馬拉松石油 (MRO) 2005 Q2 法說會逐字稿

Good day, everyone. And welcome to this Marathon Oil Corporation second quarter 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, Cynthia. And I, too, would like to welcome everybody to our second quarter 2005 earnings web cast and teleconference for Marathon Oil Corporation. With me on the call today are Clarence Cazalot, he's the President and CEO; Janet Clark Senior Vice President and Chief Financial Officer; Gary Heminger, Executive Vice President, Refining Marketing and Transportation; and Steve Hinchman, Senior Vice President of World Wide Production. Also on with us is Gary Peiffer, Senior Vice President of Finance and Commercial Services for the downstream organization.

We have changed the format of our call and will have a slide synchronized with about 15 minutes of second quarter review. And then Clarence Cazalot will spend a few minutes talking about our results and forward plans. We will then open the call up to questions. At approximately two hours after this call ends these remarks and the slides will be placed on the Investor Relations portion of our Web site, and it will remain on the Web site for one year.

On slide, two you will find our forward-looking statement 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 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 its subsequent forms 10-K and 8-K filings cautionary language identifying important factors, but not necessarily all factors, that could cause outcomes to differ materially from those set forth in the forward-looking statements.

As shown on slide three, net income for the second quarter was $673 million, and included two after tax special items totaling a negative $82 million, resulting in net income adjusted for special items of $755 million. The two after tax special items were a negative $97 million related to the mark-to-market loss on our two long term U.K. gas contracts and a positive $15 million related to a deferred tax adjustment. The tax adjustment is a result of Ohio changing its tax structure from an income base to a commercial activity base, resulting in a reversal of previously booked deferred tax. Our net income adjusted for special items of $755 million was more than double the first quarter of this year and 86% greater than the second quarter of last year. The improvement sequentially, as well as year over year, was largely a result of stronger liquids and natural gas prices, higher upstream production sales, strong refining and marketing margins, and record total refinery throughputs. A reconciliation of net income adjusted for special items to net income is included on slide three. And you can refer to slide two for a discussion of the use of this non-GAAP measure.

Moving to slide number four, net income adjusted for special items was $2.16 per share, again far exceeding any of the previous several quarters. You should note that with the closing of the downstream minority interest acquisition on June 30th, we now have approximately 17.5 million additional shares outstanding. These additional shares and the elimination of Ashland's minority interest did not impact second quarter earnings, but beginning in the third quarter, our share count has increased and we will be including 100% of downstream income in our reported earnings.

As shown on slide number five, second quarter segment income was $1.6 billion, more than double the $772 million in the first quarter. Again this increase is a result of higher upstream and downstream earnings attributable to better prices, margins and production. This slide also illustrates the value of integration as over the past six quarters, our upstream and downstream businesses have been very complimentary, helping to sustain relatively consistent operating earnings when both performed -- pardon me, sustain relatively consistent operating earnings and when both perform well, we have a quarter like the one just completed.

Upstream segment income as shown on slide six was up $221 million quarter over quarter. The increase was primarily due to higher liquid sales volumes, and higher oil and gas realizations, offset by lower gas volumes, due mainly to seasonality, and effects of the restoration costs and insurance recoveries related to Petronius during the first quarter, not repeated in the second quarter and higher DD&A and production taxes, both resulting from higher production and higher prices.

Focusing on domestic upstream operations on slide seven, second quarter segment income of $394 million was $89 million higher than the first quarter 2005, primarily a result of higher liquids and natural gas prices and higher sales volumes, offset by lower other revenues as a result of the restoration and insurance recoveries recorded in the first quarter related to the Petronius damage. The increase in domestic production sold, particularly liquid volumes, was primarily a result of a full quarter of Petronius production.

As shown on slide eight, while production was up almost 9% quarter over quarter, total expenses decreased 8% on a barrel of oil equivalent basis. Stripping out expiration expense which can vary based on the timing of dry holes, expenses per BOE were down 11% from $16.41 to $14.64 per BOE. This reduction is largely a reflection of increased volumes and second quarter damage insurance recoveries related to Petronius.

Moving to slide nine, domestic income for BOE increased 17%, reflecting increased liquids and natural gas realizations, and the lower average cost per barrel of oil equivalent.

Moving to slide number 10, international upstream segment income of $382 million for the second quarter increased $132 million over the first quarter, primarily due to higher liquid sales volumes and prices, partially offset by lower natural gas volumes and prices, and higher production taxes in Russia.

Moving to slide number 11, total international sales volumes increased 11%. Liquid sales volumes increased 46%, primarily as a result of ramping up production in Equatorial Guinea, from the LPG expansion, and balancing our under lift position in the United Kingdom and Gabon at the end of the first quarter. Lower gas sales volumes were a result of seasonal reductions in the North Sea and Ireland. Expenses increased to approximately 5% on a barrel of oil equivalent basis, as a result of Russian production taxes and increased expenses associated with the start-up of our EG LPG plant.

Slide number 12 is our last international slide. And it shows that income per BOE moved up almost 36%, and this was largely a reflection, again, of higher liquids listings and prices.

Moving to our downstream business in slide number 13, second quarter segment income of $823 million was $246 million higher than the second quarter of 2004. Because of the seasonality in the downstream business, I will compare the second quarter 2005 results against the same quarter in 2004. The most significant factor contributing to the downstream improvement was a steep sweet sour crude oil discount experience during the quarter. Average sweet sour differentials widened to $10.72 per barrel in the second quarter of 2005, versus $7.09 per barrel in the second quarter a year ago. Consequently, our crude oil and other feed stock acquisition costs were significantly lower relative to the change in WTI this quarter, compared to the same quarter last year. While we generally utilized over 50 different grades of crude to optimize our refinery utilization, the representative sour crude market we are using, as shown on this slide, is comprised of 15% low river, 15% Maya, 35% Kuwait medium, and 35% Arab medium. Also benefiting the June 2005 quarter, the futures market was in constant tango, $1.28 per barrel on average, versus being $.73 per barrel in backwardation in the same quarter last year. This improved our crude oil acquisition costs relative to the WTI price used in the traditional WTI 3-2-1 crack spread calculation this quarter versus the same quarter last year.

In addition, you will note we processed on average 31,000 more barrels per day of crude oil and other charge stocks in the just completed quarter than in the second quarter last year, or almost 3 million barrels more in total, resulting in our best refinery throughput quarter ever. This is primarily a result of a relatively light planned maintenance activities, and a relatively strong refining margins we experienced in the current quarter. Also during the quarter, we recorded a gain of about $5 million on crack spreads sold, versus a loss of about $40 million in the same quarter last year. Approximately $1 million of the current quarter's positive effect is related to crack spread derivative contracts that expire in the third and fourth quarters of 2005, and the remainder applies to crack spread contracts that expired in the June quarter. These positive factors were partially offset by the fact that WTI averaged $53.08 per barrel during the quarter compared to $38.28 per barrel in the same quarter last year, for an increase of about 40%. We are not able to pass along this higher cost primarily on asphalt and other specialty products. This resulted in lower realizations on our entire product slate than that indicated by the change in spot prices for gasoline and distillate, included in the traditional 3-2-1 calculation quarter-to-quarter. And lastly, the crude oil in transit effect was a negative $19 million in the current quarter, compared to a negative $12 million in the second quarter of 2004.

As shown on slide 14, Speedway SuperAmerica's gasoline and distillate sales were up about 20 million gallons quarter-over-quarter, or about 2.5%. Same store gasoline sales volumes were up about 5%, even though Speedway SuperAmerica's retail gasoline prices averaged $2.06 per gallon in the quarter just completed, compared to $1.83 per gallon in the same quarter last year. Speedway SuperAmerica's merchandise sales on a same store basis increased over 10% last quarter, from the same period last year. Speedway SuperAmerica's gross margin in gasoline and distillates was up slightly at 12.1 cents per gallon as compared to 11.9 cents per gallon in the same period last year. All seven refineries ran very well last quarter. And assuming margins remain strong, we continue to expect that 2005 will exceed the crude oil throughput record set in 2004. Looking at the integrated gas business segment, operating income was $11 million in the second quarter of 2005, versus $7 million in the first quarter of 2005. In the unallocated category, administrative expense was $85 million in the second quarter. A decrease from the first quarter total of $91 million, was due primarily to a decrease in the noncash charge related to equity-based compensation. The charge in the second quarter was $21 million, compared to a charge in the first quarter of $43 million. This was partially offset by lower allocations to the business units.

Net interest and other financing costs were $35 million in the second quarter, 3 million higher than the first quarter, largely a result of higher foreign exchange losses, partially offset by higher capitalized interest and interest income. Marathon's pre-tax income for the second quarter reflecting just Marathon's share of downstream income was just over $1 billion. The tax provision was $336 million, or 33% effective tax rate. This lower than normal tax rate was a result of the significant increase in domestic income subject to the recently enacted Internal Revenue Code section 199 manufacturing deduction, and a change in our mix of foreign and domestic income projected over the rest of the year, along with the previously discussed $15 million deferred tax adjustment. We now expect our tax to be in the 35 to 36% range for the entire year. With the closing of the minority interest acquisition, cash adjusted debt went up by $2.3 billion during the quarter to $3.1 billion. The cash adjusted debt to capital ratio at June 30 is approximately 24%. I need to remind you that this percentage would increase by approximately 4% as we replenish working capital for the accounts receivable distributed to Ashland at closing. I also note that the cash adjusted debt balance continues to include approximately $587 million in debt to service by United States Steel. And I also remind you that these are preliminary numbers. Second quarter preliminary cash flow from operations was approximately $1.2 billion, and cash flow from operations before working capital changes was approximately $1.5 billion.

Finally, on slide 15, we provide information from prior quarters as well as estimates for the third quarter. Total liquids production available for sale in the third quarter is expected to be lower than the second quarter due to higher exposure to weather-related downtime in the Gulf of Mexico, and planned maintenance at Point Haven in the U.K. North Sea. Please remember this estimate is production available for sale and the timing of our international listings can cause the reported sales volumes to vary materially from its estimate. Worldwide gas production is expected to be lower than the second quarter because of lower seasonal gas sales in the United Kingdom and Ireland. While third quarter 2005 production available for sale is projected to be slightly lower than the second quarter, the strong overall performance of both new core areas and the base business have allowed us to adjust our estimated 2005 production available for sale upwards from the previous estimate of 325,000 to 350,000 barrels of oil equivalent per day so an average of between 340,000 and 355,000 barrels of oil equivalent per day, excluding the impact of any acquisitions, dispositions, or of our potential reentry into Libya.

I would now like to introduce Clarence Cazalot, who will provide comments talking about our results and our forward plans. Clarence?

Thank you, Ken. And I think as Ken has outlined, the second quarter was a very strong financial quarter for the Company, but I'm extremely proud of the operational performance that the Marathon and MAP people put forward in that quarter and you know, a good operation belongs with a strong commitment to health, environment and safety and our focus in those areas is paying off. We're seeing much lower, or much improved rates in terms of our safety and environmental performance almost across the board compared to 2004, and indeed better than our 2005 goals, and this is an area where we will continue to remain focused and vigilant. We really had strong production results from our base business and the new core areas, and as Ken indicated our available for sales in the quarter of 353,000 BOE a day exceeded the guidance we had previously given, and of course as a result of that performance and what we see going forward to the rest of the year we have now raised our guidance for the year to the 340 to 355 range. We talked about the completion of our Phase II liquid expansion in EG which is now producing in excess of 80,000 gross barrels of liquids per day. We were blessed by the restoration and return to production of Petronius in the Gulf of Mexico, and we continue to see a very strong performance from the East Kamennoye Vickulov development in Russia where we've seen really a doubling of our production from the time we've acquired that asset.

As you know it isn't just about what is happening today but continuing to build for the future and to that extent we announced the sanction of the Neptune development project in June and all of the major construction contracts have been completed there, and development drilling will commence in the fourth quarter. The very important Alvheim [Viljay] product in Norway is progressing on schedule and through June, we're 20% complete there. And are conducting, at the present time, a feasibility study to tieback Hanson which is a 2004 exploration discovery to Alvheim. From an exploration standpoint, again a big part of our future, Phil Berman and his team had 5 announced discoveries in the first half of this year, out of 5 wells drilled. We expect to drill and complete 11 wells in the second half of this year, which will bring our total for the year to 16, which is in accordance with our plans, and again, as we've outlined in the press release and Ken mentioned strong success in both Angola, block 31 and 32 where the certainty of commercial developments at least two and probably three is now much greater.

In terms of our integrated gas business, Equatorial Guinea, LNG Train One, progresses ahead of schedule and on budget. We're 43% complete there and at the end of June about $815 million expended on the project. First LNG shipments still expected in late 2007. I think as all of you are aware, a really key part of that project is the ability to fill up train one beyond the existing bridge gas contract as well as the potential for a second train, and I think as you perhaps have seen in the press, comments by a number of key people from Nigeria, we're having good success in identifying and beginning to source additional gas supplies for train one fill-up and train two, and expect to continue to advance that for the remainder of this year. I'm extremely proud of the MAP team. As we were going through our negotiations and concluding the agreement that closed on June 30, they were not at all distracted by any of that. They continued a strong operational performance with once again record refining through puts at an ideal time; and again, as I indicated before, doing it in a safe and environmentally sound fashion. The Detroit expansion project continues on track, and is still scheduled for start-up later on this year. And we continue to look at the new opportunities that we've discussed with you before, in terms of coker opportunities at Cattlesburg in Detroit, as well as other expansions of our existing businesses.

And obviously with a strong financial performance and our focus on returning value to the shareholders, as you saw yesterday, increasing our dividend by $.05 or roughly 18%, we are focused on delivering that value back to the shareholders. As Ken indicated, from our debt to capital numbers, we have a strong balance sheet at this time, and the Company is very, very well positioned, with a great deal of the capital spend on our major projects ongoing and in many cases behind us, with a great opportunity set for the future.

So I say things look very promising for Marathon for the second half of this year, and I can assure you that Marathon and MAP or now, Marathon Petroleum Company teams will continue to focus and execute as they have done in the second quarter. And with that, Ken, I would turn it back to you for questions.

Thank you, Clarence. Cynthia, we're now ready to turn the call over to questions. I would like to remind everybody to please identify yourself and your firm affiliation for the benefit of those who are listening in on this call.

[Operator Instructions] And we will take our first question from Mark Flannery with Credit Suisse First Boston. Please go ahead.

Thank you. I have two questions. One is on operating costs. Ken, you mentioned in your prepared remarks that expenses were down about 11%, at least in the U.S. segment. We noticed that too. You mentioned higher volumes and damage recoveries from Petronius. My question really is, what should we expect those costs to do for the rest of the year? Are there one-time reductions included there? Or do you think this is a decent run rate for the rest of the year for the U.S. business? And then I have a follow-up.

Mark, I will make one comment and turn it over to Steve. There was about $20 million of insurance recoveries of reduced costs domestically in the first quarter. That was the only one-time item that is in there.

Mark, I think if you look at the second quarter results, I think they are a very good proxy of what we see moving forward. Without thinking about the continued weakening dollar that might affect the exchange rate, but I think the second quarter is a good proxy, both domestically and internationally, for our production costs.

Okay. And back on to the increase in the guidance in your volume, you mentioned you're better -- a better results in the first two quarters, is that you -- to increase full-year guidance. Could you point to any expectations of continuing better performance in certain areas? Or have you brought forward any start-ups or just a little bit more color on the transition between those two guidance numbers would be quite useful.

Yes, Mark, Steve again. Mostly what is driving the increase now, and we've both increased the guidance and we've narrowed the range and the range has been narrowed because principally we have two major risk factors behind us now. One, our Phase II expansion project in Equatorial Guinea is up and running and the Petronius platform has restarted after it concluded its restoration following the damage of hurricane Ivan. Those two things are big factors in terms of narrowing our range. We also are seeing better performance coming out of Equatorial Guinea, our liquid yields are a bit higher, and our Viculov development in Russia is exceeding our expectations. So those are really the principal drivers. As we look forward in the second half of the year, our biggest risk factors are going to be really the mechanical reliability, weather in the Gulf of Mexico, and really seasonal gas sales both in Europe and in Alaska.

Okay. Thank you very much.

We will take our next question from Bruce Lanni with A.G. Edwards. Please go ahead.

Yes, good morning Clarence and -- I got a quick question for you. In regard to -- let's first start with the downstream. I just really wanted some general guidance from you, you know, both you and Ken, on what you really believe is going to be happening in the downstream, say over the course of the next 12 to 24 months especially now that you have acquired 100% of MAP. Are you making any changes in your assumptions for mid cycle earnings as an example? And if you are, over what period of time? And also now that again that this is 100% your entity, are you planning any changes within the MAP system, possibly divestitures?

Bruce, let me take the high level question first and then I will turn it to Gary Hemminger do to give you more specifics. But again given MAP's historic success and most recently in the second quarter, we don't plan any major changes now that we have 100% of this. It wasn't about changing MAP or the way that it does its business, it is really about taking advantage of some of the strategic options that we see available to us by owning 100%. And really, we talked about some of those things in the past. That's really where our focus is going to be. And I will let Gary Hemminger give you a little more specifics on that.

Yes, Bruce, as I think we've talked in the past, we have always put together our business plans and tactical plans, while we were a joint venture, Marathon always used the same business and tactical plan that we were using within MAP and that continues, so we have not changed our mid cycle earnings outlook from those plans that we have going forward. And we constantly review market values of assets, both from an acquisition standpoint, and from any other market standpoint, but we do not have any plans at this time.

Okay. And just one other question, if I can make ask you, Gary, in respect to the downstream and then I will leave it with that. The energy policy that's going through, what type of impact do you see that having on your downstream business in respect to something like with MTBE or other areas?

Well, I see it having minimal impact. First of all, we were a very, very small producer of MTBE. Our maximum capacity ever was 5 thousand barrels per day. And in November of 2002, we got out of the producing business of MTBE. We have always been a very large ethanol blender, prior to MTBE, and during the MTBE phase in and now phase down. And if not the largest blender the country of ethanol, one of the largest. So I would say it has minimal impact going forward.

Okay. But fundamentally, do you see any changes? I mean just in the gasoline pool or other aspects of that, as you continue to switch over to ethanol?

Well, fundamentally, the industry is going to be octane short. Where if you take MTBE out of the marketplace, and the logistics of being able to move ethanol to the two coast lines, are going to be difficult as well. You know, if the -- if the energy bill ends up being approved, as it looks like it is going to be, and have a 7.5 billion gallon per year ethanol number by 2012, yes that is going to have some change in the overall marketplace. We expect ethanol to be about 5 billion gallons at the end of this year. So, you know, that is another 50% increase in ethanol by the time we get out to 2012. We will have a dramatic change. I don't believe in the overall -- but we have a lot of work to do within the industry on how we're going to move ethanol either paper ethanol or physical ethanol into the coast lines.

Okay. Well, thank you very much, and great quarter. And just great year to date operational results.

We will take our next question from Chris Moore with Merrill Lynch. Please go ahead.

Thank you. Could you give an update on Angola, kind of what you're thinking there in terms of exploration and when you think you might be able to come up with a development plan?

Chris, in block 31, we -- I think as you know, have announced 7 discoveries thus far, 4 up in the Northeast development, Marte, Plutao, Saturno, and Venus. BP is the operator, and along with the input from us and the rest of partners, they're finalizing concept selection and would expect to enter into front end engineering and design in 2006. Perhaps sanction the development in 2007 time frame, with first production in 2010. Beyond that, we have had three successes in the Southeast part of block 31, [Series], Palace and the recently announced Juno well. We've finished drilling the Australia well, but have not yet released the results of that, and we're now drilling on the [Hiby] well that is also in the same Southeast section. So certainly we will await the results of all that drilling activity to determine the next steps in that part of the block, but again, very promising there. And then of course, in block 32, Total operated where we have a 30% interest we have got three successes to date,Canela, Gindungo, and Gengibre. And we have now reached total depth on a appraisal well in Gengibre, but have not released those wells -- the results of that well, and we will spud another well and start a well in August. We also I think have now secured drilling rigs for all of 2006 for continuous drilling in both blocks. So I think as we've indicated to you before, a tremendous amount of opportunity in both block 31 and 32, and a big part, frankly, of our building for the future.

Okay. And on Russia, you made some positive comments there. Is any update on what you're thinking maybe volumes over the rest of this year and into next year?

Well, Chris this is Steve. Russia today is producing about 28,000 barrels a day. That's -- when we acquired the property, it was producing about 14,000. So since acquiring, we doubled it. I would suspect that Russia will average somewhere between 25 and 27,000 barrels a day, and earlier in the year we were ramping up and we have been having great success with our East Kamennoye Viculov drilling program there. We have drilled 37 wells so far this year. We have four rigs running. And will run through the rest of the year. We expect that we will drill and complete around 80 wells this year. We are in process now of injecting water and a water flood pilot in the Viculov and then we will monitor those results throughout the year, and then we're also doing some appraisal drilling on the right bank, drilling two long-range laterals over there, through the [vaginov] shale, and we should have those results before the end of the year, and a more firm idea of what the write back potential is.

Okay. Thank you.

We will take our next question from Neil McMahon with Bernstein. Please go ahead.

Hi, I just wanted to put in a few questions. First of all, it would be good to get a CapEx update. I think it was good to hear from the EG LNG project, that that seems to be on track and on budget. I was just wondering how much other parts of the world are you seeing any CapEx inflation? The second part of the up stream question -- I've got another one for Gary, on demand on the downstream -- is really around getting a handle on the size of some of your more recent discoveries during the quarter, around the world in particular, in Angola, and can you give us some rough indications of how big the gross discovery sizes have been?

Neil, let me say on Angola, not at this time. I think we would prefer to wait until the drilling advances a bit further before we talk about the total resource finds that we've had there. Steve will talk about the other.

Yes, Neil, on -- in large part of our capital program is driven by major projects, and these are multiple year projects. Clarence mentioned our LNG project in Equatorial Guinea. You know, that project is procured about 60% of the total capital already. It is around 43% complete. And about 90% of the remaining spend on this project is under EPC contracts. So as long as we manage the cope and execute within that scope, the project costs are relatively secure. The same is true of Alvheim. Alvheim has spent about 20%. It is around 20% complete. We secured a rig almost a year and a half ago for that. So the day rate on the drilling portion of this project is secure and fixed. And all of the construction on Alvheim is under lump sum turn-key contracts. So our biggest exposure on Alvheim is primarily exchange rate risk. In the currency that we are bringing in we're well in line with our budget expectations for that. We've just announced Neptune sanctioning in June, so Neptune is a little bit earlier in its spending profile. But we have secured -- we have secured the rig and about 40% of the total Neptune development costs. The day rate on those -- that rig is fixed. And about 35% of the construction costs right now are -- or 35% of the project is made up of construction costs, which is also fixed under lump sum turn-key bids. So in terms of our major projects, they're fairly mature in our understanding of them. Many of them are mature in the spending. And most all of them are secured under lump sum turn-key type arrangements. So our biggest risk is exchange rate. And execution within the scope of the project.

Great. And thanks for that. And just a question to Gary. From the driving data we've been looking at, it seems like the driving seasons got off to quite a significant start throughout the third quarter as we've gone through to date. Are you still seeing pretty strong demand in terms of gasoline and diesel and going through some of your stations?

Yes, Neil. On the second quarter, as Ken mentioned we were up 5.1% on a same store basis, versus Q2 of '04. And going into July here, surprisingly, at an average retail price of 2.24 across our entire network, we continue to see very strong demand.

Great.

On the distillate side, the same. We have pretty good optics through the pilot travel centers, and the -- Q2, the U.S. demand indicates about 3.5% increase in demand on distillates, and in Q2, at pilot, we were north of that number, and we continue to be north of that number coming into the third quarter.

Great. Thank you very much.

We will take our next question from Doug Leggatt with Smith Barney. Please go ahead.

Thank you. Good afternoon, everybody. The LNG project in Equatorial Guinea, you sold at a portion of that earlier in the quarter. Is there any chance we can get the contribution to cash flow number from that sale? I don't think we've seen that disclosed and any impact that is going to have on your capital expenditures going forward? I believe were you funding the whole project before?

There was no impact on the second quarter cash flows because we just closed earlier this week and there is a confidentiality agreement around that transaction. Also you remember that we account for the LNG project on a consolidated basis so the CapEx numbers that we give you already have 100% of spending.

Okay. So there will no change in that treatment going forward?

Right.

Okay.

But, Doug, just to be clear, we were -- although we consolidated that project, we did not fund 100% of that project. We funded it up until the selldown 75%, the government oil company, G Patrol was funding fully 25% of it, and of course now with the sell down, we will only be funding 60% of it. But for accounting purposes we will consolidate the variable interest entities so we will consolidate everything into our numbers.

Okay. That is very clear. Thank you. Just one follow up, I guess Oxidental sounded a little more positive about their update in Libya. I wonder if there is any update from the Oasis side of things.

I believe John Hess gave an assessment yesterday in the Enron Hess call and I would support what he said.

Okay. Thank you.

We will take our next question from Paul Cheng with Lehman Brothers. Please go ahead.

Hi, guys. Good afternoon. Congratulations. Very good quarter.

Thanks.

Ken, is Petronius, in the second quarter, are they in full production or are we going to see some ramp-up here?

Paul, this is Steve. No, Petronius is in full production in the second quarter. We had an initial ramp-up beginning really in April. But now, it is running just around 27,000 barrels a day net. And we would expect it to stay there for a few months and then we will see some actual decline.

And maybe this will be for Gary. Gary, do you still have any more remaining [hatches in pays] in MAP for the remaining of the year and next year?

Nothing remaining -- we didn't have anything for next year. And what we've reported in the 10-Q at the end of the first quarter, some of those -- I will call them fences or collars if you will, those are still remaining here in the second quarter, and will be reported separately. And as we went to August, September, nothing additional than was what reported in the first quarter. So there is still something to come off but we had already reported those.

Should we assume that from the -- from a strategic standpoint, or a little bit higher level, going forward, that do you still intend to engage actively in the hedging program? Or that you think you're probably just going to go with whatever is the market price?

Well, I won't say never, Paul. You know, we assess those, and we report those to our management committees who -- and we look at that of course every day in the commodity business. I won't say never. But as you can see, we have not put anything on since the first quarter and part of that is tied to the making sure we had enough cash to be able to fulfill MAP's responsibility for the partial redemption, within the transaction.

And talking about -- now, it seems that now you have become wholly owned by Marathon, and as part of the family, I think before that, there was some constraint whether you were going to make certain heavy capital investment in your facility, including the coker unit or other things, where are we there? I mean when are you guys going to make a decision whether you are going to proceed with some of the investment?

And I would really say that it is fair to assess that we were capital constrained. You know --

Not capital constrained but that may have some different interest between the parent corporation such that they constrained you to go ahead in a more speedy way in your capital investment.

Okay. Well, you know, fair enough. Where we are on -- we publicly have stated that we are studying Catlettsburg and Detroit and we are right on schedule with our front end engineering and we are going to make sure that we have all of our engineering done so that we have a very good understanding of the -- we have talked about the conceptual phase in the past. Now, we're understanding -- I shouldn't call it front end engineering. I will call it feasibility engineering, that we're making sure we understand the -- all of the -- some of the parts, before we finalize any project, but we're on schedule to finish that here in the end of the third, early fourth quarter, and present that along with our total budget process to present that to executive management in the fourth quarter. And of course, they approve the budget at the end of the fourth quarter, early first quarter is our normal budget cycle. But Paul, we're on schedule with our feasibility study.

So by the end of this year then, you will decide whether you are going to go ahead with those trends or not?

That would be the plan.

Okay. And I think the last two questions is for Clarence. Clarence, two questions, one, you mentioned that in block 31, the lot East discovery, you were thinking you may be able to fencing in 2007 and first oil in 2010. I'm just curious, I mean given that it seems like you're already have ordered discovery, it seems to be quite long, I thought that you may be able to fence in a little bit earlier than that, is there any hole up there, or just the way that -- how Angola is working, it will just take a long time?

No, I think it is a reasonable time frame. Again, we are in the ultra deep water there, Paul. And I think the operator BP, along with the other participants, Exxon and ourselves and others simply want to make sure we do it right. So I think it is a reasonable time frame. Perhaps if we had more than 10% interest, we would do more to accelerate it. But no, I think it is a reasonable time frame.

So it is not because the government has been -- perhaps they have their own agenda in terms of say when they want to bring on new production as a result that have you delayed?

No, we are not being impacted by any queueing up of developments at this time.

I see. And I know that it is a bit early, but wondering if you can share with us any rough estimate on 2006 capital spending, and also if there are any change in your capital spending for 2005 from the previous guidance?

Well, let me say with respect to 2006, Paul, we have earlier given guidance. I don't have the chart in front of me for capital spending in '06 and beyond. I would not want to change that at this time. But I do think certainly as Gary indicated before, as we go forward, the remainder of this year, and look at '06 and beyond, we will be analyzing that again, and when we issue our capital spend guidance in January, as we do, we will talk about what changes there are.

But can I just confirm, the number that you were talking before in '06 is not including any of the investment Gary tried to make in MAP?

The number we had talked about before, Paul, we had a place holder, we had stated before, in that capital budget, for the front end engineering piece, and maybe some long lead items. So we had a place hold in the budget. Not a big number. Gary Peiffer might know off the top of his head. But it wasn't a big number. We do have a place holder in '06.

And Gary, do you remember how much is that that you assigned?

Gary, do you know?

Yes, this is Gary Peiffer. In '06, we didn't expect to be spending a lot of money, assuming the projects were approved. It would be less than $50 million probably for Catlettsburg and so at this point we haven't clearly defined it, but those are going to be long lead time projects, which Catlettsburg, at least preliminarily, won't come online until I think 2009 is the latest thinking, so next year is kind of a ramping up year, if we decide to go forward.

Very good.

Thank you very much.

Thank you.

We will take our next question from Mark Gilman with Benchmark Company. Please go ahead.

Guys, good afternoon. A couple of things. Are you far enough along on the purchase allocation and the accounting on MAP to give us an idea what the incremental DD&A will be if there is any goodwill? And will you report that incremental DD&A included in the gross margin as present MAP DD&A is?

Yes, this is Janice. We are still working the purchase delegation accounting, as you can appreciate, it is really quite complex, there will be goodwill, and it will be on the order of about $800 million-ish. Around there. The DD&A after the purchase price accounting will be impacted by the transaction. We don't have any precise numbers right now, but it will go through DD&A. And I think that will be on the order of 60 million, plus or minus 10 to 15 million on either side.

And it will be recorded in margin, Janet just as it is currently?

Yes.

Okay. Also, with respect to MAP, I believe that in the release there were comments about an increase in the percentage of sour crude. Gary can you talk a little bit about that, quantify it and compare it to prior periods?

Yes in the first quarter we ran 51.6% sour crude and 62.9% in the second quarter and it is just a -- the only difference would be we had some spalling of the cokers in the first quarter for turn-around, and some other minor turn-arounds, that's why we were able to run a little bit more in the second quarter. No change in our conversion units.

What was the '04 average on that? Gary, you know offhand roughly?

Yes, I can get that unless Gary beats me to it.

59%. I think more importantly, too, Gary if you look at the second quarter last year, it was close to about 57%. So quarter to quarter, which I think what Mark is looking for is really a fairly substantial increase.

Right. And again, that would be for some turn-around and you know, one of the differences that you look at, is depending on the discount how much of that spalding crude you can run through different processes an our asphalt sales are up, and doing a very good job on our asphalt business, which leads us to run those heavier discounted crude.

Okay. On EG, looking post the startup of the LNG project, and the absence of re-injecting the gas, will the liquids plateaus be sustained beyond that point?

Mark, this is Steve. We're cycling that reservoir now and stripping the liquids out. And as we go into blow down, there will be some loss of incremental liquids, but this is a very high temperature reservoir, and the liquid dropoff curve is much more a function of the temperature drop than it is a pressure drop. So relatively speaking to most gas condensate reservoirs, we really lose very little to the reservoir, most of it is dropping out through the tubing and through the producing facility. So going to blow down or seizing injection has a minor, very minor impact on overall condensate recovery.

Steve is there anything to update us on Perseus and your plans there?

Perseus is being -- is already being developed. We were -- or Chevron was drilling their long reach well from the platform A20, and we were in the midst of completing that well when hurricane Ivan came through. And so one of the first things we did once the platform was put back together is finished completing that well. So that well is now up and producing. And it has been part some of the better performance coming out of Petronius. And I don't know if we're drilling it now. If not, we're very close to drilling the second long-reach well to also exploit the Perseus discovery. So we will develop Perseus with two long-reach wells from the Petronius platform. And that work will all be completed before the end of this year.

Okay. One more, if I could. I'm having a little trouble getting to your third quarter production number. And I guess, at first cut I would ask how much storm-related allowance you've got built into that range that you quoted?

Basically on the down side we've got about 9 days. On the high side we got about 6 days, so that would be essentially be about 3 storms where we have to evacuate and shut-in.

Okay. That helps a lot. Thanks a lot, guys.

We will take our next question from Jennifer Rowland with J.P. Morgan. Please go ahead.

Thanks. On the exploration side you mentioned the second half drilling 11 wells and you had mentioned what you were doing in Angola. Just wondering what other sizable prospects you might be drilling in other parts of the world that we should be looking out for?

Jennifer -- and I'm subing, obviously poorly for Phil Behrman who is out of the country, but we will have 2 wells drilled in the Gulf of Mexico, one is currently drilling at this time, a second will spud after it. We have the [Hiby] well currently drilling in Angola block 31 and will likely complete one additional well there in block 31 before the end of the year. We've got at least 1 and potentially 2 wells in block 32 to be drilled. We have a well in Norway on the Goodrun prospect, in which we have a 28% interest. We have 2 prospects in the U.K. to drill. And one well in Gabon to drill. So it is perhaps a bit more diversified set of wells than what we've done in the first half of the year, which was largely Angola and one in the Gulf of Mexico.

Okay. And just a question on the exploration strategy, you obviously had a pretty good success rate here on the exploration side and just wondering how you your strategy might change going forward as far as far as your appetite. Maybe to go into newer areas or potentially take higher working interest in some of the prospects that you look at?

Well, I think if you are drilling 100%, you probably don't want to change your strategy too much, except maybe ask yourself whether you're taking enough risk or not, but I think we are taking appropriate risk. I think we feel very comfortable with the portfolio we've got and the level of drilling we've got in '05 and probably '06. I think if Phil were here, what he would tell you is what he is really building for is what is the drilling portfolio going to look like in '07 and '08 and beyond. Because of the lead times and developing that prospect portfolio. And so he is indeed looking at new areas that we think offer appropriate risk and appropriate potential that are outside of the current areas we're focused on. But obviously for competitive reasons, I won't talk about where those are.

Okay. Great. Thank you.

We will take our last question from Paul Sankey with Deutsche Bank. Please go ahead.

Hi, good afternoon, everyone. Could I just ask about your balance sheet post the MAP deal, and the shape of it, and how you might look at that going forward? To the extent that you can answer that question?

Paul, are you asking about our capitalization?

Exactly.

Okay. I think Ken talked about at the end of the second quarter, net debt to capital, it was around 24%-ish. Of course, you know, the accounts receivable that was conveyed to Ashland as part of the consideration in the transaction will relatively quickly turn to cash. Or that cash will -- would have turned to cash had we retained it. So if you make an adjustment for that we would have been closer to 28 to 29% debt to capital at the end of the second quarter. So it puts us in very strong financial conditions and as Clarence noted we did increase our dividend yesterday by 18%. And I guess just to say the way we look at this, the balance sheet, is given the nature of our business, we think it is important to have a strong balance sheet, so that we're able to fund the opportunities as we capture them, because they tend to be large -- large projects that we go after.

Is the level of leverage there that you are talking about around where you want to stay? Or are you intending to move that either way?

Well, you know, I think we've got flexibility around that number. It really depends upon finding value-accretive opportunities to redeploy the capital.

And is there a credit rating backdrop to that that you -- I mean do you aspire to move that way?

You know, I think that really what we aspire to do is to create value, and I think the BBB-plus area is a very comfortable area from which we can maximize value and that is really what we focus on not the credit rating score itself.

Interesting. Thank you. If I could address a little bit of a strategy question as well regarding the fact that you've talked about integration and you talked about your ability to process crude. Is it set that your production slate is lightening over time, Clarence, could you address the issue of how you might manage -- how you might view that strategically?

Paul, in terms of the mix of crude and natural gas, or I'm not sure I understand your question.

Well, just in general term, Clarence, whether or not, you know, you feel you have the right slate going forward, for instance, you might also tie it into your global gas strategy, which I guess is a bit concentrated now in the Atlantic basin. You know, I was just going to slightly give the floor to you to talk about how you saw the shape of the Company going forward?

Well, I guess one of the things I probably don't pay too much mind too, Paul, is what type of hydrocarbons or the qualities of the hydrocarbons that we find or produce or refine. To me, it is really around the value that each one creates. So -- and as you know, there is very little connection today between the barrels we produce and the barrels we refine. And we're perfectly content with that. I think what we're simply trying to do is find those opportunities, as Janet said, that create extraordinary value and build a portfolio of assets and opportunities that deliver that value, and we continue to believe that the integration across our business of a profitable growing upstream, complimented by an integrated gas strategy, that in some cases will indeed capitalize and commercialize some of the upstream resource that we find attached to a downstream business that in and of itself is a high performing, very profitable operation. But that also is, as we've talked about before, may well provide us the opportunity to integrate upstream because of the market access it offers to those who have resource to offer. Because I would say again what we've said many times before, and have said before most people who are saying it today, but the biggest issue facing this industry is access to resources. And we believe that being an integrated company gives us access, not just to resource, but profitable resource that we look at in terms of the value it creates on an integrated basis. So you know, I think we've said before, the strategy we set out on four years ago is, we believe, the right strategy, not just for today but for the future, and I think it is evidenced in the things we're doing.

Sure. Thanks Clarence. I realize I asked you more about that but I realize we're past the hour so I will leave it for another time. Thank you.

And this will conclude today's question-and-answer session. Mr. Ken Matheny, I will turn the conference back over to you, sir.

Cynthia, thank you very much. Thank everybody for their participation and we look forward to talking about another quarter next quarter. So goodbye to all.

Once again, this will conclude today's conference call. We do thank you for your participation. And you may disconnect at this time.