馬拉松石油 (MRO) 2004 Q3 法說會逐字稿

Good day, everyone, and welcome to this Marathon Oil Corporation third quarter, 2004 earnings conference call. Today's call is being recorded. For opening remarks and introductions I'd like to turn the call over to Mr. Ken Mathney, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Okay, thank you very much, Carol, and good afternoon to everyone. I too would like to welcome you to the third quarter 2004 earnings teleconference call for Marathon Oil Corporation. With me on the call today from Marathon Oil are Phil Behrman, Senior Vice President of Worldwide Exploration, Steve Hinchman, Senior Vice President of Worldwide Production, Janet Clark, Senior Vice President and Chief Financial Officer. Also with me from Marathon Ashland Petroleum are Gary Heminger, President, and Gary Peiffer, Senior Vice President of Finance and Information Technologies. I'm going to spend about 30 minutes reviewing third quarter results, then we'll open the call to questions. About two hours after this call ends these prepared remarks will be placed on the investor relations portion of our website and will remain there for 1 year. I do need to remind you 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 it's annual report on form 10K for the year ended December 31, 2003 and in subsequent forms 10Q 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. In connection with the proposed transfer to Marathon Oil Corporation by Ashland, Inc of its interest in Marathon Ashland Petroleum, LLC and other related businesses, each of Marathon, New EXM, Inc and ATB Holdings Inc. has filed with the US Securities and Exchange Commission a registration statement on form S4 that included a preliminary proxy statement of Ashland and a prospect of Marathon,New EXM, Inc and ATB Holdings. Investors and security holders are urged to read the preliminary proxy statements and prospectus which is available now and a definitive proxy statement prospectus when it becomes available because it contains and will contain important information. Investors and security holders may obtain a free copy of the preliminary proxy statement prospectus and the definitive proxy statement prospectus when it is available, and other documents filed by Marathon, Ashland, New EXM and ATB Holdings with the SEC at the SEC's website at www.sec.gov. The definitive proxy statement plus prospectus and other documents filed by Marathon may also be obtained for free from Marathon by calling investor relations at 713-296-4171. Now let's move on to the quarterly results. Reported net income for the third quarter was $222 million or 64 cents per share. This was a decrease of 126 million when compared to the second quarter 2004 income from continuing operations of $348 million or a $1.01 per share. Net income adjusted for special items was $296 million or 85 cents per share in the third quarter compared to the second quarter's $407 million or $1.18 per share. Special items in each quarter were pretaxed non-cash mark-to-market losses on our long term gas sales contracts in the United Kingdom of $129 million and $95 million respectively. Due to the volatility of the forward gas sales curve in the United Kingdom, Marathon has decided that all gains or losses related to these contracts will be treated as special items when reporting our financial results. Third quarter net income adjusted for special items was less than the second quarter, primarily because of lower upstream production volumes and lower refining and wholesale marketing margins partially offset by higher crude oil prices in the third quarter. Looking at the upstream segment, third quarter operating income totaled $222 million or $7.87 per BOE. In the second quarter it was $343 million or $11.12 per BOE. Lower segment income in the third quarter was attributable to significantly higher mark-to-market derivative losses, lower volumes and, to a lesser extent, higher exploration expense partially offset by higher prices. The third quarter upstream segment included a negative $204 million of derivative related impacts including $129 million mark-to-market loss in 2 long term gas sales contracts related to Brae. The remaining losses primarily associated with crude oil hedges in the United Kingdom and Gulf of Mexico. In the second quarter the derivative related impact was a negative $126 million and that included $95 million of mark-to-market losses on these same Brae contracts. Focusing on domestic upstream operations, third quarter operating income was $244 million or $14.73 per BOE versus $285 million or $16.09 per BOE in the second quarter. Lower third quarter income was primarily attributable to lower volumes and higher derivative related losses partially offset by lower DD&A and higher prices. Our average domestic realized liquids price, excluding derivative activity, was $35.56 per barrel, $3.82 greater than the second quarter level of 31.74, but $1.79 less than the increase in spot WTI which was $5.61, primarily due to widening sweet sour differentials as our third quarter domestic crude production was over 60% sour grades. Our third quarter average domestic gas price of $4.76 per MCF, excluding derivative activity, was down 26 cents from the second quarter level of $5.02. For lower 48 gas sales our realized price was $5.65 or 13 cents below second quarter lower 48 prices but in line with the 21 cent decrease in average bid week prices for the quarter. Derivative related activity was a negative $58 million or $3.50 per BOE compared to a negative $23 million in the second quarter, primarily result of our crude oil hedges including a $17 million mark-to-market loss on a crude oil hedge related to Petronius production in the Gulf of Mexico that previously qualified for hedge accounting but now must be mark-to-market. Exploration expense was $13 million in the quarter or 76 cents per BOE, down from the second quarter level of $15 million. DD&A in the third quarter was $5.39 per BOE compared to $5.89 in the second quarter, primarily result of an impairment taken in the second quarter related to cancellation of a deep water Gulf of Mexico exploration license. All other domestic costs in the third quarter totaled $8.19 per BOE up from 7.53 per BOE, the level that we incurred in the second quarter. The increase is primarily the result of higher production and ad valorem taxes associated with higher crude oil prices and fixed costs that don't change with the lower volumes associates with weather down time in the Gulf of Mexico. Domestic liquids production came in at 81,000 barrels of liquids per day, that was down 7% versus the second quarter, again primarily related to Gulf of Mexico weather. During the third quarter 4 major storms impacted Gulf of Mexico production resulting in deferred crude oil production of 510,000 barrels during the third quarter. All company operated properties have returned to production with only minor damage. Viosca Knoll 786, or the Petronius platform, remains shut in. Prior to Hurricane Ivan Petronius was producing approximately 25,000 barrels of oil equivalent per day. Damage assessment activities are under way and predictions about a likely start-up date are premature until the damage assessments are complete and recovery plan is finalized. Natural gas production was 598 million cubic feet per day, down 7% from the second quarter. Again, a result of weather related downtime in the Gulf of Mexico. Total deferred gas production in the Gulf of Mexico for the third quarter was about 1.7bcf. In addition, Camden Hills well number 1 began producing water about 2 months earlier than expected. Turning to international upstream the operations had a lose of $22 million or $1.91 per BOE compared with income of $58 million or $4.45 cents per BOE in the second quarter. Lower income in the third quarter was the result of significantly higher mark-to-market derivative and hedging losses, lower volumes, higher exploration expense partially offset by higher prices. Our average foreign liquids price of $37.07 per barrel was up $6.16 sequentially, in line with the $6.22 cent increase in dated Brent. Our domestic price realizations in Russia do not track Brent and actually lag the Brent quarter on quarter increase. International crude realizations from our West African and European operations, outpaced the Brent increase primarily due to the timing of liftings. The average gas price of $2.79 per MCF was down 28 cents primarily due to sales mix as a European business unit sales were seasonally lower and were also impacted by planned and unplanned maintenance while sales of EG gas were slightly higher quarter-over-quarter. Derivative related activity was a negative $146 million or $12.53 per BOE including $129 million of mark-to-market losses on 2 long-term gas sales contracts related to Brae. Derivative related activity in the second quarter was a negative $104 million, $7.88 cents per BOE and that included $95 million of mark-to-market losses on the previously mentioned long-term sales contracts. International exploration expense was $31 million or $2.65 per BOE, up $18 million from the second quarter, primarily result of the Crimson well that was plugged and abandoned in the quarter. DD&A was $7.72 per BOE, up 99 cents per BOE over the second quarter primarily as a result of relative production mix in Brae and a prior period adjustment to the cost of reserves at Foinaven. All other costs total $9.08 cents per BOE, that's up $1.25 per BOE versus the second quarter. Field level controllable costs were up in the third quarter due to facility maintenance on the Brae B platform, Foinaven and Heimdal. Production tax increased, primarily Russian mineral extraction taxes due to higher crude oil prices and the second quarter included the reversal of an accrual related to a fire on the cargo ship Jumbo Challenger in Equatorial Guinea. International oil liftings were 76,000 barrels of liquids per day, down 16% from the second quarter as a result of lower liftings in Gabon and Foinaven. Gas production was 303 million cubic feet per day down 6% over the second quarter level due primarily to increased injection in Kinsale Head, unplanned downtime and outside operating facilities as Foinaven and Heimdal partially offset by higher production in Equatorial Guinea. Production on a world wide basis for the quarter just ended was 307,000 barrels of oil equivalent per day versus 372,000 barrels of oil equivalent per day including Canada for the same quarter last year. Three main components reduced production year-over-year. First, asset divestitures reduced production approximately 35,000 barrels of oil equivalent per day. Second, we continue to see around a 8% decline rate in our base assets, that's about 30,000 barrels of oil equivalent per day. And third, we experienced more weather related and maintenance downtime in the current quarter. These 3 reductions have been partially offset by new production primarily from Equatorial Guinea. Turning now to downstream results, Marathon's refining marketing and transportation reportable segment income in the third quarter was $391 million, essentially flat with the third quarter 2003 level of $394 million. Second quarter 2004 results total $577 million. The 2003 third quarter includes $34 million of gains related to the sale of interest in two refined product pipelines that Marathon includes in the RM&T segment. Because of the seasonality in the downstream business, I will compare the third quarter 2004 results against the third quarter in 2003. Crude oil prices increased from $37.05 at the end of June to $49.64 at the end of September, representing a 34% increase during the quarter. The market continues to be very volatile due to the fear that crude and product supply capabilities are not sufficient to meet growing demand, that terrorist activities will disrupt supplies and that social and political unrest in a number of the major crude oil producing countries could also disrupt the flow of crude oil. In addition, Hurricane Ivan blew through the Gulf of Mexico late last quarter and the U.S. oil industry has yet to fully recover. The combination of shut-in crude oil on the Gulf of Mexico due to the storm damage and the hurricane related disruption of crude oil imports into the gulf coast, resulted in crude oil inventories being reduced to January lows. Likewise, the after effects of Hurricane Ivan shut in a number of refineries for a few days that depend on heavy Louisiana sweet crude from the gulf. Combined with turn arounds under way elsewhere in the Gulf Coast and the East Coast, this storm significantly reduced product supplies delaying the traditional seasonal stock build. In spite of high crude oil prices refining wholesale marketing margins were relatively strong in the third quarter. Last quarter margins were strong initially due to concerns about the adequacy of gasoline supplies during the prime driving season and later due to concerns about the adequacy of distillate supplies heading into winter. Chicago crack spreads were relatively strong during the September 2004 quarter, averaging about $7.70 per barrel down slightly from the $8.22 per barrel average in the September 2003 quarter. However, on a two-thirds Chicago, one-third U.S. Gulf Coast bases, a 3-2-1 crack spread was essentially the same at about $7.35 per barrel in both September quarters due to very strong gulf coast margins. Due to the dramatic increase in crude oil prices during the September, 2004 quarter, our wholesale prices, especially on our non-gasoline and non-distillate refined products, did not increase as fast as the spot market prices included in the 3-2-1 calculation quarter-over-quarter. This is primarily due to the fact that prices for our other refined products didn't change as quickly or as frequently as spot gasoline or distillate prices which are used in the 3-2-1 crack spread calculation. For example, 3% residual fuel oil prices were about $18.50 per barrel lower on average than WTI last quarter, versus only about $5.50 per barrel lower on average in the same quarter last year. Due to the significant increase in crude oil prices during the quarter, our crude in transit effect was a negative $70 million during the September, 2004 quarter versus about $10 million positive effect in the same quarter last year. More than offsetting these negative factors, however, were the following positive factors: Due primarily to the more than $3 improvement in the sweet sour differential in the current quarter versus the same quarter in 2003, maps crude oil acquisition costs improved this quarter compared to the quarter-to-quarter change in the WTI price. Our refinery volumetric gains also had a much more favorable benefit this quarter than the same quarter last year, primarily because of the improvement we made in our cat cracker at Catlettsburg earlier this year as part of the major repositioning project and the much higher prices we realized on those volume metric gains in the current quarter. As a result, our refining and wholesale marketing gross margin increased from 8.6 cents per gallon in the September, 2003 quarter to 9 cents a gallon in the current quarter. MAPS over all consolidated refined product sales, excluding buy-sell volumes, total about 5.2 billion gallons, that's down 1.2% from the same quarter last year. Speedway SuperAmerica same store gasoline sales were down about 1% quarter-to-quarter, primarily reflecting the high prices that we try to recovery retail throughout the quarter. SSA's gasoline and distillate sales were down about 21 million gallons quarter-to-quarter, primarily due to the fact that SSA operated fewer stores during the quarter compared to the same quarter last year. At the end of the September, 2004 quarter, Speedway SuperAmerica operated 1685 stores compared to 1791 stores at the end of the September, 2003 quarter, continuing MAP strategy of consolidation and focus on high volume locations. SSA's merchandise sales on the same store basis increased about 10% last quarter. As a result even though they operated fewer stores last quarter, total merchandise sales increased by $46 million quarter-over-quarter. SSA's gasoline and distillate gross margins decreased from 13.5 cents per gallon in the September, 2003 quarter to about 11.9 cents per gallon last quarter, again reflecting our attempts to increase a significant increase in raw material prices at the retail level last quarter. Our refineries ran very well during the first 2 months of the quarter, averaging about 1 million 6 thousand barrels per day of crude oil throughputs. Year-to-date MAP has set 16 new monthly production records throughout its refineries. In September our refinery throughputs were down to about 918,000 barrels per day primarily due to an unplanned outage at our Catlettsburg, Kentucky refinery to repair damage to 1 of our vacuum tower heaters. In addition, while our Garyville, Louisiana refinery was spared a direct hit from Hurricane Ivan, we reduced its major units to minimums and shut down the minor units for a few days as a precautionary measure. Total crude oil throughputs for the quarter averaged 977,000 barrels per day. Turning to the integrated gas business segment, operating income was $18 million in the third quarter of 2004, compared with a loss of $8 million in the second quarter of 2004. The primary reason for the increase was that the second quarter included the recognition of $18 million of gross start-up costs associated with our LNG project in Equatorial Guinea. Included within the integrated gas segment is income from our 45% equity interest in the AMPCO methanol plant. Operating income for the third quarter was $13 million and totals $43 million year-to-date. AMPCO is one of the newest methanol plants in the world having started operations in 2003. It is a world scale methanol plant and is a low cost producer. Methanol prices have remained strong in 2004, averaging $220 per ton through September and we expect them to remain relatively strong for the remainder of the year and we still estimate operating income and cash flow for the full year 2004 to exceed $50 million. Moving back to overall financial results, total segment income in the third quarter of 2004 was $631 million, down 31% from the $912 million in the second quarter. The upstream decreased by 35% while the downstream was down by nearly 32%. In the unallocated category, administrative expense was $90 million in the third quarter. The increase over the second quarter level of $84 million was primarily due to pension and OPEC(ph) effects related to outsourcing. Included in the quarter was stock-based compensation expense of $24 million and up front costs of $7 million incurred to outsource portions of the Marathon and MAP accounting and IT functions. Net interests and other financial costs were $40 million in the third quarter, lower than our guidance of $45 million as a result of interest income and capitalized interest, yet both were higher than anticipated. Cash adjusted, that went down by $267 million during the quarter to $1.6 billion as a result of strong cash flow in the quarter. The cash adjusted debt to total capital ratio at September 30, is 17%, down from just under 20% at June 30th, and a peak of 48%, just more than 2 years ago. These are preliminary numbers and I need to remind you that once the acquisition of the minority interest in MAP is complete, our cash balance will be reduced by approximately $2 billion. Marathon's pretax income for the third quarter reflecting just Marathon's share of downstream income was $355 million. The tax provision was $133 million for an effective tax rate of 37.5%. Third quarter preliminary cash flow from operations was $754 million, preliminary cash flow from operations before working capital changes from $627 million. Finally I want to make a few observations about the fourth quarter and the full year of 2004. For 2004 we've hedged a portion of our anticipated oil and gas production utilizing 0 cost collars. We've also swapped a part of our anticipated gas production for 2004. We have no oil and gas hedges in 2005. There have been no changes to our hedge volume since last quarter. The detail of IM's and prices are included on pages 29 and 30 of our June 2004 10Q, so I will not repeat them here. On the domestic upstream side we expect fourth quarter liquids production to be about 60,000 barrels of liquids per day and gas production should be about 590 million cubic feet per day. Because of the uncertainties surrounding Petronius, these estimates assume no Petronius production in the fourth quarter. Domestic exploration expense is anticipated to be approximately 10 to $25 million. On the international upstream side liquids production in the fourth quarter should be about 100,000 barrels of liquids per day, up from the third quarter due to increased production in EG, Russia, the UK North Sea and balancing liftings in Gabon. We expect gas production to be about 400 million cubic feet per day up compared to the third quarter due to increased seasonal sales across all of our European operations. And international exploration expense is anticipated to be approximately 30 to $45 million in the quarter. On a BOE basis we expect fourth quarter world wide production to be approximately 325,000 barrels of oil equivalent per day and for all of 2004 we expect production to average about 335,000 barrels of oil equivalent per day, excluding acquisitions and dispositions. This year's total estimate for production is down about 25,000 barrels of oil equivalent per day from our prior guidance of 360,000 barrels of oil equivalent per day due primarily to deferred production from 3 areas: The Gulf of Mexico accounts for 9,000 barrels of oil equivalent per day due to the Gulf of Mexico weather and principally an assumption that Petronius will remain down for the entire fourth quarter. Second, delayed production ramp-up in EG accounts for about 9,000 barrels of oil equivalent per day. The reduction in EG is entirely related to mechanical issues during commissioning of our Phase 2A expansion. We expect to have all of these resolved and reach full facility capacity of 57,000 barrels per day of gross liquid hydrocarbons by year end. Third and finally, the remaining difference is primarily due to unexpected down time and rig delays in outside operated properties in Europe. In early June we announced our intention to solicit offers for Pennnaco Energy and the related assets in the Powder River Basin. Strong natural gas prices and previous industry transactions in the Rocky Mountains were the main drivers behind this marketing effort. There was not an offer compelling enough for us to sell and as such we will continue to invest in and operate this asset. While the asset is not performed to original expectations, it provides a natural gas profile difficult to duplicate in the lower 48, and we have significantly increased our understanding of the area. Taking a forward look at the downstream, forward crack spreads have dropped from the strong levels experienced earlier this year but are still relatively strong for this time of year. The major unknown at the present time is how crude oil prices will react in the fourth quarter of this year and the impact those crude oil prices will have on demand. However, we still expect that the crack spreads will be significantly higher than mid-cycle differentials due to the concerns about the adequacy of refined products supply as we move into the winter season. Assuming margins remain strong in the fourth quarter, we still expect that our total crude oil throughputs for the calendar year will average at or above historical levels. Finally gasoline demand has been relatively strong in spite of the high prices we've experienced so far this year. As we discussed in last quarter's conference call, we have observed a deceleration in demand as retail prices exceed about $1.80 per gallon. Therefore based on current price levels and our recent sales experience we'd expect fourth quarter gasoline demand to be about flat or down slightly versus the same quarter last year. Integrated gas income is forecasted at about $10 million for the fourth quarter. Net interest and other financial costs excluding any exchange rate gains or losses will be approximately $45 million in the fourth quarter. Unallocated administrative expenses should be about $70 million in the fourth quarter, reflecting $10 million of pension settlements related to outsourcing but excluding any impact of share price movement and resulting gains or losses on equity based compensation. Like to remind everybody again that for every 1 dollar change in our stock price will result in $4 million of expense. For 2004, we continue to estimate our effective tax rate will be 38%. In closing we have made significant progress on our focus next few goals for the year, we finalized the investment decision on EG LNG Train 1 and continued construction on this important project. Earlier this month we signed an agreement with BP to utilize our offtake capacity at the Elba Island for a minimum period of 5 years beginning mid-year 2005. We continue to realize significantly improved exploration success. We have a number of additional wells to drill this year. And along with our partners continue reentry negotiation from Libyan officials. While we have experienced some delays we are well along on our liquid expansion project in EG, we have just received government approval for our Norwegian development plan for Alvheim project and just yesterday received clearance that should allow development of the core field in Ireland to move forward. The acquisition of Ashland's 38% interest in MAP continues to move forward. Transaction is subject to several previously disclosed conditions, including approval by Ashland's shareholders, consent from public debt holders, and receipt of a favorable private letter ruling from the Internal Revenue Service with respect to the tax treatment. We have filed registration statements and proxy materials with the SEC and are responding to comments. In addition we submitted a request for private letter ruling to the IRS on the tax free status of the proposed transaction. We continued to discuss the complex tax issues related to this transaction with the IRS, we have not resolved all issues with the IRS and we're exploring alternatives for the unresolved issues. We continue to believe that the transaction will close. With respect to the timing of closing, it is possible that the transaction will close by year end, but it is more likely that the transaction will close in the first quarter of 2005. Additionally I would remind you that we issued 34.5 million shares of Marathon common stock at the end of March to help facilitate this transaction, which diluted our earnings for the quarter, but on a perspective basis we anticipate this transaction will be accretive to earnings. For example, had we owned 100% of MAP under the terms of the agreement, our earnings per share this quarter would have increased to approximately 22 cents. I'll now open the call up to questions. I ask you to please identify yourself and your firm affiliation for the benefit of those listening in. Carol.

Thank you, sir. At this time if you would like to ask a question, you may do so by pressing the star key followed by the digit 1 on your touchtone telephone. If you are using a speakerphone for today's call, please make sure that you're mute button is turned off to allow your signal to reach our equipment. Once again that's star, 1 if you would like to ask a question. And we'll go first to Doug Terreson with Morgan Stanley.

Good afternoon, everybody.

Afternoon, Doug.

In ENP, just to double-check, assuming that output at Petronius returns to normal levels by the beginning of 2005, is previous production guidance of 350 to 360 still the operative level for 2005?

Yeah, Doug, this is Steve Hinchman.

Hi, Steve.

You certainly appreciate that we have a high degree of uncertainty of what is going to happen with Petronius. The operators is doing their assessments now. And until we complete the assessments on the damage at Petronius it is premature for us to really make a projection on re-establishing production from that facility. But if you exclude Petronius, we have previously talked to you about our Equatorial Guinea Phase 2B project. Our original forecast for that had that project coming on line early in 2005 and as we've previously stated we now believe that we'll have the -- the commission will be completed at the end of the first quarter and we'll ramp up production beginning in the second quarter. So that impact on its own is about a 6,000 barrels per day impact against our original guidance for 2005. You know, everything else, as we look out at 2005, with the exception of Petronius and that particular project slip as a result of the LPG construction, we're pretty much in line with prior guidance.

Okay. That is good. Secondly, it appears that the core of natural gas project in Ireland is going to be moving forward during the next quarter or so. So, my first question is whether that would be your expectation as well. And, if so, can you provide the time frame by which you would expect first output from this project. That is assuming, based on Ken's comment, that development does begin by early 2005.

Of course we received the planning approval that we've been waiting for and so with that in hand, we expect we will proceed with the development of this project and expect first targeted gas production would be in the second quarter of 2007.

Great. Thanks a lot, guys.

And we'll go next to Paul Ting with UBS.

Hi, just a couple of questions. First of all on the upstream. Given what you know right now, do you have any sense of what the derivative loss might be or if there will be a derivative loss in the UK gas contract for the fourth quarter? And maybe similar comments on the U.S. side where you saw $58 million of derivative related loss. What can you tell us about the fourth quarter at this point, if anything?

I'll tell you, Paul, this is Ken, it is really impossible for -- to put predictions on that, Paul. The comparison has to be made as against the forward gas curve which would be what's effective on December 31 of this year, matched against our future sales prices and you really can't make that call. Paul, that is really the reason because of the inability of this, the non-cash nature of it and quite frankly the way it distorts our income that we chosen to treat it as a special item and will continue to do that for all future quarters, whether it's a loss like it was this quarter or when it reverses, which I think ultimately it will and turns into a gain, we're going to treat it as a special item. So, I think you're best off to just ignore trying to predict it, Paul.

What about the U.S. side, is that a little bit more determinable?

Yeah, if you look at what we have in the 10, you know, we have all the volumes and prices in the 10Q and you can just make your own crude oil assumption and gas assumption against the prices that we have in there, Paul.

Okay. Secondarily, on your MAP comment, the closing date has been nudged back a little bit from this year into first quarter of next year. I know you're restricted in how much you can say about MAP, but the closing delayed beyond first quarter?

Well, first, I would say that we still fully expect the transaction to close. You know, at the outset our legal counsel advised us that it would be 6 to 9 months for the tax ruling and it is probably been about 6 plus months since we filed, so we're well within our expected range, although at this point, you know, given that we didn't get the tax ruling at the end of 6 months we're kind of in 7 months now, you got to expect that you push that out a little bit. So, I think at this point we wouldn't foresee closing any later than the first quarter.

Highly confident it's going to close before the first quarter?

You know, I don't know --

End of the first.

what you're trying to accomplish by using the term highly confident. I can tell you this, we're have every expectation that the transaction will close and it is just a matter of getting the final issues resolved with the IRS and getting clearance from the SEC.

Okay. Thanks a lot.

And we'll go next to Arjun Murti with Goldman-Sachs.

Thank you, just a few followup questions guidance related. As a result of some of the tax changes in Russia, have you all -- are you all making any change to your plans there, assumed the target was 50 or 60,000 barrels a day out a few years and then what are you all expecting from the Powder River Basin, now over the next couple of years given that you're now, it looks like, going to keep the asset.

Arjun, we're, of course, putting our plans together at this time, so it is a little premature to me to dig down into the individual assets. I can tell you that Russia will be a little bit slowed down from our expectation because we have slowed down some of our capital investment. As we've been developing in the Potanay field, we have gotten some unexpected results there, a little bit lower pay, some of our water flood has not been responding as we thought, and so we slowed the investments down there to get a better grip on that particular field performance. But offsetting that is that we have had wonderful performance in the Camen -- East Camenoid field, especially in the cortasious(ph) horizon there where we have drilled 17 wells, or have 17 completions on production. Each of those wells now are producing well over 400 barrels a day. Some of the more recent wells have actually been producing around 1800 barrels a day and we have over 270 well locations in this field of which we'll have about 40 completions done by the end of the year. So there is quite a few moving parts in Russia. I suspect it will be a little lower but I really can't tell you exactly the magnitude of that now in Russia. In the Powder the marketing activity slowed us down a little bit this year. We started off with getting about 3 rigs during the -- up in the -- really up and running in the second and then first quarter and now we've geared back up to running about 9 rigs. We'll drill about 300 wells this year. That is probably about 50 wells shy of what we had originally expected. Next year we'll drill about 500 wells and keep those 10 rigs running. So, the Powder will be maybe slightly lower but reasonably within the projections that we've made previously.

And then just a final question, if I can. Given your desire to build up the Norwegian business, beyond Alvheim and those developments, which look like they're moving forward, would you have an interest in BP's Ormanlunga stake?

I guess, Arjun, I'd have to say that we don't comment on those kinds of things.

Sounds like it strategically could fit in between Norway and Global Gas and such things.

I guess if you think so, Arjun. But, we really can't comment on that.

Okay. Thank you very much.

I'd like to remind everybody that Steve's comments and Arjun's questions are very good. We're in the middle of our planning process on production and in fact our business plan for all of next year. As normal, when we have our call in January we'll be giving a full update of our forecast for 2005 at that time.

Then we'll go next to Neil McMann with Sanford Bernstein.

Hi, two questions. First of all just looking towards Libya, maybe you can give an indication of the, say, the cost for borrow it is going to take to get back in maybe on from bonuses to get back into Libya and is that what is holding up your reentry into Libya? And, secondly, can you give us some indication on your operational up-time in the North Sea versus last year when there were some problems last year and earlier this year. Maybe lastly just back to Corrib(ph), given the fact it was in big inflation in the cost base from oil service companies, how much will CapEx increase on Corrib and will there be rig availability to actually start work on the development phase of Corrib through '05 to try and meet the second quarter 2007 start-up time.

Okay, Neil, I'm going to take the first of those questions to be the easiest and the shortest and that is, you know, we and our partners are working very hard to get back into Libya. We want to get in there, I think the Libyans want us back in there as well. While we're negotiating with the Libyans, we'll really not going to comment on anything. It wouldn't be the right time to do that.

Neil, on the operational up time in the UK, our company operated facilities in the UK based on the McKinsey benchmarking rank on, typically, best in class, where our up time is typically on the order of 97%. However, we have experienced problems in up-time but most of it has been in our outside-operated properties. Last we had a pretty significant compression problem on Foinaven and this year we continue to see a little disappointing up-time performance on our outside operating facilities, both at Foinaven and at Heimdal. Regarding Corrib, you're exactly right, there are pressures that are causing costs to go up. We typically don't comment on the cost of our projects, but with the increase in costs we're also seeing increases in the prices and so we still see Corrib as a very attractive investment and provides strong economics. Rig availability at this point in time we have not seen the same rig availability issue in the UK as we've seen in other places in the world and we are in the process of securing or maturing those contracts for rigs at this time. Corrib project is not -- critical path on that project is not rig. It will be in the terminal construction. So I don't see rig availability as a problem in terms of execution.

Could I just have a followup on Corrib on the operational up time. I just want to get a feel for how sensitive is that Q2, 2007 time frame for delivery, because it is obviously quite important given the whole issue that we're seeing in UK gas and the longer term supply for UK gas and just on the operational up time what would you say your over all number at the moment on operational uptime with your operated and non-operated fields in the North Sea.

You know, Neil, I don't have a number that allows me to give you a total up time for our operations. The Corrib start-up date is the best estimate at this time coming from the operator of Corrib, and as you know projects can move up or down, but at this point in time that is really our best estimate would be the second quarter of '07.

Thanks.

And we'll go next to George Gaspar with Robert W. Baird.

Good afternoon.

Yes, George.

First question relating to the 70 million negative in transit number, can you break that down on a per-barrel negative basis?

Gary, you want to handle that?

Yes, this is Gary Peiffer. We general have 6 to 7 million barrels at the moment of crude oil on the water. At that rate it is about $10 per barrel for the quarter.

Okay. All right. Now it leads to my next question and that is on tankering costs, can you give us a little background over the last 12 to 15 months the differential in tanker costs per barrel that you're experiencing and how do you actually cost this out? Does this get -- do you sign on this tankering costs when a crude, for example, leaves the Middle East or wherever, and -- or do you sign on to it when it arrives here and you cut the actual price that you're paying for the crude?

George, I think Gary Heminger can get that one for you.

Okay.

George, we do it about 3 different ways. First of all, about 60% of all of our supply is domestic based, but for the crude that's on the water. From West Africa to the U.S. gulf coast we have seen about just in the last few months a doubling of those tanker rates in comparison to last year. Our Suez max vessels, we have seen, again, about a doubling of those. From the Arab gulf, we've seen the price go up almost 4 times compared to last year. Right now we're paying just under $5 a barrel or the equivalent transportation cost is just under $5 a barrel compared to about $1.10 same time last year and about $2.20 just a month ago. So that is how much the transportation rates have changed. On the--but there are some crudes that only about 20% of our crude that we bring in do we have the transportation costs that we have to go out and apply for or broker. The balance is all priced FOB when it is delivered to loop or wherever it is, delivered into the gulf coast. I'll let Gary Peiffer talk about the actual accounting and how we cost it.

I think from a costing standpoint or maybe more from a economic evaluation standpoint we're always constantly evaluating our foreign crudes, late in, versus our domestic alternative. So in a sense, even though the freight rates are higher, what that will tend to do, all things being equal, is we use less foreign crude and use more domestic crudes. So, it's a constant reevaluation or reoptimization of the process to see what is the cheapest laid in cost to our refineries of the crudes we have available. So, from an accounting standpoint you really can't compare our freight costs of crude because we may be one period buying more domestic crudes with less costs, freight costs, versus foreign where the initial price is cheaper and the freight is higher. So, it's basically we look at it on a total laid in cost basis including freight. And as Gary said, with these higher freight rates you obviously need, all things being equal, a relatively lower foreign price to make it competitive with domestic crudes.

And George, one other thing I forgot to mention, we have about 100,000 barrels a day Mexican contract. Those rates have gone from $1.05 - they're at $1.05 today, they were about 32 cents same time last year and about 45 cents a month ago. So they've doubled in the last month. And that's with a Suez max type vessel.

And maybe 1 other thing, Gary was talking about 60% domestic and that really -- that includes our Canadian also in that category.

Okay. So, basically, if one was to try to attach a cost factor to a 42-gallon barrel and you're looking at a $5 transit number versus 1.10, it works out to 10 cents a gallon versus 2.5 to 3 cents.

Today your math is correct.

The reason I'm asking, I don't think consumer appreciates the added cost of bringing, you know, this crude over at higher prices. If I could ask another question on refining. You know, you guys have a pretty good ability to run sour crudes and that's potentially to your advantage right now because of differentials. Are you experiencing anything unusual in the kind of cross section of sour crude that you're bringing into your refineries now versus let's say a year ago that would be creating a different refining yield impact?

George, if you look at the total assays of just a normal run of the day medium sour, no matter what type of crude it is, you will get a generally less than a 2% yield change in the mid-section across of -- across the mid-section assays of crudes. If you go from a very sweet barrel to a very sour barrel, in total, and we have looked at that whole array of about 20 crudes, the yield can change to be about 6%, but you have to understand, we're already running the maxim -- the crudes that provide the maximum yield to us based on the cracks, whether it be a distillate cracked or a gasoline cracked. So we're already running, as Gary just mentioned on the way we cost transportation, we running the crudes that give us the best yield everyday.

Okay. So would you say you're in the mid-range when you talk about this 2% or 6% problem?

I would say we're maybe even on the -- little bit on the upper end of the range.

On the upper end. Okay. Thank you.

And we'll go next to Jennifer Roland with J.P. Morgan.

Thanks. I have a question for you on the capital spending program. Looks like your capital spend the past couple of quarters has been pretty conservative relative to what you had been guiding for for the full year. So, I was wondering if your capital spending target for the full year has changed or should we expect either significant ramp up in the fourth quarter or maybe some push-off of capital spending into '05?

I think, yeah, actually our capital spend is about where we thought it would be. I think typically we saw it lag a little bit behind our plan in the first 3 quarters and do tend to catch up in the fourth quarter. So we think we're going to be right about, you know, where we guided you to.

Okay. So that would imply CapEx almost doubling then from this quarter to next?

That could very easily happen, Jennifer.

Okay. Thank you.

And we'll go next to Gene Gillespie with Howard Weil.

Okay and I have 2 questions. One, what is the termination date on the Petronius contract that's subject to mark-to-market. First question. The second question is what percentage of your Russian production are you exporting and what can you do to make that a greater number?

I'll take the first one, there, Gene. On the Petronius, that is part of the 44,000 barrels a day that we have hedged this year as relates to Petronius it is 16,000 barrels a day. That qualify for hedge accounting up to the first 2 quarters but the last half of the year it has to be mark-to-market.

And that -- that goes away at the end of the year?

Correct. We have no oil and gas hedges for 2005. And quite frankly right now I don't have any plans to put any in place.

Gene, this is Steve Hinchman. We have been exporting our quota a little over 35%. You know, we continue to look for ways to increase the export and the next best option tends to be rail. But with our volume level and with a fairly attractive domestic price, the rail option just isn't economic for us other than maybe a few months out of the year. So we continue to look for ways to improve that revenue stream, but right now we continue to just be a part of the allocation.

All right. Thank you.

And we'll go next to Steve Enger with Petrie Parkman.

Hi, guys. Couple of things. I guess for Phil, if you can update us on plans to go back to Neptune and then, as you may have had the opportunity to digest some of the info from Nova Scotia, what your view is on further exploration there.

Let me take the second one first, Steve. On Nova Scotia we're doing 2 things. First of all, we're, as you point out, looking at our lessons learned from the Crimson well and then planning the next steps. It is a little early to say what the next steps would be. The second thing that we're doing is we're looking at our Annapolis discovery. And because of the short falls in production at Sable, we're looking at opportunities to work with the Sable owners to see about developing or commercializing Annapolis in some form. So those discussions, again, are in its infancy but we're exploring those opportunities. In regard to Neptune, I'll turn it over to Steve.

Yeah, Steve, you might be thinking about Kansas, I don't know. Neptune is where we're progressing, really, the development plan for Neptune. There has been ample wells drilled on Neptune to date. So we're actually at this point in time moving into from feasibility into feed. We'll probably begin feed sometime in early November and we expect we'll sanction development of this project in the first half of 2005.

Great. I had the impression you guys were at least thinking about the need for one additional exploratory well there. That's not the case?

No, we're just sharpening our pencil on the cost but we don't believe we need any additional wells.

And then finally for one of you on Angola blocks 31 and 32, obviously lots of agreements yet to be forged and approvals to get, but what kind of timing could occur between now and first oil as you see it separately on blocks 31 and 32?

Yes, Steve, this is Phil Behrman, on Angola block 31 we have the northern -- what we call the northern development area, northeast development area. What we're doing now is working with our partners on 2 fronts there. First of all, we're beginning our preliminary engineering studies which will ultimately lead to a development and there probably is some appraisal activity associated with it. Both activities will go on simultaneously and we'll probably culminate in the end of 2005 or early 2006. In terms of block 32, we're currently drilling on block 32, as you know. Drilling the Gengibre well and we're going to go ahead and look at our results of that well and plan our next steps for block 32. It is about a year behind in terms of our overall activity plan and so we're just beginning to work those plans with our partner, the operator TOTAL, in this case, and so we'll be continuing our exploration activity in 2005.

Great. Thanks, guys.

And we'll go next to Doug Leggit(ph) with Smith Barney.

Hi, good afternoon, guys. It seems a little bit early but could you just remind us where you see the overall exploration success this year in terms of reserve replacement. The reason I'm asking specifically is you talked about both Powder River and Russia performing little bit below expectations. I'm just wondering is there any risk of impairment in either of those two assets that could pull the number down a bit for this year?

Starting with the accounting question of impairment, you know, the Powder River is an asset that we've had reviewed by Netherlands Sul every year since we acquired it. Yeah, I don't think it is any surprise that results since the acquisition have been a little bit disappointing and we're in the process of doing that technical review as we are with all of our properties.

And Russia?

Likewise. You know, Steve mentioned earlier we've had some disappointments but we've had some upside surprises and we are going through the internal audit on that. It is not complete yet, but that--we will have that complete in the fourth quarter.

And Doug, I think maybe the other part of the question you're referencing there, you know, we had a target of around 240 million BOE of reserve additions this year. Is that what you're asking?

Yeah, that's what I'm referring to.

That's still our target. We don't have any reason to change that at this time.

Based on pretty comfortable and realistic.

The significant drivers for that reserve addition were the sanctioning of the EG, LNG project, the sanction of Alvheim and Clag and Corrib, and I think, as we said through this conference call that we're very comfortable that those projects are moving forward at this time. So those were the big drivers for the reserve adds in 2004.

Okay, great stuff. Thank you.

And we'll go next to Paul Cheng with Lehman Brothers.

Hi, good afternoon. Maybe this is for Ken and Janet, first question. Is there any uninsured damage related to Ivan as being bought in the third quarter, if not, is there any reason not?

Janet can handle that one.

I think as Steve or Ken has already told you that the operator is currently in the process of trying to assess just what the damage is. From an accounting perspective, when you got repair work, you charge those expenses as you do the work. We do have insurance in place, both in terms of property damage and business interruption insurance.

Janet, what is the deductible?

We've got different deductibles on both BI and on the property damage. Property damage I think it's between 7 and 10 million and the BI is not exactly sure what that amount is. I think you can assume that there will be some amount of uninsured losses associated with the damage.

Should we assume that if not in the third quarter then sometime in the fourth quarter, before you end the year, you probably are going to have to book some of the spending?

Steve, I think you have a better answer for the timing of it. I suspect there will be some booking of spending for restoring the productions that will occur in the fourth quarter. But, again, we really haven't even had the initial assessment yet. So I have no idea at this time how much that might be.

Okay. Steve, as of September 30, within your system, are we overleaf, underleaf or we are at balance?

We're about balanced, I think, for the year, relatively speaking. I'm sort of guessing off the top of my head, overall. Yeah, balance to date, we're pretty much on balance.

Okay.

Around 63,000 barrels over for the year.

How much.

63,000, so essentially balanced.

63,000. Okay. And, Ken, for the Elba Island, you signed a contract with BP, can you share with us what kind of return you might get in those contracts.

No, we're not in a position to share the returns, Paul, but we're certainly going to make a profit off of that. I think, as you know, we have maintenance expenses that we pay at Elba Island in the 14, and $15 million a year range and the margins we expect to make off of this will certainly give us a return on that.

Okay. Is it double-digit, single digit.

Good try.

Never hurt. Two final questions. First is for Gary, what is your retail margin look like so far in October compared to the average of the third quarter.

So far in October, you know, we only have 24 days in, but it would be a little bit less than the average for the third quarter. We have had to restore prices every week in order to be able to try to move these costs to the marketplace. And as Ken said, where demand is down oh about I would say 1.5% for the first 24 days on a same-store basis and margins are probably down. What I've seen month to date we would be down a couple cents versus our average for the quarter. Just at retail.

Um-hum.

Not wholesale, just at retail.

I see. Very good, thank you. And then finally I don't know this maybe is for Steve, maybe is for Ken. Ken, if we look at over the past at least for the past 12 months or so, that's number of times the production nolo has been changed unfortunately that it has changed for the downward. Wondering, is that the point to perhaps in the way how the original data production outlook is being assessed--obviously that there is a lot of factors could be changed but are we not putting a conservative enough of an approach in having, perhaps, there is some cushion because, I mean, often time we going to see surprises and more often than not surprises will lead to maybe some downward surprise then upward. Should we look at the whole thing and saying perhaps that we need to be more conservative in the estimate putting out and give yourself maybe more cushion.

Steve is here now. And Steve A big part of those forecast and we'll let him answer that.

Well, you know, a big part of our revisions that we've had to make this year have been primarily a result of project delay in EG and primarily really due to compressors in EG. And perhaps in hindsight, and hindsight is always 20-20, we should have been more conservative with that, but we're using the judgment of the vendors that we were working with and their guidance in terms of when we thought things would be corrected and on line. The other aspect of the big hits for us has been Gulf of Mexico weather and we're probably in there with a pack of many other people in the third quarter with four major storms having come through the gulf and in particular very damaging storms in the form of Ivan. You know, we typically estimate around 6 days of weather related down time in the Gulf of Mexico and we have far exceeded that in 2004. You know, the weather down-time that is a statistical average over about a 15 year period. So I think we're using our best judgment there in terms of the project in EG. Perhaps we should have been more conservative that we certainly have thought we've been right every time. The other aspect that has hurt us a bit this year is been really some of our non-operated properties and some of the upsets that we've seen there and extended shut-downs, significantly more than what the operator had indicated would be and we typically take the operators advice. In one case was a -- from the Heimdal was a pig that got stuck in a line in a clean-out operation and it was stuck for over a month which is difficult for anybody to predict there.

Steve, I think I just want to make one comment. I understand what you just said, but throughout the years of your career, I think you have seen more often than not from time to time, we're going to see some surprises or some outages and that when that happened or any surprise, that is more often than not that the surprises need to down size revision. So from that standpoint I think it is one thing that you have the best guess but on the other hand if you're going to have at some number putting on the public domain, should we be even putting some cushion for yourself to take into consideration of that unforeseen or unexpected down time.

Your point is taken.

Thank you.

And we'll go next to Fred Lueffer with Bear, Stearns.

Hi, a couple of questions. First, do you have an estimate on the exit rate for production at the Powder River Basin this year?

Yeah, Fred, Powder will exit a little over 70 million a day.

Steve, that's a bit lower than the last guidance you gave us which I think was 90. And, you know, my--my reconciliation here in the third quarter actuals versus production guidance for Marathon looks like the Powder River Basin was maybe the biggest component of the change not only the--you know, the Gulf of Mexico for the quarter was only 4,000 barrels a day. What is going on in the PR base base is it rigs or whatever.

No, the Gulf of Mexico was much higher than 4,000 barrels a day, Fred. And, you know --

Well, on average. Remember, you only lost it for about half of one month, right?

We had four storms come through with different shut-ins on each and of course for the quarter we were down about 9,000 barrels a day in the Gulf of Mexico.

You're estimating 9,000 for that?

Um-hum.

And can you take me through that? With Petronius and each of the other fields?

Well maybe we can get back to you with that level of detail but we had deferred production in the Gulf of Mexico of about 833, 000.

Independently he and I got a different number than that so I'm just wondering -- .

We would be happy to do that with you later, but not during the conference call here. But that is the correct number.

Those are the numbers, Fred.

And the Powder has been slower to react for us. We've seen positive results in our Sheraton area development this year. We saw a continued decline at the beginning of the year, that has been offset now and we're now experiencing an incline. And as I said, we got off to a slower start this year than what we had originally expected in the Powder but we're ramping back up our rig activity. So for the most part we've seen some more disappointing results in -- deeper in the basin in the Big George than what we expected, but the coals and Sheraton area have exceeded our expectations. We haven't drilled as many wells and our average time to permit has been going up, it's been taking a little longer to get wells permitted, slowed us down a little bit and that standpoint, but Fred we still like the resource potential in the Powder and the fact that it is located in the lower 48 and it is still a growth profile for us for the long-term.

What is the end of line decline for your wells there?

I don't know that off the top of my head right now, Fred.

Do you have an estimate of production for the PRB for next year?

We're in the process of putting that together at this time and as Ken said we'll share all of that detail for you in January.

You think it would be higher or lower than 70 million a day.

It will be higher than 70 million a day.

Okay.

If I can just ask a question on that --Ken? Yes. What are the unresolved tax issues that you mentioned in your press release, national mention in there.

I'll tell you, Fred, you know, we're working with the IRS to resolve these and you don't do that by talking about them in public. That is just not the right way to handle them. Unless, you know, we're confident they're going to be resolved. We're confident that we're going to ahead and get the transaction closed.

Both press releases talked about alternatives around these problems and I guess my concern would be would 1 of these alternatives involve Marathon paying more for MAP than the agreed upon price so far.

Want to go on to the next question, Fred or is that your final one?

Yeah, it is my question. I would like it answered.

I don't think that question is going to be answered. You're making a supposition that is kind of a hypothetical example that we're not going to address.

And we'll go next to Paul Sinkie with Deutsche Bank.

Hi, guys. On a slightly less detailed note, could you just confirm for me that the Powder River Bason remains an area that you're going to develop or is it my understanding that you might still have it for sale?

No, we checked the market. We didn't get a compelling enough offer. We liked the--we still like the exposure to the resource and the growth potential to lower 48 gas, so we've done our check on the market and we're now focussed on moving with the development.

Great. And the second one is next year's capital expenditure guidance, could you say more about that? I think you did the fourth quarter pretty comprehensively but anything to say about next year.

Again, I think we've said a couple of times that we really are in the early phases of putting together our plan for next year and when we do get it finalized we'll be sharing all that guidance with you.

Great. And very specifically on Equatorial Guinea can you tell us where you are with the LNG project development now that you've got FID there. Have you started construction or where are we at?

It's construction started and a lot of the civil works are well under way at this time.

So we're on schedule then for a start-up when?

Fourth quarter 2007.

Okay and that is all in good shape. Great. Thanks a lot. I'll leave it there. Thank you.

And we'll go next to Mark Gilman with Benchmark Company.

Guys, good afternoon. I had a couple of things. Ken, did I hear you reference quickly something about a reserve adjustment at Foinaven.

Not a reserve, there was an adjustment to the cost reserves which causes DD&A to change. That's what we mentioned. Capitalization and some costs there.

Is that a one-time thing?

Yeah. It was only 4 to $5 million, a very small onetime item. Had nothing to do with the reserves there.

Okay, I misinterrupted.

Sorry if I didn't make that clear.

I was looking at the other international accrued realizations and relative to my understanding of Russian domestic prices, the number is kind of inconceivably low. At least in conjunction with 35% exported at what we assume would be a Euros price. My indications are that Russian domestic price is in the neighborhood of 23 in the third quarter, am I missing something here?

Um, well, I got my year-to-date, I don't have the third quarter. Do you have the third quarter.

I don't have third quarter but if you look, we had -- we had -- our domestic prices were somewhere in the $21 - $22 range there in the third quarter, Mark.

Okay. But the export price. I mean, the average Euros quote in the period was, I don't know, 37, 38.

Correct.

So how do you do a one-third, two-thirds and get to the-- .

The domestic price--I know our average realization for Russia has been on the order of about $20 a barrel. And that is taking into consideration the 65% domestic, 35% export.

Mark, I misspoke, I had just the September price. It was actually closer to 18 for the whole quarter.

Okay. Maybe we'll take it off-line. Can you give me an idea of what the hedging gains were for Integrated Gas and also what you did with those refining and marketing hedges and whether there was any gain or loss on those on the quarter?

On Integrated Gas side it was very, very small, Mark. In Integrated Gas it was about $5 million in gains for the quarter.

And R&M?

R&M, Mark, we were breakeven for the quarter.

Okay. Gary, just one final one. Can you talk a little bit about whether there has been any variability in this environment in what you're doing with respect to product purchase for resale which MAP does a lot of?

We're down a little bit on the product purchase for resale because the north-south differential which I've talked about a lot has been--has not been able to hurdle the transportation costs to move a barrel from the gulf coast up into the midwest. You know, we've had a lot of discussion about, you know, why is the gulf coast cracks (inaudible) strong and the midwest been weaker this year and it's because there has been a tremendous amount of storms and damage and down-time in the gulf coast, which has propped up margins in the gulf coast and the midwest all the plants in the midwest, both MAP and our competitors have run very strong and we've been well supplied. So that is really why we've seen a reduction in the north-south differential.

Gary, when you say you're down a little bit, does that mean you're losing money on product purchase for resale or down versus some prior period?

No, I'm just saying down on the amount of volume that we're moving and we're purchasing. We're making money on the amount. Everything that we're buying and reselling we made money on it. It is just the actual volume has reduced. And I might have that number.

I can figure out what the number is, Gary.

It's just we've reduced our purchases a little bit this year only because north-south differential has been negative.

So I can assume that margin has been down.

And the margin is lower, correct.

Okay. Just one final one. Can we split out for Petronius what the liquids and gas numbers were prior to the storm? I assume that 25,000 equivalents is net. Is that correct.

Yes, that is a net number. It is about -- Petronius is running just about 19,000 barrels of liquid, 32 million cubic feet of gas.

Okay, guys, thanks a lot.

And we have a followup from George Gaspar with Robert W. Baird.

Yes, thank you. A couple, now, you probably talked about this, but on your gross forward '05 hedged positions, how far along are you percentage wise? What are the price ranges both oil and gas.

George, we don't have any hedging of any kind in 2005.

Okay. All right. And then question on Petronius. Maybe this is more theoretical. And I understand there're rules in the Gulf of Mexico. Why is it that oil can't be off. I assume that the problem here is pipeline more than platform problem at this point. Can you first of all explain that?

It is more platform than pipeline.

Okay. Is this--what about off-loading to tanker or it doesn't make sense because you have got platform problems you've got to solve.

Yeah, it is not an issue of export.

It is not. Can you explain exactly the magnitude of what you're looking at, yet, that needs to carry the repair all the way through potentially the fourth quarter?

Well, again, George we don't know. That is an assumption that we've made. The operator really has only had access for a little over a few weeks to really go in and begin to assess the damage, and at this point in time, they have not completed that assessment or finalized their go-forward plans. So, again, it is just anything I say about Petronius at this time would be wrong.

Okay. Is this a problem of not having enough personnel in the industry to jump on something like this and get the job done and everybody so tight in the Gulf of Mexico that there is just not enough flexibility to really get something like this turned around in a shorter time span?

You know, I mean, everybody is competing for the available services, but that's not really a significant issue with Petronius. Pet throne use, you know, Ivan's, the eye of that hurricane really essentially came right over top of the pet throne use's platform and I think there has been information in the public that shows pictures of pet throne use with the helipad and crew corridors basically turned over on to the drill deck. So, again, that's what we -- again, we have to wait for the assessment from the operator and finalize both plans.

I see. Okay.

It is a big unknown at this time.

All right, thanks for that.

Our final question today comes from Steve Enger with Petrie Parkman.

One clarification, Steve. The Powder River Basin you said some of the coals up by Sheridan are working but you did say that you'd been disappointed in some of the Big George results.

Yeah, the Big George was a bit of a disappointment against what we had originally talked to you guys about probably late last year and it is likely a little more under saturation in that cold than what was thought to begin with. The Sheridan area is coming on gas immediately and we're seeing good results and being good gas content, et cetera, in there. So we're quite pleased with that and we've got a large feed position in the Sheridan area to execute on which makes it a little less complicated to develop.

Okay. And given that you're going through your processor Netherlands Sulis, reserve or resource implications then based on the results you see this year are possible?

Yeah, I guess it is possible, yeah, we'll know when they finish their evaluation.

Okay, thanks.

We have no further questions at this time. I'll turn it back to you in Mr Mathney.

Okay, I'd like to thank everybody very much for participating today and we'll be back talking to you again at the end of January. Thank you.

That does conclude today's conference. You may now disconnect your lines.