馬拉松石油 (MRO) 2003 Q3 法說會逐字稿

Good day and welcome to the Marathon Oil Corporation third quarter 2003 earnings conference call. Today's call is being recorded. Opening remarks and introductions I will like to turn the call over to Mr. Ken Matheny, Vice President of investor relations. Please go ahead, sir.

Thank you, Chris. I'd also like to welcome all of you to the third quarter 2003 earnings teleconference for Marathon Oil Corporation. With me on the call today for Marathon Oil is John Mills, our Chief Financial Officer, and also with me for Marathon Oil Ashland Petroleum is Gary Piper, Senior Vice President of Finance and Information Technology. I'm going to spend about 15 minutes going over the financial aspects of Marathon's third quarter, then open the call up to questions. Approximately two hours after this call ends these prepared remarks will be place on the investor relations portion of our website, they will be in a downloadable format and remain on the site for about two weeks. My remarks today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2002, and in subsequent forms 10-Q and 8K. 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.

Third quarter of 2003 was a good operating and financial quarter for the upstream business, downstream likewise had an outstanding operating quarter with financial performance significantly exceeding the second quarter. Unless otherwise noted, all quarterly comparisons I make will be third quarter 2003 versus second quarter 2003. Net income for the third quarter was $281 million or 90-cent per share, compared to second quarter net income of $248 million, or 80 cents per share. Net-net income adjusted for special items was $263 million, or 85 cents per share in the second quarter, there were no special items in the current quarter.

Third quarter did contain a number of events that could have been considered special items but they only came to a loss of about $4 million after tax. The events all pre-tax were gains on the sale of our interest in Colonial and West Shore pipeline that totaled $34 million, and accident impairment for an equity employ in a pipeline system up for sale of $22 million, and business transformation costs of $19 million. A reconciliation of net income adjusted for special items to net income including an explanation of the reasons for using this non-GAAP measure, is included in our second and third quarter 2003 earnings press releases. These press releases are posted on our website under the press releases tab, which is located under the news center stab. In addition, Marathon closed the sale of its western Canada assets on October 1, 2003, a fourth quarter event for reporting purposes.

However, in the third quarter we are reflecting the results of operation for these assets as discontinued operations for all prior periods. Marathon's investor relations pact, now on our website, reflects quarterly results for 2003 and 2002, adjusted to the effects of discontinued operations. Likewise, my segment analysis remarks will also use the segment numbers that reflect Canada as a discontinued operation. In other words, Canadian financial results are excluded.

The upstream segment had third quarter operating income from continuing operations of $343 million or $10.59 per barrel of oil equivalent. That compares to the second quarter of $304 million or $8.91 per boe. This experience is primarily a result of higher liquids prices and lower equity affiliate expenses partially offset by lower production volumes. Third quarter up stream segment included a $35 million charge for derivative activity while the second quarter included a charge of $32 million. Worldwide production averaged 372,000 barrels of oil equivalent per day in the third quarter, which exceeded the guidance given in the second quarter of 366,000 barrels of oil equivalent per day.

Domestic upstream operations had third quarter operating income of $295 million or $13.91 per barrel of oil equivalent versus $237 million or $11.18 per barrel of oil equivalent in the second quarter. Our average domestic realized liquids price excluding derivative activity was $26.84 per barrel, up $1.97 from the second quarter. The prompt NYNEX posting average was $30.21 per barrel versus 28 dot 91 per barrel in the second quarter an increase of $1.30 per barrel. Our outperformance above the NYNEX exchange was primarily a result of narrowing sour grade differentials relative to WTI during the quarter.

Our third quarter average domestic gas price of $4.38 per MCF, that also excludes derivative activity, was a decrease of 2 cents from the second quarter level of $4.40. Our relative outperformance compared to the 43 cents decrease in mid-week prices and the 84-cent decline in the daily average Henry Hub (?) prices primarily reflects higher value mix as production from the Gulf of Mexico increased relative to the remainder of our lower 48 production. And unchanged quarter on quarter price realizations from our Alaskan production, which is not subject to lower 48 market swings.

On a barrel of oil equivalent basis, domestic sales revenue averaged $26.55 in the third quarter, compared to $25.66 in the second quarter. Derivative activity was a negative$ 9 million, or 41 cents per barrel of oil equivalent, and domestic exploration expense was $13 million or 59 cents per boe, compared to $12 million or 58 cents per barrel of oil equivalent in the second quarter. All other domestic costs in the third quarter totaled $12.02 per boe, that was down $1.21 versus the second quarter. This variance is a result of lower DDNA expense, lower unproved property impairments, and no FAS 144 impairments in the third quarter. Also contributing were lower expenses as a result of the sale of our interest in SACROC. On a going-forward basis we expect our field level operating costs to average about $2.50 per boe and DDNA to be about $4.70 per boe, excluding any FAS 144 property impairments or cancelled and impaired unproved property [inaudible] impairment obligation.

Domestic liquids production came in at 113,000 per barrels of liquids per day compared with a second quarter of 114,000 barrels of liquids per day. The increase over our guidance was primarily the result of good weather in the Gulf of Mexico, and the performance from Troika, where the TA3 well was forecast to water out during the middle of the third quarter but it did not begin declining until late September. Natural gas production of 704 million cubic feet per day was down 3 million cubic feet per day, versus the second quarter.

Moving on in the international upstream, segment income from continuing operations was $48 million, or $4.27 per boe, compared with $67 million, or $5.22 per boe in the second quarter. Our average international liquids price at $25.28 per barrel was up $1.72 sequentially, 63 cents less than the change in dated rent primarily due to lower priced Russian volumes. partially offset by European and West African volumes, which outperformed Brent due to the favorable timing of liftings. The average international gas price of $2.46 per MCF was up 2 cents versus the second quarter.

On a barrel of oil equivalent basis, sales revenue averaged $21.53 versus $19.84 in the second quarter. Derivative activity in the quarter was a negative $26 million or $2.35 per boe. $21 million of this amount was FAS 133-related mark-to-market losses attributable to our long-term gas sales contract in the U.K. Second quarter included a negative impact of $11 million, or 88 cents per boe. Exploration expense of $17 million was up $3 million to $1.52 per boe, versus $14 million or $1.09 per boe in the second quarter. All other international costs total $14.90 per boe, up $1.05 versus the second quarter.

[inaudible] level of control of expense was higher as a result of cost in Point Haven where we have high fixed costs and lower production, primarily because of compresser problems and [inaudible] due to higher liftings and work-over expense, plus the additional full quarter of Russia. On a going-forward basis we expect our field level operating costs to average about $3.15 per boe. and DDNA to average about $5.50 per boe, again excluding any property impairments or cancelled impaired unproved property or asset retirement obligations. Production, including Canada, came in lower than expected, international oil liftings of 82,000 barrels a day were down 7% compared to the second quarter, the decrease was a result of compressor problems at the outside operated point haven field in the North see.

International gas production including Canada, came in at 356 million cubic feet per day down 22% over the second quarter. This is a result of several factors, first balancing in the U.K. Braemar Field, continued gas injection in Ireland, our sale of our interest in CLAM (phonetic) and downtime in Equatorial Guinea associated with the conditioning work that needed to be done for Phase II. Turning now to downstream results, the reportable [inaudible] segment income in the network was $356 million compared with second quarter income of $253 million. The third quarter [inaudible] segment income was the fifth highest quarterly income reported since MAP's formation in January of 1998.

The improvement over the second quarter was a result of higher crack spreads, lower maintenance costs, and higher refine rye throughputs. The intranssit adjustment was a positive $9 million versus negative $5 million in the second quarter, and offsetting the positive factors, spot gas lean and distillate prices as reflected in published crack spreads increased significantly faster than praise on all the petroleum products MAP sells. As published Chicago 321 crack said average day [inaudible] in the third quarter versus 664 a barrel in the second quarter.

Our refining and wholesale marketing margin in the third quarter was 8.6 cents per gallon, versus the second quarter level of 7 cents. The gasoline and distillate gross margin for the retail business speed way super America, was 13.8 cents per gallon in the third quarter, as compared to 12.3 cents per gallon in the second quarter. Refinery crude oil runs averaged 966,000-barrel as day in the third quarter or 103% of rate the -- rated capacity compared with 951-barrel as day or 102% rate of capacity in the second quarter.

As we maximized our runs to meet increased product demand in the late summer driving season. Refined product sales excluding buy-sells averaged 1.370 million barrels a day on the third quarter, up about 7% from the second quarter, and up about 6% over a year ago. Manufactured sales and margins continue to be a key focus area for MAP. Merchandise sales flat with the second quarter 586 million dollar, however on a same-store basis, sales were up approximately 15%. And total margin of $145 million improved by nearly 3% over the second quarter. The other energy-related business segment income was $21 million in the third quarter of 2003 compared with $39 million in the second quarter of 2003. The decrease was a result of several factors. Included in this segment were asset sales gains of $34 million related to sale of Marathon's interest in the colonial and west shore pipelines, the negative earnings from the second quarter included 22 million dollar impairment on a pipeline equity interest in a pipeline system we have for sale, and $13 million less gains in derivatives and related gas purchase for resale activities compared to a particularly strong second quarter.

Moving back to financial results, total segment income in the third quarter of 2003 was $720 million, up $124 million from the second quarter with the upstream being up 13% and the downstream was up 41%. The unallocated category, administrative expense was $61 million in the third quarter, compared with the second quarter total of $49 million. The increase was primarily related to business transformation costs incurred in the third quarter. We now estimate that our year on year pension expense increases will be $35 million for the Marathon plan, and $51 million for the MAP plan. And that pre-tax impact to Marathon, full year 2003, over 2002, after justing or Ashland's minority interest to $67 million, during the third quarter, MAP made cash contributions to its pension plan totalling $89 million, we do not expect additional contributions until 2004.

For other post-retirement benefits, we estimate year-over-year increases of $10 million for Marathon, and $11 million for MAP, net pre-tax impact to Marathon full-year 2003 over 2002, again, after adjusting for Ashland's minority interest, is $17 million. Net interest and other financial costs were $55 million in the third quarter, compared to 52 million in the second quarter, the primary difference is a result of foreign exchange gains of $8 million in the second quarter. Capitalized interest of $11 million was close to the $12 million that we capitalized in the second quarter. Preliminary cash adjusted debt went down by $89 million during the third quarter to $3.9 billion. If preliminary cash adjusted debt-to-capital ratio in September 302003 is 40.9%, down from 42.4% in June 30. Please note that these ratios and total debt include approximately $546 million of debts that serviced by U.S. Steel. They also do not reflect the $588 million of proceeds received from the sale of our western Canadian assets that closed on October 1.

As part of our commitment to maintain financial discipline and high grade our asset portfolio, we announced an asset rationalization program in February to divest of certain upTammy and downstream assets determined to be noncore to Marathon's strategy. Including the Canadian sale that closed on October 1, our total asset sales to date exceed $980 million with a few assets sales still possible prior to year-end, sales for the year could exceed $1 billion. Proceeds are being used to strengthen our balance sheet, and to invest in select business opportunities like KMOC consistent with Marathon's strategy to create superior long-term value growth. Our pre-tax income for the third quarter reflecting just Marathon's share of MAP's income was $471 million. The tax provision was $191 million, or tax rate of 40.6%. The higher than usual effective rate for the quarter is one-time noncash adjustment related to the remeasurement of deferred foreign tax liabilities related to discontinued Canadian operations.

For 2003, we still project an effective tax rate of approximately 37% for the year. Third quarter preliminary cash flow from operations was $675 million. Preliminary cash flow from operations before work capital changes was $732 million, and our capital spending in the third quarter was $453 million.

Finally, I want to make a few observations about the fourth quarter and the full-year 2003. In 2003 we hedged a significant portion of our anticipated oil and gas production utilizing zero cost collars. We also sold [inaudible] pardon of our anticipate oil production for 2003 and support of our anticipated gas production for 2004. Natural gas hedges cover approximately 285 million cubic feet a day, representing approximately 25% of production for the remainder of 2003, and 73 million cubic feet per day for 2004. Oil hedges for the remainder of 2003 average approximately 67,000 barrels per day, or approximately 35% of liquids production.

The detailed volumes and prices related to the hedges have been disclosed in previous calls and are also included in the second quarter 10-Q on page 29, so I will not repeat them on this call. During October, we also entered into WTI and Brent-based collars on 44,000 barrels per day of anticipated oil production for all of 2004, at an average floor price of approximately $24.25 and an average ceiling price of approximately $29.70. On the domestic upstream side we expect fourth quarter liquids production to be about 104,000 barrels per day, gas production should come in at about 740 million cubic feet per day, and domestic exploration expense is anticipated to be about 15 to $25 million.

On the international upstream side, liquids reduction in the fourth quarter should be about 88,000 barrels a day, we expect gas production to be about 360 million cubic feet per day, international exploration expense is anticipated to be approximately 25 to $35 million. Taking into consideration the acquisitions and dispositions made to date, but excluding the impact of any additional acquisitions or dispositions of producing properties, we expect fourth quarter worldwide production to be about 375,000 barrels of oil equivalent per day, and 2003 production to average approximately 390,000 barrels of oil per day. Downstream crack spreads recently come off the relatively high levels we enjoyed in the third quarter of 2003, in addition to the normal uncertainties we deal with such as worldwide crude production, weather and refinery production disresumptions, the downstream business is dealing with uncertainties by changes in gasoline specifications nationwide due to clean fuels requirements particularly in New York and Connecticut due to the elimination of MTBo that goes into effect on January 1, 2004. Therefore, we believe the fourth quarter 2003 downstream financial environment is going to be influenced more than normal by world events and the early winter weather in the United States, since the new gasoline required effective January 1, 2004, must be produced and shipped beginning in the fourth quarter of this year.

At this time, we believe our downstream financial results should -- will be below the third quarter of 2003 and have the potential to be better than the results we reported in the fourth quarter 2002. As far as the other energy income line, we estimate income to be $20 million, administrative costs should total about $65 million, including approximately $15 million in business transformation costs. Net interest and other financial costs are expected to be approximately $57 million for the fourth quarter. For all of 2003, we project net interest and other financial costs of $230 million.

In closing, Marathon had a very good operational and financial quarter. While the parts moved a bit as they always do, we exceeded our production forecast and our price realizations remain good. Exploration expense was less than forecast as a result of outstanding exploration success during the quarter. MAP was able to operate at record run rates during a quarter which also saw refining margins and retail margins at high levels. Our asset sales program has been a great success. And along with strong operating cash flows, there's a -- has allowed us to strengthen our balance sheet and positioned us to fund our development projects and other select opportunities that might come our way.

We look forward to telling you the more complete story at our analysts' meeting on November 4 in New York City. Invitations have gone out. If you plan to attend and have not responded, I ask you do so as quickly as possible so we can finalize the arrangements. I will now open up the call to questions. I ask that you please identify yourself and your firm affiliation for the benefit those listening in.

Thank you, sir. At this time, ladies and gentlemen, if you would like to ask a question, please press the star key followed by the digit one on your touch-tone telephone. Once again, ladies and gentlemen if you would like to ask a question at this time, please press star 1. We'll take our first question from Doug Terraceson with Morgan Stanley.

Good afternoon, guys.

Hello, Doug.

I had a again about really a clarification Ken on what you said on why your profits will be better than the fourth quarter of last year, which is typically your lowest quarter of the year. Could you just kind of restate what you said as to the rationale?

Gary, pipeline up a bit, but really, the fourth quarter of last year was not a very, very good quarter.

Right.

Gary, I don't know if you might have anything to add to that?

I think -- that, this is Gary Piper for MAP. I think the issue was that we were just expecting and we've already started out here in October a little better than we had last year in terms of crack spreads. And we're expecting that there's going to be a little bit of volatility in the marketplace as the introduction of a new, the phase-in of the new clean fuel starts nationwide as of the first of the year, as well as the fact that, starting in January of '04, both New York and Connecticut have banned the use of MTBE. So there will have to be changes in the products that have to be supplied into those markets to allow it to be blended with ethanol beginning January of '04. So we did see a little bit more uncertainty going forward at this point in time than we did last year.

That's pretty straightforward. Okay. Also in the deepwater offshore eastern Canada, some of your competitors have announced some fairly disappointing drilling production results during the last couple of months, which may or may not improve your position in that play. So I wanted to see if we could get an update on deepwater Nova Scotia as it relates to Marathon. As you do that if you could cover the specific next steps you guys envision between where we are today and first production and any time frame that you may have on that topic?

Okay, Doug, a couple of things. One, the wells of that been drilled have not dampened our enthusiasm for the area. We still, all the acreage we have, we've had the one discovery proved us, we have a good gas system in the area. We've done three seismic survey on the two adjacent blocks that we have. And right now are working with partners to drill either one or two wells next year in that area.

So we still, we see that as an area that we feel good about, it's a frontier area, we know there's risk involved, but we think that the potential there is such that we need to continue the program and we plan to do so.

Okay. Thanks a lot.

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

Regarding your ambitions in the area of GTL there's been a big announcement in the last week that Shell has managed to sign a multi-billion-dollar GTL contract with Qatar Petroleum. What are your ambitions in that area in terms of scale or size or capital equipment? These things can run into multi-billion-dollar projects. Is that the kind of thing that you guys are pursuing?

Mark, this is John Mills, let me take the first part of the question on hedging and when we do it and why we do it. You're exactly right, our balance sheet has improved significant I in the last year. But we believe mid cycle prices on crude oil are in the 21 to $22 range, $21.50, someplace in there. When we see crude prices in the neighborhood of two standard deviations above that mid-cycle price, we think that's an opportunity that -- to sell forward through collars as Ken has described, agents least -- at least a portion of our liquids production for a year. You know, we typically don't go out more than a year but have put positions in place in October that will cover all of 2004.

Similar philosophy on the gas side, so that's really the philosophy is in essence to help protect our capital program for 2004, and you know, as you, I think can get a sense from the numbers, that the amount hedged for 2004 represents about 25% of our liquids production. So it's still a relatively minor portion of our overall production.

Okay. So basically, it's kind of a philosophically-driven rather than balance-sheet-driven issue?

I'd say some combination of the two. But clearly Mark off of our balance sheet today, you know, probably incrementally more philosophy-driven than balance sheet. But certainly both, you know, both of those issues are factors.

All right.

Mark, on your second question I'd have to say, I look at what Shell did, it's obviously a big project, it's something that's positive for the area, let's everybody know there are opportunities there. We're still looking at a project there, I think, as you know. But I have to tell you on this call today at this point in time, I just probably better to just wait until November 4. We will certainly address this in a lot more detail at that time, Mark and I think we'd be better off to wait just 10 days.

Okay. That's fine. Thanks.

We'll take our next question from Gene Gillespie with Howard Weill.

Good morning, sorry, good afternoon, my advanced age, you understand.

I do.

Two questions here. Looking at your European natural gas price realization, as a point clarification, it appears that you rolled from U.K. mark-to-market derivative loss into that realization; is that correct?

No, the realizations, Gene, that I quoted, are totally without the market-to-market launch there.

The 201 is considerably below the U.K. bid week of 288, and in the past you've tracked U.K. bid week much closer than that.

Let me take a look at the 201 . Our Europe gas prices were actually 315.

I'm looking at average price realization on your -- in your-

If you're looking at the total for all of international?

No, I'm looking the Europe specifically. It says 201 versus $1.77 a year ago.

Looking at the investor relations package?

Preliminary supplemental statistics part of --

Oh, I see, I'm sorry. You have 201?

Yes.

I apologize, Gene. What did you have for the second quarter?

I don't have a second quarter number.

Ken, I think on page 11 of the earnings release, isn't it?

Yeah, I got it. We've got it here.

I'm looking at the 201, Ken, versus U.K. bid week price of 288 for the third quarter. And typically in the past, you know, it appears that you tracked much more closely than that.

Yes. Let's see if we can track that down and give an answer a little bit later in the call. I apologize, I don't have the detail behind that right now.

That will be fine. Secondly, you may or may not want to answer this question, how would you handicap the probability of a sale of Yates in the fourth quarter?

You're right, Gene, we don't want to handicap the possibility. It is something that we are having discussions with Kinder Morgan on, but we can't comment on merger and acquisition activity.

Fair enough, John, thank you.

Yes.

We'll take our next question from Albert Anton with Carl R. Forsheimer and Company.

I wonder on the KMOC acquisition, you did buy a going concern, but I wonder how it has gone and what kind of a program you're undertaking to move some of the probable and conditional reserves over into proved and so forth?

I have to say what we found in the months since we've been in there has all been -- has been very, very positive to us. More upside surprise that I have to say than downside surprises. We've increased the drilling quite a bit, we're bringing a lot of -- we have a good work force and we're bringing a lot of planning skills and logistical skills to the operation.

Probably planned to at least double the number of wells we drill this year there next year so you know, we've said before at the time of this acquisition that we would probably be booking something in the neighborhood of 85 million barrels of proved reserves this year from that acquisition. I certainly don't see anything at this point in time that gives me any pause that we'll not hit that number or perhaps even exceed I. I have to say everything's going very well.

Very good. Thank you very much.

We'll go next to Mark Gilman with First Albany Corporation.

Guys, good afternoon. My analysis is suggesting that the costs in MAP, exclusive of those that are burdening the wholesale and refining margin, were up quite significantly in the third quarter. Could you validate the accuracy of that observation and if indeed it is accurate, talk a little bit about what was responsible for it?

This is Gary Piper. What are you comparing it to, Mark, second quarter or third quarter last year?

Gary, any period you want to compare it to. It's running $30-$50 million above.

I'd say that's probably on a manufacturing basis, not between the second and third quarter, but, say, third quarter of last year to third quarter this year, our manufacturing costs would be up about $40 million or so. And about half of that is driven by higher natural gas prices, and the other half would be primarily driven through increased maintenance.

But aren't I correct that the manufacturing costs are implicit in your reported margin?

That is correct. It is.

Okay. What I'm talking about Gary is a variance of that magnitude that is below that line, so to speak, such that it's got to be general and administrative, distribution, marketing, and those cost categories.

Well, as Ken said in his remarks, our pension costs for the year for 2003 will be up about 50 million, I think 51 is what he mentioned in his remarks. And our OPEC benefits cost will be up another 11 million or so. So in the case of the retirement-related expenses, they're up -- they'll be up for the year about 60 million.

Okay. All right, Ken, could you perhaps update us just a little bit about the Powder River, the volumes just kind of keep slipping.

They've stayed just about flat, Mark. We certainly haven't seen the increase there that we had counted on, we're naturally disappointed about that. We have taken a long, hard look and -- at our technical knowledge base and have done a lot of studies over this last year and we think we're finally beginning to have a much much better understanding of the subsurface coal that is we're dealing with in the various basins that we have, particularly in the Big George area. I think I'd rather wait until November 4. Because we do have a fair amount to talk before on the Powder River at that time.

But it's something that we still feel it's going to be a very, very good asset for us. We are looking at good growth there. But it's just taking us quality a while to get our hands around all the technicals that we need to to make that grow like we know it can grow.

One more, if I might. Do you possibly have international third quarter liquids production as opposed to liftings? Based on your regional categories and breakdown?

Well, if you look at -- if you want to look, we were over-- we were over-lifted in Gabon by about 111,000 barrels in total.

U.K., Ken?

U.K., we're under-lifted by about 188,000 barrels of oil equivalent, 188,000 barrels, I'm sorry.

Any variances in other regions?

Nothing -- nothing really material, Mark, no. Those are the two primary areas, Gabon and the U.K. That's as of September 30. And EG about 349,000 barrels down.

Under-lifted?

Under-lifted, yes.

As of September 30, Ken?

As of September 30, correct.

Okay. Thank you.

We'll go next to Paul Cheng with Lehman Brothers.

Hi guys. Several quick questions. Ken, any kind of time line you can share in terms of development plan in Angola?

You know, that's an area that we really -- Paul, as you know, we're not the operator on either block ,BP operates Block 31, total operates Block 32, the drilling is much much more advanced on Block 31. I think -- the best I could probably say, I can't give you any timing, but certainly it's beginning to look more and more like 31, you've heard, I think BP has publicly stated that they think there's a probable development there and we certainly have no reason to disagree with the operator at this point in time. But I'd really rather not try to speculate without a plan of development that's been approved by the partners and communicated to the government what that time period might be.

Okay. On MAP, I think the wholesale margin was down equate substantially in the third quarter comparing to the second. Can you give us some rough idea that how so far in October, wholesale margin comparing to the third quarter average?

Gary, do you have something there?

Paul, this is Gary Piper. I don't have anything month to date but you're exactly right in terms of the third quarter versus the second quarter. We did a little analysis recently here and if you look at just the 87 conventional gasoline and the slow sulfur diesel, the numbers used in the traditional crack spreads they only represent a little under 50% of the volume we sell. So, you know, the two proxies, the two numbers you're using as proxies, is a fairly less than half of what we sell.

As you rightfully know, in the second -- from the second to third quarter, the -- from the second to third quarter, the spot prices of gasoline in Chicago increased about almost [inaudible] a gallon, we did not increase our wholesale prices the same on the whole slate of products we sell all the way down to asphalt. As a matter of fact asphalt prices dropped a bit between the second and third quarter. About 100 to $120 million which is what I've seen you've been quoting is probably a reasonable ballpark estimate of how much versus the change in 87 conventional, and low sulfur diesel, our profits were down because of wholesale prices not keeping up with those two indicators.

And you have no ballpark estimate at how so far in October we are doing?

Nothing that I can quantify you at this time, no.

Okay. How about Gary, about the blackout?, How much it cost you?

I'm sorry, Paul, what did you say?

The blackout?

Oh, the blackout. That was really fairly minor. We would estimate somewhere in the $5 million range is what it would have cost us. It was relatively small in its overall impact.

Okay. Ken, I think you mentioned that interest expense for the fourth quarter is about 57.

Correct, 57 is our estimate.

Is there any reason, with your asset sales from Canada of $600 million, that you're going to receive the cash? I presume you're going to pay down debt further, why your interest expense will be actually be sequentially going up, not going up by a notch, but should be actually going down?

Paul, you know, in our fixed rate -- our fixed debt portfolio, we don't have an opportunity to pay off any debt in the fourth quarter without a buy-back, which is fairly expensive. So that we're going to be -- we will use the cash from asset sales proceeds essentially to build a cash position in the fourth quarter. And as you know, earnings on cash in today's short-term environment are pretty modest.

I see.

So that that modest interest income will offset only to a pretty small degree our overall interest cost.

I see. Okay. And Ken, I presume that you will not want to talk about, say, what is the preliminary outlook for the capital spending for '04 and also the production profile?

No, I think you'll get a real good story and a lot of information on that on November 4.

Okay, that's fine. Thank you.

Operator, before we take the next call, Gene, I hope you're still listening, if not, you can come back on if this doesn't clarify the point. Maybe we were just making a reference in our earnings release on page 11, we have two tables on prices. One of those includes derivative activity, the other one does not.

And our third quarter Europe gas realizations before derivative activity was $3.15, the $2.01 was after derivative -- the derivative losses in the U.K. And that $3.15 compares to $3.01 in the second quarter. So come back on if that doesn't -- isn't responsive to your question, Gene. Thank you. Okay, operator, I'm sorry, go ahead.

Sir, we'll take our next question from Ted Isaac with Lehman Brothers.

A couple of questions, first I heard you say to all you're not going to give any production guidance for '04 until the meeting; is that correct?

Correct. We'll wait until November 4. We'll have all the information you need at that time, Ted.

Okay, great. My second question has to do with Ashland's ownership and MAP, and are you looking at buying that back or what's objection current statement regarding that?

Ted, this is John Mills, you're aware of the put-call arrangement that-- first effective 1/1/05, you know, that where we're looking at numbers to see -- I don't think it's any secret, we've not tried to make it a secret that that first option for the -- for our call is coming up within now 15 months, so that, yeah, we're certainly actively looking at alternatives. But beyond that, we're not going to comment.

Is it something that you'll make a definitive statement on one way or the other at some point or is it something that, you know, if you could just lead out there on an ongoing basis? I mean, if you decided not -- if you had made the decision not to exercise it, you know, will you ever -- will you state that ask we are just not going to do it, or will you leave it out it's always a possibility?

I guess the way we'll feel right now, of course it's not exercisable right now, but the way we feel right now we'd leave it out there as a possibility. I don't know why we'd limit ours to any particular path or alternative if -- as you're aware, I think, the option is ever green after 1/1/05 so market conditions change, strategic alternatives change, I don't believe we'd want to limit ourselves in any way if we looked at it, you know, first quarter '05 and concluded it was not in our interest to exercise the call but six months later looked at market conditions and other narcotics and decided that it was.

Okay. Thanks.

It's clearly an option we like to have. There's no reason to ever, you know, try to divorce ourselves from it. It's a great option to have out there. It's a one-way option, it's ours.

Is it just a question of price or what are the key issues you'll think about in making is this decision?

Well, the mechanics, I think you're aware, Ted, the mechanics of the call would be that we'd have in effect we'd negotiate for a period of time and assuming we couldn't reach agreement on a price, then we'd have investment banker, you know, we'd choose one and they'd choose one and if the two conclusions of value from the respective investment bankers are win 10% of each other, you add the two up, divide by two and that would be the transaction price.

Assuming they're more than 10% apart, we would nominate a third and take the value that was the average of the closest two. And then add 15% to it so that in effect we would be acknowledging that we'd be buying an asset above market price. So that we would have to, in my view, we would have to be able to demonstrate maybe the synergies in combining the minority interest with the majority interest in order to justify paying above market for that asset or any other asset.

Okay. Thank you very much.

We'll go next to Jay Saunders with Deutsche Bank.

Thanks, a couple of quick questions. On the Cap Ex, where do you think Cap Ex will end up for the year, and if you could break it down by segment that would be great. And also on the downstream, the 15,000 barrels a day FCC capacity addition, where does that come through, I guess it comes through in the runs number, operate your utilization at a much higher rate or not. And was that 15 in total or at each of the two Gulf coast plants?

I'll let Gary Piper take the second one. On the first one, right now, the capital budget that we put out at the beginning of the year, it's detailed very much by segment, and we put it out I think in early February, has not materially changed, not changed enough for us to really put out anything different than that for 2003. So there really have not been material changes to that.

You just look much, you know, pretty low through nine months against that.

I tell you what happens all the time in this experience on capital budgeting if you follow them, things get analyzed and booked much better in the last quarter and you usually see -- you're going to see us get pretty close to the capital budget, I'm sure.

Okay.

The only caveat I'd put on that is the $282 million of KMOC, which obviously was not included in that late January, early February release.

Which is now making it into the foreign MP number?

Correct.

Correct.

All right. Regarding the FCCU question, you'll see that coming through on our statement on the other charge and blend stocks line. That allows us to go out and buy additional cat feed on the open market and we then run that through the enhanced cat crackers the 15,000 barrels a day is the combined for the Garyville and Texas city expansion.

Okay. Thanks.

Aside reminder, ladies and gentlemen, if you would like to ask a question, please press star 1 on your touch-tone telephone. We'll go next to Steve Enger with Peachtree Parkman.

Hi guys.

Hi, Steve.

A couple of things, one, Ken, on OERB, if you make the adjustments to the number reported in the second quarter you come up with something well below 20, the adjustments for some out-of-period things but you guys are suggesting why you're going to be back at the $20 million kind of level in the third quarter or excuse me in the fourth quarter?

We, receive, quite frankly, as you do have a very, very difficult time forecasting some of the things that go on, particularly the gas for resale activity that we participate in, and quite frankly, sometimes how the mark-to-market gains and losses on paper that's used to back up that gas for resale goes, and 20 is really just the best estimate I can make at this point in time. I wish I could provide you more detail of the pieces of that, it's just very, very difficult to do.

Whatever happened in the third quarter is going to not reappear in the fourth quarter and you're going to have a better result?

I believe so.

Okay. Couple of things on production. On the Powder River Basin, do you know where you're at in terms of getting permits to drill new wells? Do you have a substantial number? Are you kind of getting back on track there or are you really still hindered in terms of what you can do in drilling new wells?

We're pretty much on track, Steve. I think as you know there our talking and others who have talked about this, when the permitting process, when the decision was made, it took a while for people to get not us, not just the operators, but for the government agencies to get together and process things. But we're seeing that move along pretty much as we expected. It's not an impediment to us.

Okay. And then finally in Camden Hills, do you have any sense for when you may start to see some declines there? Is that going to be a significant impact on next year, Ken, or are you going to be able to extend key rate for another year?

I think it's looking right now pretty much flat for next year, Steve. Declines would start sometime after that but external next year it should hold up pretty well.

Okay. Thanks a lot.

That's what our forecasts are right now.

Thanks.

We'll go next to Fred Leuffer with Bear Stearns.

Ken, can you give us an update on what reserve replacement looks like this year "X" the Russian purchase?

I tell you, what I hate to keep repeating this, it's a detailed story, I think it's going to be relatively good but we'll give you an all of lot of detail on that on November 4. I don't want to get into that on this call today.

Chief operating officering at the bit, I can't wait to get there.

I know, only 10 days.

Can't come fast enough for you. See you then.

See you there.

This concludes today's question-and-answer session. At this time I'd like to turn the call back over to Mr. Ken Matheny for any additional or closing comments.

I'd like to thank everybody for their participation today and as you can tell, some of the questions, some of interest that people have, we will have all -- not all the answers but most of those answers at our November 4 analyst meeting coming up here like I said in about 10, 12 days. So looking forward to seeing people there, and that's all I have to say. Thank you very much.

Once again, this does conclude today's conference. We thank you for your participation. You may now disconnect.