the sweet/sour differentials. We haven’t seen much difference there yet. That’s what we were referring to.

Okay. Fair enough. And also, I think you said that merchandise sales in MAP were up year-over-year, but down quarter-to-quarter?

I don’t believe that’s right. Gary, do you want to take that?

Yes, just a second, we’re -- this is Gary Peiffer. Merchandise sales were up both quarters -- sequential quarters, as well as, comparable quarters last year. Fred, we’re up in the third quarter 8.2 percent on a year-to-date basis versus last year, and 7.6 percent quarter-to-quarter. So again, 7.6 quarter-to-quarter, 8.2 year-to-year versus year-to-date.

All right. Thanks a lot --

And that’s on a life versus life basis.

Fred, just to give you a feel for the absolute numbers. It’s -- we had $645 million of retail sales in the third quarter and $612 in the second quarter.

Thank you.

Next question comes from Mr. Mark Flannery from Credit Suisse.

Good morning. I just -- can I just get back onto that sweet/sour thing. I guess, it’s a question for Gary. Our numbers show that sweet/sour is improving, certainly if you take WTI, WTS spread. I’m curious as to why you guys aren’t feeling it yet or are we looking at the wrong kind of sweet/sour for a MAP application?

The sweet/sour that we follow mostly would be a WTI to MARS, WTI to Poseidon type sweet/sour. And while we are seeing it improving every so slightly, it’s still very, very -- as someone related to me yesterday, a very sticky market. It tries to move out and it pulls back. And what has happened -- WTI versus MARS being kind of our, one of our bigger benchmarks -- it started to move out back in early September. But then with the amount of production that was shut in in the Gulf, it quickly retreated back into the levels we have seen in the third quarter.

So as we go into the fourth quarter here, yes, we’re expecting it to continue to ramp or to widen back out. But that would be the next index.

Just an example, Mark. This Gary Peiffer. In the second quarter, MARS to WTI averaged about $2.23 under. In the third quarter, it was $2.22. So, I mean, it’s relatively flat. And I think today it’s about $2.40 to $2.50.

But, September, Mark, did widen out. The September month itself was around $2.75. So it did widen out a little bit in September. But because of the storms, it retreated a little bit.

Okay. Thanks a lot.

Next question comes from Mr. William [Furr] from W. H. [Reese].

Good morning. I wish I had gone to the Eugene [Noax] School of Dialing because it seems to take a while. But thank you kindly for taking my calls. I had a couple of questions on -- comment on re-exploration expense. And if I heard correctly, activity is going to double in ’03, but the expenditure level will be no greater -- or not much greater than ’02. Is that a mix shift or is that just an oil service cost attentiveness.

And secondly, or in conjunction, could you give us a flavor of ’03 cap ex. Fred’s [indiscernible] notwithstanding about production lines. Just a little flavor as to whether it will be up and down and perhaps, by segments. And if oil prices or gas prices might change your thinking if things stay around the current level. Thanks very much.

This is Phil Behrman. I’ll answer the question on exploration. Really what we’re doing is we’re increasing the number of wells we have, the number of wells that we’re drilling. We have a higher proportion of what are less expensive wells. So, for example, in the Norway area, as well as the Equatorial Guinea area, we will increase our activity in those areas. Those wells are significantly less than some of our deepwater areas. That’s one shift that we have.

Secondly, our work interest mix has shifted slightly in addition to that. And secondly, in areas of the deepwater, we have less -- we have a fewer number of wells that are in the really higher cost deepwater category, a number of them that will be in the lower cost deepwater category. When you make all those changes, we can put more activity and improve our chances of continuing to have similar or higher levels of resources at the same capital level in exploration.

Is there any -- do you have any comments on oil service costs in general? I mean, are you locking in all three oil service activities or forward purchasing?

In the deepwater area, we have seen some softness in the rig markets there. That has had some small impact. But many of the rigs that we utilize are on long-term contracts that we don’t see those small benefits. In other areas which are shallower water, we indeed see some softness in the market. However, when they’re in remote areas, we aren’t picking up the full incremental benefit of that softness because the rig availability in some of the remote areas isn’t as great.

And a comment from Ken or someone on cap ex and should oil prices stay or gas prices stay about where they are or decline a little bit, would that change your budgeting for ’03?

Bill, this is John Mills. You know, we are -- we have tried to maintain a relatively uniform capital budget over the past several years on our upstream capital spending. And I think we’ve pretty much managed to do that. We obviously retain some flexibility should we get into a more robust either natural gas or crude environment. But for the most part, you haven’t seen our capital expenditures very much more than 3 or 4 percent from year-to-year in either robust or more modest crude and natural gas markets.

For the most part, we take a mid-cycle look at those commodity prices as we set our capital expenditure budget, we’re not relying on, you know, $3 crude or $4.50 gas to look for economic return. So you’re not going to see a lot of variation on our upstream capital spending from year-to-year.

Just out of curiosity, doesn’t four plus gas in the U.S. tempt you a little bit?

We’re -- I mean, we’re -- we’ve got our capital. I mean, yeah. We’re spending money on gas in a lot of places, [indiscernible] Basin and Powder River Basin and the Gulf of Mexico, etc. So it tempts us, but realistically, we’ve got a somewhat more constrained intermediate term gas forecast and we’ll continue to look at economics off that more constrained number.

Thanks very much.

Next question comes from Mr. Mark Gilman from First Albany.

Hello. Can you hear me?

Hello.

Yeah, can you hear me?

We can hear you.

This is Mick [Chung] from [indiscernible].

Yes, Mick.

Hi. My question is regarding MAP. There’s some derivative loss reported in third quarter from MAP. Can you comment on that. What is the nature of the loss?

Gary Peiffer, can you take that?

I’m not aware of that being reported there, Ken.

No. We hadn’t reported it.

Again, I got that from listening to Ashland’s call.

Well, I think -- you listened to Ashland’s call. There was a little of phase 133 effect we had in the third quarter for marking the market and the adoption of 133 just a few million dollars.

This is $2 million?

Yes.

Was there any activity in the second quarter?

Hold on a minute. In the third quarter, the phase 133 effect was about 3.5 million negative and in the second quarter, it was about 8.5 positive. And year-to-date, it’s been about 3.5 positive. So it fluctuates a little bit because of the mark-to-marketing effect that we’ve had to do with the adoption of 133, but overall, it’s been fairly immaterial.

That would be the overall -- the 100 percent -- I’m sorry, your share of profitability. If I do a 62 percent of the 100 percent net profits, the -- it came out lower than what you reported for the downstream. Can you reconcile that for me?

What --

Well, what you’re seeing --

Yeah, go ahead, Gary and then I’ll --

You go ahead and take it. It’s a parent issue. Go ahead.

No, that’s okay. I think, Mick, what you’re trying to do is take Ashland’s reported number and extrapolate into Marathon’s share of MAP.

Yeah.

I think you need to talk to Ashland about that --

Well, [indiscernible] the $108 million, which is 100 percent reported by you guys, 60 percent [indiscernible] less than the -- I don’t know what you have -- 67, I think.

We have other downstream costs related to small number of properties that did not go into MAP that we included in that segment. And that’s what the difference is.

Yeah. What are those things again?

It’s basically environmental expenditures and that sort of thing. John, you might have one more --

Yeah, I can give you just very quickly. It’s service station sights that were redundant that did not go into MAP. Indianapolis refinery site, a number of things that we continued to incur, environmental expenditures and pay taxes on and, you know, do minimal upkeep on as we prepare those properties for disposition. And we have disposed of a large percentage of those properties since the formation of MAP, but certainly not all of them.

Okay. On the normal quarter basis, what should I expect to look for in those areas?

The budget for our non-MAP downstream activities is a little bit lumpy depending upon the environmental and legal obligations, etc. But probably averages in the $15 million a year type of -- plus or minus a couple million -- but $15 million a year to pay for net loss.

Okay. Thank you.

The next question comes from Mr. George Gaspar from Robert W. Baird.

Yes, thank you. Question here regarding Gulf of Mexico on restarts per well oil flow rates, gas flow rates, post Lilly. Maybe it’s too early to be able to tell us if you’re seeing any decline curve on restarts. But, what is your thought on that?

Hi, George. Really, our restarts have gone very well. And we just really this weekend, there was a drilling rig laying against a pipeline. It had us restricted. But it poked a -- we got that -- that was pulled off and the pipeline was put back into service. And that was really the last effect of the Hurricane Lilly. And we’re back up to full strength now.

Okay. My question was more pointed to actual flow rates out of the well comparing them to pre Lilly. Is there any backing off of a production on a per well basis because of the shutdown?

Now we -- I’m not exactly sure where you’re -- we bring the wells back on carefully. But at this point, we’ve seen no residual impact or impact on the reservoir from the storm. Everything now at this point seems to be fully back up to where pre Lilly, or really pre Isabel.

Okay. And on the Powder River Basin, could you give us an average production per well and what depths are you completing these [indiscernible]?

Our depths range anywhere from about 600 feet to about 1,500 feet in depth. And our average well rate right now is running just around 98 MCF a well. We have groupings wells now in the more mature Gillette area that are getting lower on their decline curve. And then, of course, our new activity is in the early stages of this incline. And so overall, it averages out to plus or minus around 100 MCF a well. A little lower than probably the average well currently in the Powder River, but that has to be the lifecycle -- where we’re at in our lifecycle of our wells.

Okay. And how much time do you need to get to full -- what you could consider -- is 100 percent available stream with the water runoff. I mean, how much time is involved in that?

Dewatering in [indiscernible] natural gas production really depends on far you are away from existing production. But, we have ranges. If you’re drilling wells close to existing production where a large part of dewatering is already taking place and you’re just really stepping out from those areas, you could come on gas immediately or average maybe to get the full strength on that well somewhere from 0 to 3 months. And you move out. And like typically, the area like Big George, where there hasn’t much production or dewatering take place. That could take anywhere from 12 months to 24 months to dewater and come up to full strength.

Okay. And your decline curve. How do you figure your decline curve once you’re at maximum going forward? On an annual basis, what you are looking at?

On an annual basis decline. Again, it varies. But once a well reaches peak production and is on decline, the decline rates will average anywhere from about say 20 percent to as high as 30 percent depending upon the development spacing.

Okay.

Forty-acre wells are going to decline at a much higher rate than 80-acre wells will.

Okay. Thank you.

I show no more questions

Okay. Well, thank you very much everybody. We’ll do this again next quarter.