馬拉松石油 (MRO) 2005 Q4 法說會逐字稿

Good day everyone and welcome to this Marathon Oil Corporation fourth quarter and year-end 2005 earnings conference call. Today's call is being recorded. For opening remarks and introductions I would like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you very much. I too would like to welcome you all to this call. Let me begin by reminding you that if you're listening via telephone, you can find the synchronized slides that accompany this call on our website, www.marathon.com.

With me on the call today are Clarence Cazalot, our President and CEO, Janet Clark, Senior Vice President and Chief Financial Officer, Phil Behrman, Senior Vice President at Worldwide Exploration, Steve Hinchman, Senior Vice President, Worldwide Production, Gary Heminger, Executive Vice President and President of our Refinery Marketing Transportation organization, and Garry Peiffer, senior Vice President of Finance and Commercial Services for our Downstream organization.

Slide two contains the forward-looking statements and other information related to this presentation. Our remarks and answers to questions 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, 2004, and in subsequent form 10-Q and 8-K filings 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.

As shown on slide three, net income for the fourth quarter was $1.265 billion and included two special items totaling a negative $64 million after tax, resulting in net income adjusted for special items of $1.329 billion. The two after tax special items were a negative $45 million mark-to-market loss on our two long-term U.K. gas contracts, and a $19 million charge as a result of the December 31 adoption of FASB interpretation number 47.

While we had a very good quarter operationally and financially we had an equally good year. If you'll turn to slide four, annual net income adjusted for special items has grown every year since the USX separation. 2005 is far beyond any previous year at $3.238 billion in net income adjusted for special items, or $9.02 for fully diluted share.

If you will turn to slide five, 137% increase in net income adjusted for special items year-over-year was driven by four major components. Positive price and volume variance in the E&P segment, six months of owning 100% of our RM&T operation, and overall improvement in the RM&T business. These positive factors were slightly offset by higher expenses, largely a result of higher volumes and higher prices and higher energy costs.

Moving back to the quarterly data on slide six, net income adjusted for special items for the fourth quarter was $1.329 billion, $532 million higher than the third quarter of 2005 and 220% greater than the fourth quarter of 2004. The improvement over the third quarter was primarily the result of higher production sales volumes and commodity prices in the E&P segment and improved earnings in the refining marketing and transportation segment, with strong refining and marketing margins, along with record total refinery throughputs, record gasoline and distillate production, and record refined product sales volumes.

Moving on to slide number seven, the quarterly improvement year-over-year was again largely a result of higher production sales volumes and commodity prices in the E&P segment, improved earnings in the RM&T segment, plus a significant contribution from the acquisition of the minority interest in our Downstream business. A reconciliation of net income adjusted for special items to net income is included on slide three, and if you refer to slide two there is a discussion of the use of this non-GAAP measure.

Moving on to slide number eight, fourth quarter per share net income adjusted for special items on a fully diluted basis was $3.61, a 67% improvement over the third quarter. There were approximately 369 million weighted average shares outstanding on a diluted basis for the quarter.

Upstream segment income of $1.03 billion for the quarter is shown on slide number nine, was up $403 million quarter-over-quarter. Our worldwide average sales price was up approximately $4 on a barrel of oil equivalent basis, while sales volumes averaged approximately 100,000 barrel of oil equivalent per day more than the third quarter, as we recovered from the hurricanes and substantially balanced our underlift position at September 30.

Moving to slide number 10, domestic Upstream income of $468 million was $71 million higher than the third quarter, domestic liquid realizations fell $3.60 per barrel, while natural gas realizations were up $1.74 per MCF. Sales volumes were higher with the resumption of essentially all of our Gulf of Mexico production and higher seasonal gas sales in Alaska.

As shown on slide number 11, higher natural gas prices more than offset lower liquid realizations, providing a net price realization improvement of $70 million, while higher production sales volumes added another $57 million to domestic Upstream income. Expiration expense was $40 million higher compared to the third quarter, primarily result of the write-off of the Aquarius well in the Gulf of Mexico. All other factors combined reduced income approximately $16 million.

Total expenses in the domestic Upstream segment as shown on slide 12 were up $2.94 per barrel of oil equivalent compared to the third quarter, largely a result of the higher expiration expense. Excluding expiration expense, which can vary based on the timing of unsuccessful drilling activities, expenses were up $0.56 per barrel of oil equivalent, from $16.96 to $17.52 per barrel of oil equivalent.

Moving to slide number 13, domestic Upstream income per barrel of oil equivalent increased almost 9% over the third quarter, reflecting the 8% increase in average domestic hydrocarbon realizations.

We move on to international operations as shown on slide number 14. International income of $562 million was more than double that of the third quarter, mainly due to the balancing of the significant third quarter underlift position and higher seasonal natural gas sales in Europe and Ireland.

Slide number 15 shows on you these higher volumes resulted in a variance of more than $300 million, while price realizations resulted in a price variance of nearly $100 million. Expiration expense was $17 million lower than the third quarter. Total DD&A and controllable expenses increased $48 and $41 million, respectively, primarily a result of the higher sales volumes.

If you now move to slide number 16, total international Upstream sales volumes increased over 68% compared to the third quarter. International Upstream expenses decreased almost $4 per barrel of oil equivalent compared to the third quarter, and excluding expiration expenses the decrease was $1.51 per barrel of oil equivalent, primarily due to fixed costs spread over the higher volumes.

Slide number 17 shows international Upstream income per barrel of oil equivalent increased almost 45% compared to the third quarter, due to sales volume increases and the significant change in production sales mix quarter-over- quarter.

Moving on now to the Downstream business on slide number 18, fourth quarter segment income of $1.166 billion was almost triple the $389 million fourth quarter 2004 segment income. Because of the seasonality in the Downstream business I will compare the fourth quarter 2005 results against the same quarter in 2004. The largest single factor contributing to the Downstream improvement was the significant improvement in crack spreads. The WTI 6321 crack spread, which represents the margin between six barrels of WTI refiner produced three barrels of gasoline, two barrels of low sulfur fuel oil and one barrel of 3% number six fuel oil improved substantially, increasing to $7.95 per barrel for the fourth quarter from about $0.67 per barrel during the same quarter of 2004.

Our cost of sales was lower this quarter than a change in WTI quarter-over- quarter would suggest, primarily because of sweet sour differential improved to $12.17 per barrel, compared to $11.15 a barrel during the same quarter of 2004. In addition, our other feed stock costs were also lower relative to same quarter of 2004 versus the change in the price of WTI quarter-over-quarter.

Even though the Detroit refinery had an extensive planned turnaround for a portion of the fourth quarter, tie in all the expanded and new units that increase capacity of this facility from 74,000 to 100,000 barrels per day, and to comply with Tier II regulations, we increased our total refinery throughputs by 5.8 million barrels or by 5.4% compared to the fourth quarter of 2004. During the fourth quarter of 2005 the futures market was in contango $0.46 per barrel on average, versus $0.37 per barrel backwardation in the same quarter 2004. This improved our crude oil acquisition costs relative to the WTI price that's used in the indicator 6321 crack spread compared to the same quarter of 2004.

Our retail operations also achieved higher margins and sales compared to the fourth quarter of 2004. These positive factors were partially offset by higher costs incurred primarily for energy, maintenance, and depreciation when compared to the same quarter of 2004. In addition, WTI averaged $60.05 per barrel, compared to $48.27 per barrel for the fourth quarter of 2004. While gasoline and distillate wholesale price realizations moved up with a change in the spot price of gasoline and distillate quarter-to-quarter, our bottom of the barrel products such as asphalt did not increase as much as the price of 3% number six fuel oil used in the 6321 indicator margin quarter-over-quarter.

Finally, we recorded a positive crude in transit effect of about $27 million during the fourth quarter 2005, compared to a positive $55 million reflected in fourth quarter of 2004, producing a negative quarterly variance of $28 million.

If you move onto slide number 19, Speedway SuperAmerica’s gasoline and distillate sales were up 41 million gallons quarter-over-quarter or about 5%. Same store gasoline sales volumes were up about 4.5%, even though Speedway SuperAmerica's retail gasoline prices averaged $2.23 per gallon in the quarter just completed, compared to $1.82 per gallon in the 2004 quarter. Speedway SuperAmerica's merchandise sales on a same store basis increased about 11.5% compared to the fourth quarter of 2004. This marked the 12th consecutive quarter that Speedway SuperAmerica's merchandise sales have increased over 9% on a same-store basis when compared to the same quarter from the previous year. Speedway SuperAmerica's gross margin for gasoline and distillate was $0.14 per gallon as compared to $0122 per gallon in the 2004 quarter.

All seven refineries ran very well during the fourth quarter, in spite of a major planned turnaround in Detroit as previous mentioned, we processed more crude oil through the refineries this quarter than we did in the same quarter of 2004, and we set a new record for total refinery throughput, averaging 1,238,700 barrels per day, which is a 4% increase over our previous quarterly record, and our refined product sales volumes of more than 1.5 million barrels per day was also a record. We all set new records for gasoline and distillate production on both a quarterly and an annual basis.

We move to slide number 20. The Integrated Gas segment income was $19 million during the fourth quarter 2005, compared to a loss of $6 million in the third quarter of 2005. Any increase was primarily the result of mark-to-market changes in the fair value of derivatives used to support gas marketing activities.

In the unallocated category, administrative expenses were $83 million in the fourth quarter. A decrease in the third quarter total of $108 million was primarily due to a decrease in the non-cash charge related to equity based compensation.

Net interest and other financing costs were $46 million in the fourth quarter, and that was $14 million higher than the third quarter. As you can see the effective tax rate was 36%. Cash adjusted debt went down by $1.9 billion during the fourth quarter to 1.4 billion, and the cash adjusted debt to capital ratio at December 31, 2005 was approximately 11%. I will note that this cash adjusted debt balance continues to include approximately $543 million of debt serviced by United States Steel, and I would like to remind you these are preliminary numbers.

Fourth quarter preliminary cash flow from operations was approximately $2.8 billion. Preliminary cash flow from operations before working capital changes was approximately $1.7 billion, and for the year, preliminary cash flow from operations was approximately $4.7 billion and approximately $5 billion before working capital changes.

If you move on to look at slide number 21, we provide information from prior periods as well as estimates for the first quarter and year 2006. I want to point out that the tax rate in the table excludes Libya, and that the tax rate with Libya is projected to be significantly higher, likely in the range of 46 to 48%.

Before moving on let me remind you of news you can expect from us in the near future. Early next we week we plan to release our approved 2006 capital expiration budget, and within the next two weeks anticipate releasing our net proved reserve additions for 2005.

I would now like the turn the call over to Clarence Cazalot who will review the year just concluded and comment on our forward plans.

Thank you, Ken, and good afternoon, everyone. 2005 was a milestone year in many ways for Marathon. Slides 23 and 24 highlight a number of our accomplishments during the past year and I really don't intend to go over each one. But I do want to point out that 2005 was Marathon's safest year ever. We turned in a solid environmental performance both exceeding our own 2005 goals.

Also during 2005 we significantly expanded our presence in the Downstream business through the largest single transaction in Marathon's history. We reentered Libya and advanced all of our Upstream projects, and now expect first delivery of LNG from Train 1 and Equatorial Guinea in the first quarter -- in the third quarter, I am sorry -- of 2007. And as you know, at a time when many LNG projects are being delayed, it is quite significant to be able to bring in a project ahead of schedule. Even with combined capital and acquisition spending of nearly $7 billion, we were able to increase our dividend 18% and reduce our cash adjusted debt to capital ratio to 11%. Additionally, our Downstream organization set many records during the year for a timely throughput, production in sales, and all the while bringing on a very significant expansion project at the Detroit refinery.

Let's talk about the future. I think Marathon is very well positioned today. We have executed on the strategies and the plans that we've communicated to you before. If you'll turn to slide 25, you see that we will continue to seek to be a preferred employer and partner in both safety and environmental stewardship. And beyond funding our capital program, maintaining a strong balance sheet and growing our dividend, we'll continue to look for ways to best return excess cash to our shareholders. From an E&P standpoint, one of the most challenging issues that continues to face our industry is access to resource. We'll continue to look for unique opportunities, perhaps using our integrated structure, to access profitable resource and to move that resource to proved reserves and add value accretive production. We'll continue to focus on delivering major projects on time and on budget, and we'll also continue to look at our base business to make certain we're implementing best practices to get the most value out of our assets.

We are pleased to have rejoined our partners in Libya, and we will work with them to fully develop the potential of the Waha concessions where we see production this year between 40 and 45,000 barrels per day on a net basis. With the projects and the developments that we have in hand and under construction today, we see our production growing to between 475,000 and 525,000 barrel of oil equivalent per day by 2008, excluding any acquisitions or divestitures. A very solid growth program.

We'll continue our much improved exploration program with a solid lineup of wells on both blocks 31 and 32 in Angola, as well as in Norway, the U.K. and the Gulf of Mexico. We'll also continue to look for opportunities in other basins that would fit our program and provide value growth.

Moving to the final slide in the Integrated Gas business, as I said before, we now expect first LNG in the third quarter of 2007. We're also progressing discussions on a second train and will continue to look for opportunities to apply our GTL technology.

In the Downstream business we expect to maintain a high level of efficiency and reliability and to increase refinery capacities through debottlenecking where possible. In the retail side of the business, we'll continue to seek opportunities to grow light product and merchandise sales. We expect to have our feed complete on the possible Garyville expansion later this year, with a final investment decision to be made by year-end. We continue to look for opportunities to leverage our strong Midwest refining and marketing position with the addition of coke and capacity.

With a very solid 2005 behind us, and defined value growth in all segments of our business through 2008, we have been focusing our attention on opportunities beyond this time frame while remaining vigilant in executing on the number of major projects already in our growth portfolio. With that, Ken, I will turn it back to you.

Thank you very much, Clarence. We'll now open the call to questions. I would like to remind everybody to please identify yourself and your firm affiliation for the benefit of those listening in. Please limit yourself to one question and one follow up so all callers may be accommodated.

[OPERATOR INSTRUCTIONS] Our first question comes from Robert Kessler with Simmons and Company.

Good afternoon. Had a couple of questions or points of clarification on your production guidance. One would be -- it looks as though the range is quite a bit higher than you used to use and I am curious if you could give us some sensitivities around -- let's say you come in at the low end of range, what would be the primary drivers and what would cause you to head towards the upper end of the range, particularly for this year? And then the second question would be how much are you assuming for Libya in the '08 target understanding in the near term you have got 40 to 45,000 barrels a day assumed. But by 2008, are you expecting any significant growth in term of your forecast today?

Steve, why don't you take that one.

I would be happy to. Robert, probably one of the primary drivers on the low end is really the uncertainty in Gulf of Mexico weather. Obviously, in 2005, we experienced over 45 days of weather-related downtime in the Gulf of Mexico. So in terms of a single event that's probably the biggest thing on the downside. In order to achieve the upside, obviously having a better performance in the Gulf of Mexico than weather-related performance but also strong seasonal gas sales, which are more temperature dependent, both out of Alaska and U.K. and Ireland. Regarding Libya, really at this time we're just trying to simulate ourselves into the Libya operations, and we really are utilizing information that has been provided for us from the national oil company and Waha as the operating company. So we're comfortable with the 40 to 45,000 barrel a day range that we're giving for 2006. But it would be premature for us to make a forecast into 2008 until we've had more time to really look over the information and gain greater confidence.

Fair enough. Thank you.

Our next question comes from Doug Leggate with Citigroup.

Thank you. Good afternoon, everybody. I also have a couple of questions. I guess the first one is on cost guidance for 2006. Ken, I wonder if you can give us some idea of the expectations, both US and international. And if you could clarify whether or not you're including Libya in those numbers.

Steve, do you have that with you, I believe?

Yes, Ken. Hey, Doug, how are you doing? For international we would expect that our field level controllable costs would range between $3.35 and $3.55, DD&A between $6.50 and $7.00, and all other costs excluding those things that are price sensitive, production taxes and foreign royalty, we would estimate that that would be $4.15 to $4.45. You will note in 2005, that production taxes and foreign royalties accounted for about $2.80 per BOE. On the domestic side, field level controllable we expect to be $3.95 to $4.15, DD&A, $7 to $7.50, and the – again, the other cash cost excluding production taxes and ad valorem would be $4.05 to $4.35. Again in 2005, production and ad valorem taxes averaged around $2.27.

Thanks, Steve. Just to be clear, the international numbers, does that include Libya or exclude Libya?

That would include Libya, and of course as you look at 2005 those would represent a bit of a –- a reduction, primarily the Libya barrels are a bit lower cost barrel.

Thank you. And my follow up, Ken, was -- I wonder if we can get an update on possible feed on Train 2, LNG and Equatorial Guinea? And any possible identified sources of gas that can meet that project?

Doug, we have not yet approved with our partners moving forward with that feed. We will be meeting very shortly with them with another EG LNG board meeting to discuss just that matter. Obviously we continued to advance our discussions with other gas suppliers in EG, in Cameroon and Nigeria. Those things are coming together, but it would be premature to get into specifics. But as I say, that is a key element for us in 2006.

Thanks very much.

We'll move to Nikki Decker with Bear Stearns.

Good afternoon, everybody. To follow on EG, any progress on the Alba satellites, Gardenia and the Deep Luba?

This is Steve Hinchman. We're studying those fields and seeing how we can best integrate those. We hoped to come to a plan of development and a decision on the commerciality of those fields likely in the first quarter of 2006.

Okay. That's great. And just as a follow up, North Sea, I think you mentioned a couple of prospects last quarter. Can you update us on how those are going?

Sure. Nikki, this is Phil Behrman. The [Daven] well is still drilling at the present time, and the Dragon well was (indiscernible) as a dry hole, both in the North Sea.

Thank you so much.

Our next question comes from Paul Sankey with Deutsche Bank.

Good afternoon, gentlemen. I have two areas of questioning. Firstly on the Upstream, you mentioned a jump up in the international profitability per barrel and said it was a result of the sales mix. I wonder if you can expand on that a little bit. And related to that, you also mentioned that Upstream DD&A and controllable expenses jumped as a result of higher sales, and I wondered if you could expand on that a little bit more.

Steve, do you want to talk about that first?

That would be fine. You know, the U.K. and really our international liftings were significantly higher in the fourth quarter compared to the first quarter, and the Bray and the EG barrels are both fairly high margin barrels relative to our overall mix. With that overlift and the mix changing to a higher margin overall mix, that's why we saw the increased earnings per barrel.

Great. Thanks. On the controllable expenses in the DD&A.

The controllable expenses and DD&A for international production -- relative to the third quarter, when we don't lift, then we have still some fixed costs. And those lower volumes we have really translates to higher expense. When we do produce those volumes as we overlifted in the fourth quarter, we get the reverse effect of that and we have really kind of a lower cost. And so there is no real fundamental change in the rate in those costs. It is really driven by the larger volume that leaves in dollars the higher DD&A.

Great. Thank you. I understand. If I could ask a follow up on the Downstream, you showed exceptionally strong sales in Downstream. I wondered if that was a result of simply the strong market conditions or whether you were taking market share there, if you can comment on that. And secondly, on the capacity utilization once again, which was exceptionally strong, above 100%, is that a sustainable level to think about into ’06? Thanks.

Okay. Paul, first of all, on the margins in the fourth quarter, we had very good inventory within the majority of our markets just after the hurricanes, so the increased sales were the result of having good inventories as well as having the first two refineries to return to service, we were able to run all of our refineries at the full mark, as well as having a lot of inventory in the pipelines, we were able to take advantage of that. So to say whether or not that type of sale is sustainable, it was really a reflection of the market and the demand in the market not only moving from pad three into pad two, but in some cases reversing from pad two and moving it down into really southeast pad three type markets. As we go forward looking at the throughputs and the utilization we had, I would expect that our throughputs this year on a crude basis would be very near where they were last year. So I would think they could be sustainable, barring any unforeseen circumstances, weather, other things we've come to understand.

We'll take our next question from Doug Terreson with Morgan Stanley.

Congratulations on another great result. On page 21 of the handout, you guys provide projections for corporate and interest expense in 2006 that are about half of that of 2005, and while the decline in interest costs are self-explanatory, I wanted to see if you would provide insight into the factors that are expected to drive the big decline in administrative expenses in '06. And also, whether the tax rate that Ken mention in his comments with Libya of about 46% was the expected corporate-wide average tax rate.

Doug, that's a lot of questions. On the G&A, for 2006 the guidance versus 2005, we don't include any estimate of impact from stock price improvement, and this year we had a very substantial run up in the stock price. So that accounts for the biggest part of it.

Okay.

Interest expense, that's based on the cash building over throughout the year, and in addition to the fact that we've got a -- I think it is a 6 to 6.5% bond coming due in February, which will be paid February first. That's up 300 million or so.

And Janet, the tax rate, corporate wide tax rate was 46%, the number.

That includes Libya.

And my follow up is probably for more Clarence, but maybe for you, Janet. If consensus estimates are in the ballpark for '06 and '07 you should have a meaningful amount of free cash flow. I wanted to see if you guys would provide an update as to the priority of those funds if they materialize this year and next.

I will start, Doug. If Clarence wants to jump in, he can. Our -- we're very committed to total shareholder return, and to the extent that we've got the projects and the manpower to invest in value accretive capital programs, that's the first priority. Last year we increased the dividend 18%, but as Clarence noted we ended the year at 11% net debt to cap. Financial flexibility is important to us, a strong balance sheet is important, but again we recognize that returning cash to shareholders is an important part of total shareholder return.

We'll move to Steve Enger with Petrie Parkman.

Good morning. Good afternoon there. Question on the 2006 production guidance. It is down -- I think something like 30 MBOE per day relative to what you guys presented at your analyst meeting last February. Can you talk through what you think are the major impacts from then to now?

Steve, I am a little bit concerned because really the guidance that we've given -- if you take out the 40 to 45,000 associated with Libya, is 325 to 350, the exact guidance we’d given during our analysts. We were actually basically on track with the prior guidance.

Okay. I will check back on that. And then for Gary, following up on an earlier question, I guess just to flush that out a little more, the ratio of product sales to crude throughputs was high, and you talked about some of the inventory effects and being well positioned in those markets after the hurricanes. Do you have a sense for what your ratio of product sales to crude throughputs may be in '06? Do you think you really have pushed up to a higher level, or was fourth quarter unusual in that regard?

I would say in the fourth quarter there was about 258,000 barrels a day of additional inputs, above and beyond crude, and if you look back in our history we have averaged kind of 200 to 225 depending on the year so I would say it should still be in that ballpark.

We'll move to Jennifer Rowland with JP Morgan.

First question on the reserves -- potential reserve (indiscernible). In the press release you mentioned anticipating booking 165 million barrels from Libya. I am just wondering if that's means you anticipate doing that in '05 or would that be an '06 event?

Jennifer, this is Clarence. That's an issue still being analyzed by the various legal and accounting experts, so as soon as we resolve that I think, as Ken indicated, it is our intent within the next two week to put out a very complete reserve picture for 2005, whether it includes Libya or does not. So stay tuned; the next two weeks you will get the full story.

Just to follow up on the Downstream, you mentioned the crude oil and transit impact on the R&N results. Wondering if there was any LIFO impacts or hedging impacts in the number during the quarter.

This is Gary Peiffer. I guess -- we do all of our accounting on LIFO. I’m not -- we don’t break out anything specifically regarding LIFO. I don't have any estimate to give you. In terms of derivatives, in terms of fact the crude prices dropped from about $66 at the beginning of the month to $61 -– beginning of the quarter, excuse me -- $61 at the end of the quarter. Prices did drop, so we are generally short in our derivative activities so we would have a positive benefit there. But the biggest benefit, as Ken talked about earlier in the quarter, was just the overall improvement in the 6321 crack spread that allowed to us generate a lot more refining margins on the record volumes of throughputs which we had in our refineries.

Great. Thank you.

Our next question is from Paul Cheng with Lehman Brothers.

Hey, guys, good afternoon. Two questions. One, I think this is probably for Steve. Steve, looking at Russia, the current production is about 31,000 barrel per day. I think it is a little higher than what you guys have anticipating for at this time in the life. If there are any change to your production level for Russia going forward, and also that are you guys looking at perhaps there was some (indiscernible) going to increase your exposure in Russia –plus more M&A activities there. The second question is probably for -- maybe -- I don't know, Steve, or for Karen. In Angola, wondering if you can give us an update where (indiscernible) project on Block 31, when are we going to move to the decision process and perhaps maybe an update on the Block 32 also.

Steven and Phil, you two can handle those.

I will address the Russia production. I might pass that additional exposure to Clarence. To the production volume, we're slightly ahead of where we thought we would be on the Russian volumes. We've actually had pretty great success with our East Cam and North [Nikolov] development project. Both in terms of the our drilling performance and as well as we've initiated some water injections, water flood there, so we're already seeing some early responses there. We saw probably 10 to 12,000 barrel a day increase in Russia from '04 to '05, and our drilling activity in Russia will likely provide somewhere around 10,000 barrels a day increase in production in Russia going into 2006. We're going to go ahead and expand our water flood operations as well, so we're going to take about 4,000 barrels a day of existing producing wells and convert them into water injection. The net increase you can expect in Russia next year will be a little less, but it is because we're going to go through the conversions and expand the water flood.

Paul, this is Phil Behrman. On Angola, the update is pretty similar to what we have told you in the past. Block 31 Northeast area, we continue to move forward on engineering studies. We should be progressing to feed early in 2006. Feed will last approximately a year, so we have an FID decision to be made in the early part of 2007 for the Northeast area. Block 31.

The rest of block 31 might have a full rig that’ll be drilling through all of 2006 in Angola Block 31. Focused on moving and finding additional resource in the rest of the block. We're looking towards commercializing the southeast part and moving the southeast part of Block 31 forward next. In Block 32 we're just beginning those engineering studies, and they'll begin with feasibility studies, and that's what we'll be doing in 2006 for Block 32. In addition, we'll have a significant amount of recapacity also drilling in Block 32, focusing on adding new resource there away from what we call the east central area where we're doing our current feasibility studies. And those feasibility studies ought to last in the range of a year, maybe a little more, a little less. And then it’ll move forward to feed also.

Thank you, Phil. Shari, do we have another caller.

Mark Flannery from Credit Suisse.

Hi. I have a question about the upcoming projects, specifically Alvheim and Neptune. Regarding how protected they are from current increases in drilling costs and service costs. I understand that some of the West African stuff was on more of a turnkey basis, but how are you set in terms of contracted rigs, services, that kind of stuff for those two important projects?

This is Steve Hinchman. Alvheim ended the year around 43% complete. It is all really lump sum turnkey. The rig has been secured at really substantially below market rate at the time that we did it, and that rig should show up probably in late spring, probably May time frame and commence drilling. That project is on schedule and we have really limited exposure to some of the inflationary pressures within that project.

Neptune, we sanctioned in June of 2005. The project ended the year around 12% complete, and again that project is a lump sum turnkey project as well. The rig has been concerned -- or has been retained, and it should show up probably towards the end of the first quarter, beginning of the second quarter and commence drilling there. So as I mentioned before, a lot of our major project activity is not subject to some of the high inflationary pressures that we're seeing in terms of cost of goods and services, and specifically in terms of rigs. That doesn't mean some of those contractors aren't going to try to do some negotiations as we see these market rates, but both of these projects are pretty much on schedule and within the budget.

Do you have any areas that you are concerned about, or any projects you're concerned about?

No, really in terms of our major project activity, we're pretty well positioned in terms of having the -- all the contract in place, the rigs, yards, the facility works, the steel, so we're in pretty good shape there. I would say that some of our Gulf of Mexico drilling activity and -- is potentially impacted by being able to secure rigs, but in terms of the Alvheim, Neptune, Corrib, and certainly our EG Train 1 construction, we're in very, very good shape. And I think that most of those projects were really contracted ahead of this huge wave of increased costs and real pressure on availability of people and material.

Our next question is from Mark Gillman with Benchmark Company.

Guys, good afternoon. I got two real quick but unrelated items. First, maybe Phil Behrman, you could tell us whether you plan on drilling any subsequent deep shelf prospects in the wake of Aquarius. And then one for Gary. Gary, are you selling any ultra-low sulfur diesel yet, and if so what kind of uplift are you seeing on it in the marketplace.

Mark, Phil Behrman. Yes, as soon as we finish our operational activity on Aquarius the rig will move to what we call the Abbott prospect where we will drill a second deep shelf well. They are –- the two prospects are unrelated but will be drilled back to back.

Okay. Mark, on ultra-low sulfur diesel, we are -- have completed some test runs. We have used that to test some of our pipeline assets, but we are not selling it as ultra-low sulfur diesel yet into the marketplace to be able to determine if there is any uplift.

We'll move to Bruce Lanni with AG Edwards.

Congratulations on the quarter, and I think more importantly the success that you had last year. I have two unrelated questions. I think one goes back to Doug when he asked about the shareholder returns, and Clarence or Janet, maybe you want to answer that. I notice that in the slides you lay out increased dividends, special dividends and stock buybacks. I think what I am intrigued with is the special dividend comment, maybe I have overlooked that in the past from you. It seems to me that this is something that is not commonly considered, so I'm wondering from your perspective when this would possibly come into play and how you would prioritize when it would come into play. That would be the first question.

The second one again related back to production. I think what Steve was trying to get to originally with your guidance for this year versus last year, if you look at the lower end of your range and you take out Libya, I think it implies some type of decline rate you could potentially have for this year. I was wondering if you could share with us what decline rates you're building into your estimates for not only this year, but out to '08 on production.

I think it is –- I think I tried to address that question when Doug asked it, about our priorities, and obviously CapEx value accretive projects comes first -- as our track record the last two years will increase dividends significantly we'll continue to look at that on a quarterly basis with our board, as we will look at other means of returning cash to shareholders.

Janet, it is a comment about special dividends you put in there, and my point being that that's a topic that usually isn't discussed very much, so aside from an annual increase in dividend, are you considering a special one-time dividend? What are you implying by this?

I think you're reading a lot too much into that slide. It is sort of like what are the various ways one can return cash to shareholders? That happens to be a possible mechanism.

On the production question.

This is Steve. On the production, our sort of base decline is around 6%. Then we look for our growth areas to contribute on top of that. The guidance that we've given in the past was that we would see relatively flat production from '04, '05 into '06, and a lot of our major project activity, Alvheim, Vilje, Neptune, Ozona, the EG Train 1, LNG Train 1, and Cora in Ireland. All of those projects are completed and contribute significantly to production in 2007 and 2008. So in 2006, we're seeing a decline that is probably essentially kind of offset by continued growth due to a full year production in EG, and continued net growth really even with the conversions of producing wells to injection wells in Russia. So the message really is we will probably stay relatively flat.

And Bruce, everybody, let me just add -- our guidance at the analyst meeting we said was at '06 would have been about 335, so if you add the 40 to 45 which we're comfortable with for this year on Libya, that puts you at 375 to 380, which is smack dab in the middle of the range that we've given, 365 to 395. Hope that helps.

Arjun Murti with Goldman Sachs has our next question.

Hate to do another follow up to the use of free cash flow and balance sheet, but can you talk about what role if any -- let's call them more meaningful upstream-oriented acquisitions might play in terms of utilizing your balance sheet strength, and maybe does that in any way -- the decision to do or not do an acquisition tie into when you might initiate either a stock buy back or special dividend? Thank you.

This is Clarence. I guess you raise the issue of acquisitions. We obviously continue to look out there and see if anything -- what if anything makes sense for us. But again, I think we said before and we'll continue to say I think we've got a pretty strong organic growth profile across our businesses, and we have a lot of growth opportunities, Upstream, Integrated Gas and refining and marketing. I think as we pursue some of the opportunities we see, particularly in Integrated Oil and Integrated Gas, to Janet's point we're going to have a lot of value accretive projects to invest in. It is a pretty tough environment to make acquisitions, as you say more meaningful acquisitions, there certainly are opportunities or assets out there that would make great sense for us, but perhaps not at the price they're going for today. So we think we’ve got internally organic growth investments to make that will continue to grow the value of the company, and to the extent we have excess cash left over from that, as Janet said, we'll continue to look at ways to best deliver that back to shareholders.

That's very helpful. One related follow up. Is the magnitude of cash returned to shareholders -- should we think of that as a function of free cash flow you generat,e or would you actually be willing to, say, lever up to some degree, given as you point out you do have a project portfolio, et cetera, you're probably less dependent on acquisitions so you can perhaps lever up a bit?

I don't really see us leveraging up. We look at our plans in terms of the things, the forward investment profile, the growth profile. We don't look at it at [strip] prices. We look at it on a much more conservative basis, and we still see ourselves being able to fund that growth and maintain the financial flexibility that perhaps things aren’t going to always be as rosy as they are today. And really it would be from excess cash beyond what we see as being necessary to grow the business and maintain that strong balance sheet, but to see us lever up, I don't see us doing that, no.

We'll take the next question from Neil McMahon with Bernstein.

Hi. Two questions, one for Phil and another one for Gary. For Phil first, maybe, you mentioned earlier on Angola. I was just wondering what is the average size you’re seeing in the exploration successes that you’ve drilled over the last quarter. And then maybe a broader question, where else in the world have you been looking at acquiring acreage, or looking at potentially exploring from a Wildcat point of view, over the last quarter. And then for Gary, over the last -- probably year, there has been on and off discussions or you have alluded to discussions in terms of tying up with an oil sand producer to sink in the refinery in pad two with the oil sands in Canada. Can you give us any guidance as to how those discussions are going on, especially with the recent breakdown of some deals that were done with competitors, and also when it seems that BP and others are starting to think about doing these deals as well?

Neil, this is Phil Behrman. To give you a sense of Angola, as I am sure you appreciate, a partner can't divulge the prospect size or discovery size of individual opportunities, it really does violate our contractual agreements not only with our partners but with the government. Now, that being said, generally the discoveries that have been made, as I think we mentioned to you before, are in the mid-size category throughout all of Angola, mid-size discovery are in the 100 to 200 million barrel range. There’s a couple of very larger ones, but in general most of the them are in that range. The prospects we would have been drilling that were outside of salt bodies would be in that same range. And in addition, we're looking at opportunities that are under salt, which have much bigger potential but of course much higher costs and much higher risk. I hope that gives you a sense without giving you details that we can't divulge, but gives you a sense of the nature of the play in Angola.

When you asked another question, I believe, which was next areas or areas outside of Angola to explore in, we continue to find in the near-term opportunities in the basins which we're currently exploring in, which is the Gulf of Mexico as well as the North Sea, and we will continue to have active programs in both those areas in 2006. In addition to that, as Clarence mentioned, access to resource is key to us and we're beginning to look outward. Not necessarily into rank frontier plays, where there is not a proven hydrocarbon system, but in areas where we can extend the proven hydrocarbon system but look for meaningful and material opportunities. All of which of course have to be value add or significant money makers if we have success for Marathon. It is too early to discuss those with you, but I would tell you that we're seriously looking at those. If we can make those acquisitions in terms of acres, those access opportunities, we'll begin to make those and make those with significant more activity.

Okay. Neil, as we've discussed before, we have studied not only just Detroit and Callisberg, but we’ve looked at all of our pad two plants to see what makes the most sense. We are really way down the line on our feasibility work, on all of our Midwest refineries to understand what is the best concept. We are working hand in hand, our Upstream business development, Downstream business development, folks working hand in hand with all the major players and medium sized players in Canada.

What you have seen happen in the marketplace where one has been announced and fell apart was two things; an investment issue, about twice what was what had been initially announced, and secondly, and probably the most important thing for us right now is to understand the transportation segment of the business. How do you get that very viscous crude in material amounts into your refineries that hereto for run a medium sour all the way down to a sweet type of crude oil? Transportation is the key, I think the lynchpin to being able to really pull things together, but we are working very diligently to try to get that accomplished.

Next question is from [Sanil] Diquani] with Citadel.

Good afternoon. Just a quick question. What's your internal estimate of any potential up lift you might see in margin over '07 and '08 as we start to see some of the more sour SCO come to pad 2?

Well, I guess when you say refining margins as you see SCO, which you're meaning a sweet synthetic?

Right. Actually even some of the other heavier portions that don't get upgraded in Canada, just how have you tried to quantify it internally if you can share that with us in.

I really can't share with you as you can appreciate as we're negotiating and doing our work with other -- I really captain share what our forecast or assumptions are for margins, and when you look at the marketplace today, for sour synthetic and other western black oil, you know, very, very large discounts into the marketplace today, so it is just when you look out into '07, '08, '09 period, it is too early to divulge our assumptions.

You would expect an up lift, is that a fair at the same

Say an up lift of margins I guess I would look at it a different way. It discount if you will on the sweet sour, heavy light type spreads and it is all a function of how much goes into difficult bit and that's the function and use you're going to be able to move it into the marketplace. It is more complex than just the amount of inventory available. It is who has the appetite for it. I think that's the best way to answer that.

Next question goes to Lewis [Ogen] with ING.

Hi, guys. Quick question. What is your cash balance at the end of the last year.

$2.6 billion.

2.6.

Thank you.

We're really at the end of our time period here. We have travel schedules and I would like to remind everybody on the call I would like to thank you for participating and Howard and I are both available for questions or anything that you weren't able to get answered here today so we encourage you to call us if you have anything else and once again thank you very much.

This does conclude today’s conference. We thank you for your participation. You may disconnect at this time.