馬拉松石油 (MRO) 2004 Q1 法說會逐字稿

Please stand by. We are about to begin. Good day, everyone and welcome to this Marathon Oil Corporation first quarter 2004 earnings conference call. Today's call is being recorded. For opening remarks and introductions, I would like to turn the call over to Ken Matheny, Vice President of Investor Relations. Please go ahead.

Thank you very much, Philip. With me on the call today for Marathon Oil are Clarence Cazalot, President and CEO; Phil Behrman, Senior Vice President of Worldwide Exploration; Steve Hinchman, Senior Vice President of Worldwide Productions; and Janet Clark, Senior Vice President and Chief Financial Officer. Also with me from Marathon Ashland Petroleum are Gary Hemminger, President and Gary Peiffer, Senior Vice President of Finance and Information Technology. I will spend about 20 minutes reviewing the first quarter results. Clarence Cazalot will follow up with an update on our EG LNG project, and then we will open the call up to questions. Approximately two hours after this call ends, these remarks will be placed on the Investor Relations portion of our website. They will remain up there for a one-year period.

My remarks today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10(K) for the year ended December 31, 2003, and in subsequent forms 8(K), cautionary language identifying important factors, but not necessarily all factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

The first quarter of 2004 was a good operational and financial quarter for the upstream business, as commodity prices continued at high levels while the downstream felt the effect of these same high commodity prices and significant planned refinery maintenance work. Reported net income for the first quarter was $258 million, or 83 cents per share. There were no special items in the first quarter of 2004. This was an increase of $74 million when compared to fourth quarter 2003, income adjusted for special items of $184 million, or 59 cents per share. First quarter net income exceeded fourth quarter net income adjusted for special items, primarily because of higher crude oil and natural gas prices and lower derivative related losses; partially offset by lower refining, marketing and transportation income primarily related to significant planned refinery maintenance activity in the first quarter. Reported net income for the fourth quarter, 2003, was $485 million, or $1.57 per share and included after tax special items of a $278 million gain on the sale of our Canadian operations, a $15 million positive adjustment for interest on prior year tax deficiencies adjustment, and $8 million positive adjustment to the loss on the disposition of U.S. Steel.

The reconciliation of net income adjusted for special items to net income, including the explanation of the reason for using this non-GAAP measure, is included in our fourth quarter 2003 earnings press release. This press release is posted on our website under press releases, which is located under the newscenter tab. Before I begin the segment discussion I want to remind you that beginning with the first quarter of this year we began reporting segment income for our integrated gas business. Previously this was included in a segment we called other energy related business. Certain income and expense items previously included in the other energy related business segment are now included in the exploration and production and refining, marketing and transportation segments. The quarterly segment income comparisons I discuss today will reflect these reclassifications from prior periods. Our Investor Relations package, currently on our website, also reflects these quarterly reclassifications.

Looking at the upstream segment, first quarter operating income totaled $478 million, or $14.08 per barrel of oil equivalent. In the fourth quarter it was $339 million or $9.85 per barrel of oil equivalent, excluding discontinued operations. Higher income in the first quarter was attributable to higher crude oil and natural gas prices, lower derivative related losses and lower exploration expense; offset by a volume mix change between liquids and gas and a contract settlement gain in the fourth quarter of 2003. The first quarter upstream segment included a negative $8 million derivative-related impact including a $14 million mark-to-market gain on two long-term gas sales contracts related to Brae. In the fourth quarter, the derivative-related impact was negative $57 million, of which $33 million were mark-to-market losses on these same Brae contracts.

Focusing on domestic upstream operations, first quarter operating income was $306 million, or $16.14 per boe, versus $249 million, or $12.22 per boe in the fourth quarter. Higher first quarter income was primarily a result of higher prices and lower exploration expense, partially offset by reduced volumes. Our average domestic realized liquids price excluding derivative activity was $29.74 per barrel, $3.37 greater than the fourth quarter level of $26.37, but less than the increase in spot WTAI of $4.18, primarily due to the widening sweet/sour differentials. Our domestic crude mix is about 55% sour grades. Our first quarter average domestic gas price of $4.71 per MCF, excluding derivative activity, was up 80 cents from the fourth quarter level of $3.91. Looking at just our lower 48 gas sales, our realized price was $5.51, or $1.01 above fourth quarter lower 48 prices; in line with $1.11 increase in average bid week prices for the quarter. Derivative-related activity was a negative $17 million, or 90 cents per boe compared with a negative $15 million in the fourth quarter.

Exploration expense was $8 million in the quarter or 43 cents a barrel of oil equivalent, down from the fourth quarter level of $25 million driven by lower dry hole expense. DD&A in the first quarter was $5.24 per boe versus $5.03 per barrel in the fourth quarter. All other domestic costs in the first quarter totaled $6.87 per boe down from the $7.10 per boe level in the fourth quarter. Domestic liquids production came in as expected at 92,000 barrels of liquids per day, down 7% versus the fourth quarter, primarily due to natural declines at Troika, work-overs at Petroneus, weather-related and field declines at Indian River and the sale of Yates. Natural gas production came in as expected at 701 million cubic feet per day, down 5% from the fourth quarter primarily due to natural declines and weather-related interruptions. Turning to international upstream, segment income was $172 million or $11.46 per boe compared with $90 million or $6.40 per boe in the fourth quarter. The higher income in the fourth quarter was primarily attributable to higher prices and volumes and lower derivative-related losses, partially offset by higher DD&A.

Our average foreign liquids price of $28.22 per barrel was up $1.95 sequentially, less than the $2.60 increase in [inaudible] primarily because of lower price realizations in Russia which do not track [inaudible]. The average gas price of $3.46 per MCF was up 19 cents as a result of higher sales prices in the United Kingdom and Europe. Derivative-related activity was a positive $9 million, or 63 cents per barrel of oil equivalent, including $14 million of mark-to-market gains on two long-term gas sales contracts related to Brae. Derivative-related activity in the fourth quarter was a negative $42 million dollars, or $2.95 per boe and that included $33 million of mark-to-market losses on the same previously mentioned long-term sales contract. International exploration expense was $17 million, or $1.09 per boe, down $2 million from the fourth quarter. DD&A was $6.54 per boe in the first quarter, up 29 cents over the fourth quarter primarily a result of higher asset retirement obligations in the U.K. due to a change in the exchange rate assumption.

All other costs totaled $7.77 per barrel of oil equivalent, down 25 cents per barrel of oil equivalent versus the fourth quarter as a result of a lower cost production mix. Production came in as expected. International oil liftings from continuing operations were 92,000 barrels per day, up 3% compared to the fourth quarter. The increase was primarily a result of development activity primarily in Equatorial Guinea partially offset by compressor and generator upsets at Brae and work-overs in Gibone. Gas production came in greater than planned at 435 million cubic feet per day, up 14% over the fourth quarter levels from continuing operations, due to increase sales at Brae which took advantage of additional capacity and sage and increased gas sales in EG which was low in the fourth quarter due to an unplanned methanol plant outage. Worldwide production averaged 373,000 barrels of oil equivalent per day in the first quarter, flat with the fourth quarter level and nearly 8,000 barrels a day equivalent above our January guidance; primarily a result of additional gas sales with Brae taking advantage of additional capacity and sage.

Turning now to the downstream results, Marathon's refining, marketing and transportation reportable segment income in the first quarter was $49 million compared with a first quarter 2003 level of $70 million. Because of the seasonality in the downstream business I will compare the first quarter 2004 results against the first quarter in 2003. Crude oil prices increased about 10% during the current quarter, ending March at $35.76 per barrel. While there continues to be no shortage of events that could occur, the physical market is well supplied on most fronts. But the market's attitude in the face of low stock levels since the supply, though adequate, is tentative. In spite of the relatively high crude oil prices experienced during the quarter, refining and wholesale marketing profitability was relatively strong primarily due to the supply uncertainty resulting from the gasoline tier two regulations which became effective on January 1, 2004. We are pleased the EPA acted swifting to not allow waivers for higher sulphur gasoline imports, but rather continue the approach of allotment credits to meet the new specifications.

Crack spreads in the quarter were strong in MAP's primary Chicago market. During the most recent quarter the Chicago crack spread averaged $7.15 per barrel, up from $6.54 per barrel in the same quarter last year. Despite these positive fundamentals there were a number of items that caused MAP's first quarter 2004 income to be less than the 2003 quarter. First, MAP wasn't able to fully participate in the strong refining market because we performed a significant amount of planned maintenance activity at our refineries last quarter. For example, MAPs crude oil throughputs averaged only 789,000 barrels per day and that was down 64,000 barrels per day from the March, 2003 quarter. These lower crude oil throughputs were primarily due to planned maintenance on the crude units at our Garyville, Louisiana, Catlettsburg, Kentucky and Canton, Ohio refineries during the first quarter of 2004.

Even though crude runs were lower this quarter, we were able to purchase additional feed stocks primarily for our cat crackers which allowed to us run about 100,000 barrels per day more intermediate feed stocks compared to the March, 2003 quarter when both the Garyville and Texas City cat crackers were undergoing planned maintenance. Our total refinery throughputs were about 3.7% higher this quarter than last year's first quarter. Now that we have completed the majority of our major turn arounds for 2004, we are well-positioned to run at or above historic levels for the balance of the year. We also experienced higher manufacturing costs this quarter primarily due to work done at Catlettsburg to complete the repositioning project and additional planned maintenance work associated with a full plant turnaround at Canton. Prices dropped substantially in the March, 2003 quarter but actually increased in the current quarter. Wholesale margins especially on non-gasoline and non-distillate products were compressed compared to the 2003 quarter.

In addition the north-south differential averaged only about three quarters of a cent per gallon during this quarter compared to 2 cents per gallon in the March, 2003 quarter and that reduced our ability to profitably source refined products in the south for sale in the north. Late last year and early this year MAP sold crack spreads forward through the third quarter of 2004 at values higher than we thought were sustainable in the actual months these contracts would expire. Due to the continued run-up in crack spreads during the March, 2004 quarter, we recorded about a $10 million loss on the crack spreads that expired during the quarter and also recorded a mark-to-market loss of about $30 million on the crack spreads that will expire in the second and third quarters. Lastly, our foreign source crude oil prices were relatively flat in this quarter, resulting in a negligible in transit effect compared to a positive in transit effect of last year of about $15 million. The net effect of all these items resulted in our refining and wholesale marketing gross margins decreasing from 4.1 cents per gallon in the March, 2003 quarter to 3.4 cents per gallon in the current quarter.

MAP's overall consolidated refined product sales, including buy at sell volumes, totalled 4.7 billion gallons, or about 3% more than in the same quarter last year. While SSA's total gasoline and distillate sales were down about 66 million gallons quarter-to-quarter due to our sale of 190 locations in the southeast in the June, 2003 quarter; on a same-store basis gasoline sales were up 3.3%. At the end of March we operated 1,773 Speedway SuperAmerica stores compared to just over 2,005 stores at the end of March, 2003. And despite SSA operating substantially fewer stores, total merchandise sales were about even driven by the fact that merchandise sales on a same store basis increased 13.1%. SSA's gasoline and distillate gross margins were down slightly quarter-to-quarter from 11.7 cents per gallon in the March, 2003 quarter to 11.5 cents per gallon in the current quarter.

Looking at the integrated gas business segment, operating income was $15 million in the first quarter of 2004, compared with $2 million in the first quarter of 2003. The increase was primarily the result of increased margins in gas marketing activities, including mark-to-market changes in derivatives used to support these activities.

Moving back to overall financial results total segment income in the first quarter of 2004 was $542 million, up 27% from the $426 million in the fourth quarter, with the upstream improving by 41%, while the downstream was 49% less. In the unallocated category, administrative expense was $64 million in the first quarter. A decrease over the fourth quarter total of $67 million was due to lower employment related costs. Net interest expense was $38 million in the first quarter and this was lower than our guidance of $50 million, primarily as a result of higher interest income and higher than forecast capitalized interest. Cash adjusted debt went down by $837 million during the first quarter to $2.124 billion, primarily due to our issuance of $1 billion of common stock. The cash adjusted debt-to-capital ratio at March 31, 2004, is approximately 23 percent, down from 33% at the end of last year and a peak of 48% less than 21 months ago. I might add that these are preliminary numbers. MAP's pre-tax income for the first quarter reflecting just Marathon's share of downstream income was $423 million. The tax provision was $165 million, for a 39% rate. This rate is higher than our forecast rate of 38% as the tax provision included $3 million of prior year period adjustments. First quarter preliminary cash flow from operations was $289 million, and preliminary cash flow from operations before working capital changes was $617 million.

Finally I want to make a few observations about the second quarter and full year 2004. For 2004, we have hedged a portion of our anticipated oil and gas production utilizing zero cost collars. We have also swapped a part of our anticipated gas production for 2004. There have been no changes to our hedged volumes since last quarter. The detail volumes and prices are included on page 53 of our 10(K), so I will not repeat them here. On the domestic upstream side we expect second quarter liquids production to be flat versus the first quarter at about 90,000 barrels of liquids per day. Gas production should decrease to about 630 million cubic feet a day due to seasonal variations in Alaska. And domestic exploration expense is anticipated to be approximately $15 to $25 million. On the international upstream side, liquids production in the second quarter should be flat at about 100,000 barrels of liquids per day. We expect gas production to be about 320 million cubic feet per day, down compared to the first quarter due to seasonal variations in the U.K. and gas storage in Ireland.

International exploration expense is anticipated to be approximately $20 to $35 million. On a barrel of oil equivalent basis, we expect second quarter worldwide production to be down sequentially to approximately 348,000 barrels of oil equivalent per day. And for all of 2004, we still expect production to average about 365,000 barrels of oil equivalent per day, excluding any acquisitions or dispositions. Looking at refining and marketing, in spite of the significant reduction in crude oil throughputs in the first quarter of 2004, we expect MAP's total year crude oil throughputs will be higher than in 2003. As part of the significant planned maintenance work we did this past quarter, we increased the Garyville crude oil refining capacity from 232,000 to 245,000 barrels per day. In addition, completion of the Catlettsburg repositioning project during the quarter allows us to operate at a lower cost per barrel as well as improve the value of the yields from the same refinery inputs. Crack spreads have been very strong and we expect those crack spreads to remain relatively strong going forward.

Gasoline in demand, as well, has been relatively strong especially considering the higher prices we have experienced in the first quarter. We have just very recently observed some impact on demand as retail prices exceed $1.75 per gallon in most of our markets. However, we expect crude oil prices to moderate somewhat going forward which should help stimulate gasoline demand in the future. In addition, because of the improving economy, we expect distillate demand to continue to be strong. Integrated gas income is forecast at about $10 million for the quarter. Net interest expense will be approximately $45 million for the quarter; and for all of 2004, we project net interest expense of about $170 million. Administrative costs should be about $62 million in the second quarter. And for 2004 we continue to estimate our effective tax rate will be 38%.

Now, as I said, before we move into the question and answer session I would like to turn the call over to Clarence Cazalot who will bring us up to date on our EG LNG project.

Thank you, Ken, and good afternoon. I want to add some context to what was reported in our press release; and essentially on March 31, Marathon, The Ministry of Mines and Energy, GPetrol and upstream partners signed essentially all the commercial agreements that are required for this project. But there were several conditions that needed to be met. As we sit here today, all but three of these conditions have now been satisfied and one of these conditions involves the gazetting, or publication if you will, of the decree law that was recently signed by the President. And this decree law establishes the full legal rights of the LNG business. We expect these remaining obligations to be fulfilled shortly. We've not been delaying, however, with respect to positioning this project. We have continued to proceed with early works, particularly during the dry season here for this project, so that indeed we will be in a position by the fourth quarter of 2007 to deliver first LNG cargo. So I simply wanted to update you on that very important project particularly in light of the fact that we had talked about sanctioning that project in April. The sanction now will be in May. With that, Ken, I will turn it back over to you.

Okay, Clarence, thank you; and Philip we are now ready for the Q&A. I remind everybody to identify yourself and your firm affiliation for the benefit of those listening in. Philip go ahead.

Thank you. [Caller Instructions]. We go first to Steve Enger with P3 Parkman.

Hi, guys.

Hello, Steve.

A couple of things on Neptune. You guys announced results of a recent well. You've had, obviously, a lot of variability in net pay there and I know there's more to do, Phil, but what's your current view of the geology there?

Hi, Steve, it's Phil. The current view of the geology is--well, actually, let me stand back. We are still incorporating the results of the recent drilling of the Neptune 7 well. In addition to that we are reprocessing seismic data over the project itself--prospect itself. But, in lieu of that, what we did is, the results have come in within the predicted ranges. We knew there was quite a bit of variability in this particular discovery as well as other discoveries along the Atwater Foal Belt trend and we'll probably need some additional drilling besides the Neptune 7 well to fully understand the size of the discovery.

Okay. Are there implications from the most recent results for drilling on Kansas, Phil?

No, there really reason any implications on the Kansas well, which is located about nine miles away. We had already incorporated quite a bit of variability in what we are likely to find in Kansas and this is certainly within that range.

Phil, you want to give an update on the drilling on when we're going to drill Kansas?

The current spud date is approximately mid-May for Kansas.

Is that similar timing for Crimson offshore Nova Scotia?

Crimson is roughly early June, but we really can't be that certain on the exact timing of the Crimson well. It will depend on release of a rig from the Gulf of Mexico.

Okay, and then just one more. In Angola you've announced another discovery; I think you guys had suggested a 2008 start up for production from at least one of the blocks. Does that still look solid, or with the very large number of discoveries offshore Angola, do you think there's potential for a development queue to develop there and maybe slow that down?

I think our plans are still for first production in 2008, but really that requires agreement between all of the owners in blocks 31 and blocks 32, so that's still our plan and we need to get a consensus of all the working interest owners though to move forward.

Okay, and are those discussions starting to occur on the two blocks with multiple discoveries, or is that still a little premature.

No, those discussions have already started and are well advanced on block 31.

Okay. Thanks.

We go next to Paul Ting with UBS.

Good afternoon. A couple questions. First of all, the exploration expenditure figure that you gave ranged anywhere from $35 to $60 million. Is this more of an issue of timing-- compared to the $25 million in the first quarter, obviously it's expected to be higher. Is this an issue of timing or lumpiness of the dry hole or is this activity increase, can you put some flavor behind that?

Yeah, Paul. This is Phil Behrman. It's really a timing issue. Some of the wells really are straddling the reporting boundary between first and second quarter and so we're obviously not certain as to the exact reporting date, given our best estimate it is a little bit lumpy because it splits itself unequally between quarters.

Any guidance or expectation for the year exploration expense-wise?

I think our guidance is that it would be similar to 2003.

That's right, Phil. Paul, that's the best estimate we can give right now. The drilling program is not that dissimilar in total, so I would say it's similar to last year.

Great. Just two other issues if you can clarify. First of all can you bring us up to date about Libya, in particular, are you only negotiating as an Oasis group or have you been doing any kind individual negotiation with the Libyan government? And secondarily, bring us up to date if you can, on the gas and liquid Qatar project? Where do we stand on that scope and timing please?

In Libya, our teams have been fully engaged in negotiating re-entry with respect to Oasis only since late February when we were granted those authorities by the U.S. government; and we are making good progress, but I would reiterate, our entire efforts are focused only on oasis and with our partners Conoco-Philips and Amerada-Hess. We are not doing anything, nor are our partners outside of Oasis. That has been our agreement is to focus our efforts solely on Oasis. And we just had a high level executive visit to Tripoli and we would expect a CEO visit sometime in May. With respect to Qatar, the GTL project there, we continue our both technical and commercial discussions with Qatar Petroleum. I think we are narrowing down to really some of the critical issues around the costing of the project and again it's our expectation to sign a heads of agreement there sometime late second quarter, early third quarter so we can begin the front end engineering and design work.

Any sense of scope?

No, nothing beyond what we've talked about before, Paul. I think it's a large project. We've talked in terms of roughly 100,000 barrels per day of GTL products and, again, that's whether that's all done at one time or done in phases; I think that's all part of the discussions.

Do you have any capex targeted for GTL this year?

We would, if we do the front end engineering, yes, there would be some capital spend but, again, part of the agreements with our partners is that Marathon's expenditures this year would be rather minimal.

Thanks a lot. I appreciate it.

We go next to Doug Terreson with Morgan Stanley.

Good afternoon Clarence and company. In refining and marketing, were Canton and Catlettsburg back to normal operation by the beginning of the second quarter, and if not can you tell us when they did return to normal?

Doug, we brought Catlettsburg totally on line last week of February.

Okay. Good.

And Canton, Canton was down the majority of March and I think it came back around the 4th or 5th of April.

Okay. And also, I think Ken talked a bit about the hedging program. So on that topic can you tell us how much of your gasoline and distillate is hedged for the rest of this year and any related margin levels that you may have and also any hedging programs for '05 that you can talk about?

We don't have any hedging programs for '05. And, just a second, I have the information on, for the second quarter '04 we have approximately , here we go, we have 11 million barrels of gasoline hedged in the second quarter of '04 at $8.39. And 3 million barrels of--11 million in June of '04, 5 million barrels in the September quarter and that's all on gasoline; and the 5 million was the at $6.61 and then we have 3 million barrels of distillate in the June quarter at $2 and that's it.

Okay. One more question while we have you here, Gary, the refining margins have obviously gotten off to a good start in the second quarter and marketing seems to be doing a little bit better as well. So I was wondering if you could provide some indicator information for both refining and marketing in Q1 and also quarter-to-date Q2. If you don't have the numbers nearby if you could just comment on them qualitatively, Gary, that would be find.

As far as demand?

No, no, no, refining and marketing margins, Q1 versus Q2 quarter-to-date with more emphasis on marketing, really.

Boy, I don't have, I don't have the exact numbers.

Okay.

As far as retail, I can speak to retail. I don't have the wholesale numbers.

That's fine.

I would say that the retail numbers, Q1, Q2 are pretty much in line.

Okay.

Within a tenth of a cent or so of each other on the retail side, Q1and Q2. On the demand side, as Ken said, we were up 3.3% like versus like in the first quarter. We are still up like versus like but it is tempered just a little bit. I think we are up about 2.2% so far in the second quarter on the demand like versus like.

Still a good number. Thanks a lot.

We go next to Gene Gillespie with Howard, Weil.

Hello. I have a couple of questions regarding hedging-- the downstream hedging program. Gary, I assume this would be for you. Doug asked and you answered part of my question but lastly, do you plan to disclose the speculative hedges going forward? It was a fairly significant number.

Yeah, Gene, we have plans or we have in the past it's been in the 10(K) and it will be in the 10(K) going forward, any hedging derivative work that we do. As far as do we plan on doing any going forward, it just depends on where the market is. As I stated yesterday on the Ashland call, the reason we did the hedging in the first and second quarter is that we had significant planned downtime in the first quarter and the numbers were significantly above our mid-cycle margin forecast and we decided to lock in some of that, some of those on those margin basis. As far as into the third and fourth quarter, we have very, very little on our books this year and don't have any plans in '05 at this time.

I can understand stand you being opportunistic. I guess not having the ability to quantify this or not having the information to quantify it and given the fact it was a fairly material number relative to your overall operating pre-tax earnings, in your share of the operating pre-tax earnings, I guess that was the nature of my question. Would it be, is it possible to make it more transparent by posting it on your website like you do the upstream hedges?

We will take that into consideration, Gene.

Thank you.

We go next to Paul Cheng with Lehman Brothers.

Thank you. Good afternoon, guys. I think this is for a Clarence. Clarence, from the big picture standpoint is there any reason with your strong balance sheet and strong cash flow right now to even bother to hedge? After all I think for the long-term, hedging is probably a zero sum gain or maybe even a net loss when you take into consideration of the operating costs given that none of us really have a very good crystal ball to know where's the price going to be in the long-term?

Yeah, Paul, I think you raise a good issue and I think if you note what Ken Matheny's comments were when he talked about our current hedges. He said there were no changes in our hedge position from the last quarter and in fact I don't think there were any changes in the quarter before that. We put these hedges on at a time frankly that we weren't in quite the same position we are today and we saw prices that were well above our mid-cycle and helped guarantee, we thought, pretty strong cash flow. So, in hindsight, certainly, if we had it all to do over again we wouldn't put those on.

But, you're right, going forward I think we don't see the need to hedge in the upstream and I think you just heard from Gary Hemminger that in terms of the downstream requirements what we have in place today winds down by the end of this year and we don't have any plans to do anything beyond that and into '05. So, you're right, circumstances have changed. We are in a much stronger financial position today. Prices seem to be more resilient for a longer period of time than any of us would have expected, so I think we view it very differently today as you do.

Second question, I was wondering if you could give us a quick update in terms of Russia. Where is your production now and over the next six or nine months there? Any major development plan that you may be able to push through production?

Steve Hinchman is going to handle that, Paul.

Yeah, Paul. Our production plan is pretty much on track to what we expected and shared with you in the past. We are currently producing around 16,000 to 17,000 barrels a day of net production. Our plan for the year is to be around 19,000 barrels per day. And in terms of the execution of our program we are going to drill about 70 wells this year. Most all development wells, a few little step outs and it's in line with what I had described to you back in November. And pretty much on track to look at delivering around 60,000 barrels per day out in 2008. So things are going reasonably well.

Steve, does it make sense that, to even accelerate that program?

No, it doesn't make sense to accelerate the program.

Paul, because of the weather situation out there and the limited amount of time you can gear up to conduct your program, this is a long range planning effort and really, to a certain extent, what we are going through today is a full technical assessment as we are doing this. And we're acquiring a lot of new vintage seismic that helps a great deal in terms of picking and planning our locations because a big part of what Steve's doing is driving down the drilling cost. But the wells aren't as inexpensive as we'd like. So, to a certain extent, we're taking our time to make sure we get new seismic in the key areas, incorporate that data, pick our well locations right; particularly when it comes down to water flooding you want to make sure you've got a good reservoir understanding. So, I think the worst thing we could do today is try to run out there and accelerate production by drilling wells in advance of us having as full and complete an understanding of the reservoirs as is possible.

Finally, Ken, I think you answered the question about Libya, I know it's a bit premature, is there any kind of time frame when you think you may actually will be on the ground and start producing again?

No, I don't want to put a time frame out there, Paul. I would just say as soon as possible. We've been in there for the last two years on technical visits that were granted--permission was granted by the U.S. Government and so what we think we have a good understanding of what it's going to take, we've got good work programs put together and just as soon as all the agreements can be finalized and, we will be back on the ground.

Maybe I will ask it in this way. Let's say that today you sign everything, all the agreements, how quick--is it tomorrow or two months later that you will be on the ground?

If we sign the agreements today I think it's probably about a twelve-hour plane ride. My guess is we'd have people there in 12 hours. Good questions Paul, we need to move on, we've got a long list.

We go next to Jennifer Rowland of JP Morgan.

Hi. I have a question on Angola. When might we here results on the Venus well, and if that is successful would you be in a position to declare block 31 commercial at that point?

This is Phil Behrman, Jennifer. We don't have a firm timing of when we will be issuing information on the Venus well. Really we're waiting for government approvals to release that information. Current plans call for a declaration of commerciality on block 31 some time in the fourth quarter of this year and that's still our plan.

Okay. What about-- when might we here results on Deep Luba in Equatorial Guinea?

We are currently drill stem testing the Deep Luba well and so when we complete that process we'll have more information, certainly in the second quarter--by end of second quarter.

Then lastly, just a quick question on the Garyville expansion. Can you break out the cost of that expansion?

It was less than $10 million.

Okay. Thank you.

We go next to Jay Saunders of Deutsche Bank.

Thanks. Two questions. One downstream, that's the first one, the big yield on the gasoline in the first quarter, I assume most of that is because of the high feedstock run relative to crude. Is any of the expansions getting into that--to the yield increase for gasoline in the first quarter? And the second, is on Elba. Can you give us some more detail on who is going to sign the decree and at what point do you start getting nervous about meeting the end '07 first production in terms of a delay, if there is any?

Okay. Jay, we ran 65,000 barrels a day more of gas oil first quarter this year versus first quarter 2003, of purchase gas oil which would account for the majority of the increased yield. And well have some additional yields coming out of Catlettsburg due to the changeover from the RCC and the small less efficient cat into the new 95,000 barrel a day cat, very little consequence in the first quarter. You'll see us start stepping in the second quarter, but around 13,000 barrels a day of increased gas yield.

Gasoline yield starting in the second quarter?

You will start to see it happen in the second quarter because we didn't get the cat up fully running til the end of February, first part of March. So the numbers in the first quarter would have been diminimus.

Okay. Thanks.

Jay, on Elba, maybe I may have misspoke, I'm not sure, but the decree law has already been signed by the President but in order for it to be official it has to be gazetted publicly for a period of three days and all of that has been held up, I think as you're probably aware they held national election in EG this past Sunday. So really the past three weeks their focus has been on that and now that things will return back to normal, we expect to get that gazetting done in the near future. As well as the other couple of remaining items that need to be done. With respect to maintaining the schedule, as I said before, we're doing all of the early works today, particularly in terms of the civil work and getting equipment on the ground so we can indeed make that fourth quarter 2007 schedule. So I'm not concerned about that today.

So FID is just somewhat of a formality in the sense of your concrete kind of getting, meeting your time frame on the production?

Yes, FID, it is a formality, but it is when all the i's are dotted and t's are crossed, and our view is until that's done we're not going to declare a full F I.D. So, we just want to make sure everything is in place to our satisfaction.

All right. Thanks.

We go next to Michael Grotell with Dahlquist Capital Management.

I thank you. I am happy to say my questions have been answered.

We got next to Jack Eiden with Key Bank Capital Markets.

Hi, guys. A question, Ken, could you give us a breakdown on the refining and marketing, what was the downtime cost, maintenance cost and hedging losses that impacted the segment earnings during the first quarter.

Okay, on downtime, the best way to answer that was this year first quarter versus same quarter last year we ran 789,000 barrels a day of crude this year versus 853,000 barrels per day same quarter last year. That's really the best way to talk about throughputs and downtime. As far as the total cost, I will ask Gary Peiffer here if he has...

Well, quarter-to-quarter our manufacturing expenses were about $55 million higher this quarter than they were the same quarter last year. That was primarily driven by the Catlettsburg repositioning product which we finished up, as we said, in the first quarter and also at Canton when we were doing the turnaround work there, the planned turnaround work we also took that time to do some improvements in the cat cracker there that were expensed. So the primary drivers was the turnarounds and the doing, concurrent with those turnarounds, some other maintenance work.

And then on the hedging?

It was about $40 million in total was the impact of the crack spreads that we sold in the early part of the year and that was the negative effect in the first quarter.

Right, and $10 million of that was for barrels we had hedged in the first quarter and the other $30 was the mark-to-market effect of the balance for the balance of the year.

So we shouldn't see anything in the second quarter mark-to-market, you say?

It just depends on what the market does. That certainly could turn, but it depends on what the--the market has strengthened the last few days, it all depends on where the market goes. But the $30 million that Gary stated brought us up to date as of prices on March 31.

Excuse me, all those hedgings are related to Chicago Midwest or Gulf Coast?

They would be, they really would be both.

Okay. Thank you.

We go next to George Gaspar with Robert W. Baird.

Yes, good afternoon. A couple questions here. One on the Ashland acquisition, the MAP situation, the overview, update. Can you outline, at this point, how you're seeing the required borrowing as you move toward finality of that in the second half of the year considering the moves that you made on the equity offering and so on, can you give us some pointers on that?

Yeah, this is Janet Clark. As you know we raised about $1 billion net proceeds in the equity offering and started the year with a very healthy cash position, about $1.3 billion. I don't think we've got final balance sheet numbers to share with you today, but suffice it to say we've got substantial cash balances and don't, at this point in time, have any precise number as to what borrowing might be required. As you might remember we talked about putting an accounts receivable sales facility in place to make up any shortfall that was needed.

All right. And secondly the outlook for refinery maintenance for the remainder of the year, what might you be looking at?

Well, it's been our practice not to talk about major turnarounds throughout the year but suffice it to say we have the majority of our work complete here in the first quarter.

And at this point in time can you give me an indication of how much of your gasoline has 10% ethanol content?

I can't, I don't have that number off the top of my head as to how much we blend. We do not manufacture MTBE any more.

Right.

So, Gary?

I guess the best way to answer it is we blend about 25,000 barrels per day of ethanol, or we use that amount, so you can factor that--it's not all at a 10% blend, I guess, it gets kind of difficult to know what the percentages are--so about 25,000 of ethanols we blend in our gasolines.

Would you say that on average the gallons is carrying 10% ethanol?

It varies.

No.

Probably more of the markets are at 7.7%.

7.7%?

Yes.

In the markets required.

Right.

Okay.

And we sell where it we can economically sell it to. It's not only where it's required, like Chicago for RMG, but in other markets where we can economically supply it, we use ethanol.

All right. Thank you.

We go next to Arjun Murti of Goldman Sachs.

Thank you. Just a question on the Powder River just given recent acquisition prices in the Rockies. Curious how strategic you still view your Powder River assets? It seems since the time of the acquisition you all of had successes and made investments elsewhere. Curious if now might be a good time to realize some proceeds there?

You know, the Powder River is no different than any other asset we own and we constantly look at what the holding value is for us in that asset versus what the market will deliver and we continue to evaluate those options. Obviously, you're right our world has changed a great deal from the time we made that acquisition and it's changing even more with Libya coming back into the fold at some point. So, we certainly continue to look at all the businesses in our portfolio for how we capture, the most value. Powder River is no different.

Terrific, and then Clarence, at the time of the Ashland minority interest acquisition you highlighted some general comments about how you are thinking about E&P acquisitions. Just curious, since that time you have successfully completed the equity offering and I was wondering if had you any updated thoughts in terms of how you see the acquisition market today, the types of assets you're interested in and maybe the general, I guess, timing or desire to do things?

I guess, Arjun, that was probably one of the poorest communications I did at the time we announced the Ashland acquisition was I somewhat how gave the impression that we were going to have to do some kind of an acquisition to rebalance back to a greater weight on the upstream and that really isn't the case. And frankly, I think when we look at our portfolio as you've indicated we do have a lot of good opportunities coming along. I think that's one of the things that puts us in a unique position is that we have a lot of good opportunities on the plate; and frankly those opportunities we think are going to rebalance us in a natural organic basis back to a heavier weighting to upstream post the acquisition. So as I've said to people, Arjun, we're not sticking our head in the sand, we continue to understand what opportunities are out there and what the value is but we don't need to make, an acquisition and we believe we've got sufficient organic opportunities to rebalance.

That's very helpful, thank you.

We go next to Fred Lueffer with Bear Stearns.

Hi, guys. Just two questions. What was Powder River Basin production in the quarter and what are you looking for for the rest of the year?

This is Steve Hinchman. Let me just take a minute and make sure I have the right numbers. The Powder River in the first quarter averaged around 72 million a day, and we expect for the year that we'll average about 78 million a day.

And does that ramp up evenly, Steve, or,.

Well, typically in the Powder you get a little later start in the year because it's waste deep mud up there in the break up, so we're really just cranking up our drilling program at this point in time. So, it's a little light in the first half and a little heavier ramp up in the second half of the year.

What kind of exit rate are you figuring?

Exit rate would be around 90 million a day.

All right.

We've refocused some of our efforts over into the Sheraton area. We are just starting to put on some pods on over there, and it's coming on gas from the beginning, no dewatering time We currently have about 1.5 million per day production out of Sheraton coming from six wells. So we're encouraged in, at least an early indication, of some of our development program focus in 2004.

All right. And just secondly, Clarence, can you give us some feel for an expenditure level or maybe a ballpark number for capital commitment to Libya?

Fred, it would be premature to do that. I think you appreciate this is a four-way negotiation between the three voices partners and the national oil company. So I'd say be patient, you'll hear that number hopefully sooner rather than later.

All right. Thank you.

We go next to Mark Gilman with The Benchmark Company.

Hi, guys, good afternoon. A couple of things. If I'm not mistaken, it appears that you're now talking about a somewhat higher gross liquids level of production from phase 2A in EG Could you confirm that that is the case and, if so, whether that is based on just increased rate or whether there is reserve expansion involved?

Yeah, Mark, this is Steve Hinchman. We are seeing some higher condensate yields. Basically our current production today is averaging about 80 barrels per million. I think when--as we were looking at this project our expectations were around 70 barrels per million. And we are certainly seeing some--what we see are richer condesates deeper in the reservoir some compositional gradation with depth, we have designed our wells and completions to take better advantage of that. Right now we are optimizing the condensate by producing the higher yield wells. We would expect that as we ramp up to full production that yield will level off probably around 75 barrel per million. So the increase in condensate production that we are seeing is primarily driven by higher yields. And we are continuing to evaluate the reserve implications of that.

Okay. Clarence, I wonder if I could follow up and ask about the framework agreement that you talked briefly about and whether you can talk about whether a gas transfer price was established as part of that and if so what it is? And also whether or not it entailed any change in your working interest in the LNG project which, if I recall correctly, was either 70 or 75%?

Yeah. I would just for everyone else on the call, Mark, I would point out that I guess you are talking about the EG LNG project and I would say that all of the essential commercial elements were agreed to and handled in the agreements that I talked to before-- the documents I talked to before, including the gas sales transfer price. Again, I don't want to give that number at this point until everything is signed, sealed and delivered; but that is all agreed to as per our interest, our interest in the project remains at 75% with GPetrol, the national oil company at 25%.

Okay, just one more if I could. If my memory serves me correctly and certainly at my age I might be wrong, I thought you had drilled the Kansas prospect, Phil, a number of years ago, or at least had identified it a number of years ago. Could you fill in the gaps on that one?

Yeah, Mark, we did drill an early well on the Kansas roughly about a year and a half ago. That well did not encounter what we have planned to encounter, but like many of the wells in the Atwater Foal Belt it's taken several wells to actually fully appreciate the volumes of hydro carbons that are or could be present. In the similar vein, we see a very significant opportunity in Kansas and based on what we learned on the first well we are going further down dip in a more favorable area and we are going to test the similar section.

Did you remap it, Phil?

We remapped it. We have new seismic data over the prospect. We gained a lot of information from the well itself including the VSP and all of that has helped us put together a better understanding of the sub-surface.

Thanks.

We go next to Steve Pfeifer with Merrill Lynch.

Hi, guys. I just had one quick follow-up on the hedging and refining. You said that the mark-to-market as of March 31 was $30 million and you took that in the first quarter. What would it be, how much of an additional charge I suppose would you take in the second quarter, assuming that margins stayed where they were? Thanks.

If margins stayed where they were, right now it would be very small, if anything.

That was the effect of the prices as of March 31 of all the hedges, cracks spread hedges which we've sold forward.

Perfect, so point is that it's not much of a change from where we are now. Thanks.

[Caller Instructions]. We go next to Steve Inger.

Hi. One follow up on the Powder River Basin. Steve, that 72 million a day level that's the lowest production you've had in a number of quarters. Can you just kind of step back and catch us up on the status of permits? Are you going to hit your 500 plus wells this year? Others in the play have taken some reserve write-downs, how are you assessing the performance of the Wyadack versus Big George? Thanks.

We are at a little lower level on production. As I said before some of the declines in the mature areas have outpaced some of the development, and we had a little harsher winter up there than we've had in the past. We've had a little more weather-related downtime. We were a little over 80 million in November, December and so we are probably seeing anywhere from five to 10 million just in weather-related. And the remainder of that is a decline in the mature areas. We're in good shape. We're talking about drilling about 400 wells. A lot of our acreage especially in the Sheridan area is fee acreage so we're not on federal permits.

But at this point in time we have 85% of our wells already permitted. I don't see permitting issues really getting in the way of executing on our drilling program. When we came into this, most of the people are having similar reserve issues on drainage in the mature areas around Gillette and we really have taken what I think is probably an over development in the Gillette area into consideration though when we acquired it, so I don't believe we have any of the same reserve exposures, at least relative to what I've seen, as write-offs in the Powder River.

Okay, so the Wyadack, some of the older areas are performing as well as expected and you expect to get the ultimate recoveries that you originally projected?

Yeah, on the reserves. We do not have any exposures.

Thanks.

We take a follow-up question from Mark Gilman.

Guys, I was wondering if you could help me understand what kind of margins you might earn on the LNG you'll be bringing into Elba Island?

I'm trying to remember. We've given overall project economics for the, I'm sorry, on Elba Island. Elba Island. I don't know that we've every given that.

To my recollection you haven't, that's why I'm asking?

I don't recall that either.

Your memory is better than you thought, Mark.

Again I don't think we've given that. I'm not sure we ought to disclose it on this call this way.

Okay. Thanks a lot.

There are no further questions at this time. I would like to turn the call back over to senior management for any additional closing comments.

Okay. We don't have any more closing comments. We just thank everybody for the questions and we will talk to you again next quarter. Thank you.

That concludes today's conference call. Thank you for your participation. You may now disconnect.