馬拉松石油 (MRO) 2007 Q2 法說會逐字稿

Good day, everyone, and welcome to the Marathon Oil Corporation second quarter 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, and I too would like to welcome everybody to Marathon Oil Corporation's second quarter 2007 earnings webcast and teleconference. I'm sure by now you've seen our press release announcing our acquisition of Western Oil Sands. And Clarence Cazalot, Marathon President and CEO and Gary Heminger, Marathon Executive Vice President and President of our downstream organization will discuss this in more detail at the end of the normal earnings review. We will then open the line for questions from investors, analysts and the press.

As a reminder for telephone participants, you can find the synchronized slides that accompany this call on our website, www.Marathon.com. Also with us on the call today in addition to Clarence and Gary are Janet Clark, Executive Vice President and CFO; Phil Behrman, Senior Vice President of Worldwide Exploration; Steve Hinchman, Senior Vice President of Worldwide Production; Dave Roberts, Senior Vice President of Business Development and Garry Peiffer, Senior Vice President of Finance and Commercial Services for the downstream.

Slide number two contains the 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 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, 2006, and subsequent Forms 8-K and 10-Q 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.

Turning to slide three, net income for the second quarter was $1.55 billion versus $1.748 billion in the second quarter of 2006. This slide also provides a reconciliation of net income to adjusted net income by quarter for the last two years. The bar graphs on slide four show the quarterly net income adjusted for special items for the second quarter was $1.548 billion and provide the quarterly and yearly data for 2006 and 2005 for ease of comparison. Adjusted net income for the second quarter 2007 was up slightly from the $1.515 billion recorded in the second quarter 2006.

Slide five shows that on a per-share basis adjusted net income was up $0.17 or 8% from the year ago second quarter level and $1.23 per share or 120% above the first quarter. On a split adjusted basis we had repurchased 56 million shares as of the end of the second quarter at a cost of $2.5 billion.

Moving to slide six the year-over-year increase in net income adjusted for special items at $33 million for the second quarter was a result of higher margins in our downstream business largely offset by lower sales volumes and prices in our upstream business.

Moving to slide number seven, adjusted net income for the second quarter 2007 was $841 million higher than the first quarter 2007. This increase was primarily a result of higher average refining and wholesale marketing gross margin, somewhat offset by higher income taxes.

Turning to slide number eight, upstream segment income for the second quarter was relatively flat with the first quarter 2007. Positive price variances, slightly higher liquids volumes and higher other income were mostly offset by higher income taxes and higher exploration expenses.

As shown on slide number nine, worldwide sales volumes on a BOE basis were relatively flat in the second quarter 2007 as compared to the first quarter 2007 while the average realized price per BOE increased $2.13 quarter-over-quarter.

Moving to slide number 10, domestic upstream income increased $23 million in the first quarter largely a result of higher prices in other income, partially offset by lower sales volumes and higher exploration expenses. The lower sales volumes were largely a result of a scheduled turnaround at the Kenai LNG facility in Alaska.

As shown on slide number 11 the NYMEX prompt price for WTI crude was up $6.79 per barrel from the first quarter, while our average realized domestic realized price was up $5.87. Improved crude oil differentials for Gulf Coast sour and Gulf Coast sweet grades were more than offset by a higher Wyoming asphaltic discount. The bid week natural gas price was up $0.78 per million cubic feet from the first quarter while our natural gas realizations were up $0.25. Natural gas realizations as a percentage of the Henry Hub first of month index price decreased in the first quarter 2007, primarily due to weaker basis differentials for gas sold in the Mid-Continent and the Rockies.

Turning to slide number 12, second quarter domestic upstream expense excluding exploration expense was $1.69 per barrel of oil equivalent, higher than the first quarter, primarily as the result of the lower volumes. Domestic upstream income per barrel of oil equivalent increased $2.66 quarter-over-quarter, reflecting those higher realized prices.

Moving to slide number 13, international upstream income for the second quarter was essentially flat with the first quarter. Higher volumes and liquids prices along with higher income from our LPG plant in Equatorial Guinea, were essentially offset by higher income taxes and exploration expenses.

As shown on slide 14, our international liquids realizations were approximately $2.00 less than the increase in the price of Dated Brent. International crude realizations outperformed Dated Brent, primarily due to the timing of listings. However, our reported NGL realizations had a negative impact which reduced total international liquid hydrocarbon realizations. The decrease in the international gas price compared to the first quarter was a result of lower volumes and realized prices in Europe, and a commencement of gas sales to the liquefied natural gas facility in Equatorial Guinea. Please remember that our LNG business is recorded through the integrated gas segment, so the additional uplift in value realized by this facility is not reported through our upstream business.

Turning to slide 15, second quarter international upstream expense excluding exploration expense decreased $1.35 per BOE over the first quarter 2007, largely a result of the increased volume of lower cost natural gas production in Equatorial Guinea.

Moving to slide 16 on our downstream business, second quarter 2006 segment income was a record $1.246 billion compared to $917 million earned in the same quarter last year. Because of the seasonality of the downstream business I will compare our second quarter 2007 results against the same quarter of 2006. The most significant factor contributing to downstream's improved results quarter to quarter was the improvement in the refining and wholesale marketing gross margin in the second quarter of 2007.

As discussed in our interim update earlier this month the pricing of WTI crude has become disconnected from the actual cost in most light sweet available to refiners in the US Gulf Coast and in the Midwest. Because of this we have switched to market prices utilizing light Louisiana sweet or LLS as it is commonly called, crude oil prices which better represent the actual cost of light sweet crudes available both in the US Gulf Coast and the Midwest.

The LLS 6321 crack spread on a two-thirds Chicago and one-third US Gulf Coast basis increased from $11.24 per barrel in the second quarter 2006 to $15.47 per barrel in the second quarter 2007. Another positive impact in the second quarter 2007 compared to the same quarter last year was the change in our average wholesale sales price realization per gallon was higher than the change in the average spot market prices for the products that are used in the LLS 6321 calculation during these periods.

Our refineries ran extremely well in the second quarter 2007, setting quarterly records for crude oil and total refinery throughputs. Crude oil throughputs were up 3.3%, and total refinery throughputs were up 2.8% compared to the second quarter of 2006. These higher throughputs combined with the extremely strong margins in the quarter positively impacted our financial results on a quarter-to-quarter basis.

For the full-year we expect our total crude oil throughputs will exceed the record level of 980,000 barrels per day we achieved in 2006. Partially offsetting these positive results, was the fact that our crude oil and other feedstock acquisition costs were relatively higher than the change in LLS prices during the second quarter 2007, compared to the second quarter 2006 -- what the 2006 quarter would indicate. This is primarily due to the fact that non crude oil feedstock prices tend to move more closely with refined product prices than the cost of crude. Therefore, the relatively larger increase in refined product prices we experienced during the second quarter 2007 compared to the change in LLS prices, which on average actually decreased $1.41 per barrel quarter to quarter, resulted in a relatively higher charge in other blend stock cost than would have resulted just based on the change in LLS prices quarter to quarter.

In addition, we built inventories during the second quarter of 2006 versus drawing down inventories in the second quarter 2006, which given the change in prices in each quarter negatively impacted our second quarter 2007 results compared to the second quarter of 2006.

As shown on slide 17, Speedway SuperAmerica or SSA's gasoline and distillate sales were up 12 million gallons or an increase of 1.5% quarter over quarter. SSA's same-store gasoline sales volumes were up 0.9% and same-store merchandise sales increased 3.4% in the second quarter 2007 compared to the same quarter in 2006. SSA's gross margin for gasoline and distillate was $0.1029 per gallon compared to $0.1019 per gallon in the same quarter last year.

Slide 18 provides a summary of segment data, along with a reconciliation of net income. I will discuss three items of interest on this slide. First the integrated gas segment had income of $12 million during the second quarter 2007 compared to $19 million in the first quarter. As mentioned earlier, the LNG production facility in Equatorial Guinea shipped the first three cargoes of LNG during the second quarter. The increase in earnings from EG LNG was more than offset by a decline in methanol income as a result of lower prices and volumes, lower domestic LNG income due to plant maintenance and increased technology development costs.

Once the LNG facility commenced primary operations and began to generate revenue in May 2007, EG Holdings was no longer a variable interest entity. So effective May 1, 2007 we no longer consolidate EG Holdings because the minority shareholders have rights limiting our ability to exercise control over the entity. So our investment in EG Holdings is accounted for prospectively using the equity method of accounting.

Second, unallocated administrative expense increased to $96 million, $24 million higher than the first quarter primarily a result of higher stock-based compensation and pension expenses. And third quarter net interest and financing income was $20 million, essentially flat with the first quarter.

Slide 19 provides selected preliminary balance sheet and cash flow data. Cash adjusted debt to total capital at the end of the second quarter was 8%, up slightly from 7% at the end of the first quarter. And just as a reminder, the cash adjusted debt balance includes approximately $510 million of debt serviced by United States Steel. Year-to-date preliminary cash flow from operations was approximately $2.4 billion, and preliminary cash flow from operations before working capital changes, was approximately $3.1 billion.

Slide 20 provides guidance for the third quarter and full-year 2007, specifically related to production, our previous 2007 production available for sale guidance assumes first oil from the Alvheim/Vilje development in the first quarter 2007. While all other areas of our business remain within initial guidance, as announced this morning in the earnings release, the delay in first production from Alvheim/Vilje to the fourth quarter results in our 2007 production forecast now being 350,000 to 375,000 barrels of oil equivalent per day.

Despite this delay, our strong portfolio of development opportunities continues to underpin our 2006 to 2010 average production growth rate of 6 to 9% per year. I will now turn the call over to Clarence.

Thanks, Ken, and again good morning, everyone. Ken has covered the quarterly earnings, and I will just add that we did have another exceptional quarter from our downstream operations, which allowed us to supply our markets to the fullest extent possible. In integrated gas we completed commissioning of the Equatorial Guinea LNG facility and made our first shipment in late May about six months ahead of the originally planned date. In the upstream segment operations and production are moving ahead as planned everywhere except the Alvheim/Vilje product in Norway.

Due to the commissioning delays which Steve Hinchman outlined last quarter, we now expect first production to occur in the fourth quarter. As Ken just outlined, we moved our 2007 production guidance down due to the Alvheim delay, but I want to emphasize two things. First, this new guidance does not include any production from our just announced acquisition of Western Oil Sands but is an apples-to-apples comparison from our previous guidance. And second, again as Ken said, we remain solidly on track to realize 6 to 9% production growth between 2006 and 2010. And again, this is an apples-to-apples comparison and does not include any production from Western Oil Sands which would simply be additive to our production profile.

Let me turn to this acquisition. As you know, we had been working hard for the past two years to identify a Canadian oil sands business opportunity that will enable us to link our best in class US downstream business with a very substantial Canadian oil sands resource base to create increased value through lower-cost integrated solutions.

Moving to the first slide, you will find the forward-looking statement associated with the following presentation. Moving to slide two, as you've undoubtedly read by now, we have signed an agreement to acquire Western Oil Sands. As shown on this map, Western Oil Sands has a substantial position in the Canadian oil sands region, primarily through their 20% interest in the Athabasca Oil Sands Project or AOSP. This acquisition will link the world-class AOSP multiphase development with our best-in-class refining assets in the Midwest and Gulf Coast, providing opportunities for significant value enhancement.

It also means that we will maintain complete ownership and control through the value chain while providing a lower-cost alternative to upgrading the crude in Alberta, and will provide for finished products rather than synthetic crude which would still need to be refined. The acquisition secures for Marathon long life production of OECD crude for future refinery upgrade projects and positions Marathon across the entire value chain. It will also allow for our future refinery upgrade projects and transportation solutions to be sequenced so as to coincide with the planned production growth from the AOSP expansion projects.

Turning to the next slide, we are acquiring Western Oil Sands for a total consideration of about C$6.5 billion or $6.2 billion US using the midday exchange rate and Marathon's closing share price as of July 27th. It also includes Western Oil Sands debt of approximately $650 million US at June 30.

Western Oil Sands shareholders will receive approximately C$3.8 billion in cash and 34.3 million shares of Marathon common stock. This acquisition will significantly increase our access to resource, providing two billion barrels of net resource from mined bitumen acreage and another 600 million barrels of net oil resource from in situ acreage for a total of 2.6 billion barrels of net resource at very attractive prices.

On a pro forma basis at year-end 2006, this acquisition will increase our reserve to production life from 9 years to 12 years, and increase our proved reserves by over one-third to 1.7 billion barrels equivalent. In addition to the mining and in situ assets this deal encompasses, it also includes a 20% interest in the Scotford Upgrader, which creates additional value by processing the AOSP bitumen into higher value synthetic products. Currently Western's share in the upstream operations of AOSP produces 31,000 barrels per day of mined bitumen and is shown on the next slide with five well-defined expansions. Net production is projected to grow to over 130,000 barrels per day by 2020, and will in fact remain at that plateau for many years thereafter.

We see Marathon's refining network as very well positioned to provide the best value commercial and processing solution to the increasing volumes of Canadian oil sands in general and AOSP, in particular. I would now like to have Gary Heminger share with you additional information on our planned integration of these assets.

Thank you, Clarence. As we likely have many Western Oil Sands shareholders and analysts on the call, I would like to share with you some highlights of our downstream operations and potential projects. As you'll see on the next slide, Marathon's seven refineries with almost one million barrels per day of refining capacity really operate as one fully integrated system through our extensive pipeline, barge and terminal operations.

Those of you that follow us will recall that we are currently conducting a front-end engineering and design or FEED study for a heavy oil upgrade project at our Detroit refinery as shown on the next slide. If approved this project will increase the refinery's crude unit capacity to approximately 115,000 barrels per day on a calendar day basis, include the construction of a 28,000 barrel per day heavy oil coker and other associated process units.

While we are not finished with the FEED study, we are close enough that we believe that we can process an incremental 80,000 barrels per day of heavy sour crude at Detroit for less than half of the capital investment needed to build new upgrading capacity in Alberta. Not only will this be at a substantially lower cost as I just described, but it will also provide higher value consumer products such as gasoline and diesel rather than a synthetic crude oil, which as Clarence already mentioned would still need to be refined into finished products.

Beyond the Detroit project, we continue to evaluate the potential for similar heavy oil processing projects at our St. Paul Park, Minnesota and Robinson, Illinois refineries. In addition, both our current, Garyville, Louisiana refinery and the new Garyville refinery currently under construction have the ability to run Canadian heavy crude and through our extensive barge system we will have the ability to transport AOSP crude oil to that location when economics warrant this supply alternative. Importantly, these upgrading projects can be sequenced to coincide with the planned production growth from the Western Oil Sands expansion projects, as well as production growth from other oil sands projects seeking to find markets for their crude oil.

Finally, moving to the last slide, you will see that there are a number of already proposed pipeline solutions to move increasing volumes of Canadian crude into the US, and we will work with the same diligence that brought us what we believe to be an outstanding win-win solution for capturing value across an integrated oil value chain with Western Oil Sands and seeking the proper additional pipeline solutions needed. And with that, I will turn it back over to Clarence.

Thanks, Gary. I would just sum it up, ladies and gentlemen, by saying that we see this acquisition as really providing a significant value opportunity not only for the Marathon shareholders, but for Western shareholders as well. And we have what we believe is truly the highest value commercial solution to world-class oil sand assets in Canada. And with that, I will turn it back over to Ken for questions.

Thank you very much, Clarence. We will now open the call to questions. I would like to remind people to accommodate all who want to ask questions we ask that you limit yourself to one question plus a follow-up; you may reprompt for additional questions as time permits. And for the benefit of all listeners we ask that you identify yourself and your affiliation. Go ahead, operator.

(OPERATOR INSTRUCTIONS) Doug Leggate, Citigroup.

Congratulations. Can I try a couple? I guess the first one is what are the risks of the deal falling apart? What if a third party comes in, what are the provisions you've built in there? And secondly, could you talk a little bit about how this impacts your CapEx outlook going forward and what your thoughts are on a comfortable level of debt, given the commitment you've made for share buybacks as well this morning? Thanks.

I'll take the first one. It is a fairly standard agreement. There are no-shop provisions in the agreement, meaning and the directors and officers of Western have agreed to support this proposal. That is the first thing. And if there is a superior proposal made, then Marathon will have a right to match that proposal on a go forward basis.

Is there a fee, a breakup fee?

Yes, sir. Sorry I missed that, Doug. There is a breakup fee of C$200 million.

Thanks.

And Doug to your question on debt levels, pro forma for this transaction net debt to total capital will be in the mid 20% range, 26%. And I think it is also important not to look just at book capital, but also on an enterprise basis our net debt to enterprise value is closer to 13%. And if you look at some other measures of credit capacity, debt to EBITDA pro forma for this transaction, without giving any credit for EBITDA from the transaction itself, is around 50% or 0.5. So I think that we are still very comfortable, very strongly capitalized pro forma for this transaction. The $2 billion of incremental stock buyback will be executed appropriately to maintain the strength of our balance sheet. And in terms of CapEx, over the next couple of years the incremental CapEx associated with this acquisition is on the order of $900 million to about $1 billion a year.

And that includes Detroit.

Including the Detroit coker, absolutely.

Great. Thanks very much.

Doug Terreson, Morgan Stanley.

On Western, while the strategic rationale for the transaction is pretty clear, my question regards your financial objectives on this transaction, meaning with pretty healthy industry conditions thus far in 2007 your returns are over 20% which are obviously very strong. With the Western transaction, Gary talked about further integration and value capture, and on this point I wanted to see whether you could quantify some of the financial benefits that you envision from integration of this transaction. That is while the upstream benefits are pretty obvious from Western's financial statement I want to see if you can shed some light on the specific financial benefits from the downstream component and any total return expectation that you might have had when you entered into the transaction today.

Doug, I will tackle part of it, and then Gary or Janet feel free to jump in. I would say first of all as we looked at our economics around this transaction we did not include any downstream benefit just so we are clear. And I think in terms of describing any downstream benefit, one of the great things about this is it gives our downstream team that I think probably is the strongest commercial team in the business, tremendous optionality around how we take those volumes and capture value from them.

And so while we refer to Detroit as the nearest term and most likely solution and we can see, indeed, that refinery having the capability of handling sort of the heavy synthetic and bitumen net production coming out of AOSP for us through about 2014, there is still a lot of optionality as Gary indicated, we can underwrite conditions actually barge this crude to Garyville. Which we have done this year when the economic -- not necessarily this crude, but Canadian crude, when the conditions were right. So I'm not prepared to give any returns or whatever, but the value creation I think is around a much lower cost that we can commercialize this at.

As Gary said, well less than half and as a good benchmark, take a look at what was announced yesterday by one of the major players in Canada in terms of the cost of an additional 400,000 barrels a day of upgrading and I'll guarantee you our costs are substantially less than that. And again, I think then just the commercial value around what we can do moving these volumes to where we see the most value. So I don't know, Gary, do you want to add anything to that?

That was perfect, Clarence.

Thanks a lot, guys.

It's not even bonus time, and he said that.

Exactly. Thanks a lot.

Arjun Murti, Goldman Sachs.

Just wanted to clarify a few things. The phase I expansion for Athabasca I believe goes to the Scotford Upgrader; so the Detroit opportunity is really for the future phases?

Well, really what comes out of the Upgrader today is a variety of products, and one of those products is actually an Albian Heavy that we could begin taking at Detroit today. And the volumes are around I think 25,000 barrels, something like that. There is volumes that could go to Detroit today. But again, we won't necessarily say that they are committed to Detroit today. That is part of the commercial optionality our team will have around whether or not we take those volumes to Detroit immediately or not.

In the 80,000 barrel a day opportunity that probably is for future phases in terms of the Detroit coker?

Yes, Detroit would come on stream I think, Gary?

Yes, Detroit would come on stream at the end of 2010, and our plan is looking at what Western is producing today we can -- and in fact we can take some of those barrels today if need be into our system. But as we bring that coker up in 2010, the next expansion 2012 timeframe we believe that Detroit will have the appetite for the heavy crudes that come out of the next expansion, well out middle of the next decade before we need to consider any further solutions. And we can sequence those solutions down the road with the rest of our refineries.

I would just add, it is not just the refinery solutions but by the middle of the decade we think the transportation solutions, particularly whether or not Gulf Coast transportation has materialized or not, would be much more obvious and allow us to factor that into our decision-making.

Neil McMahon, Sanford Bernstein.

Maybe, Clarence, just a follow-up on your point there on the pipelines. Where are you in getting capacity in the new pipeline expansions, both to take crude down to the Gulf Coast and to the Midwest? Given the fact that you've now got a good handle on what your output from the oil sands could be; and I've got a follow-up question, as well.

Okay, Gary.

Neil, obviously we have been working with the major transporters for some time, and now that we have announced this transaction we really can formalize. There are going to be some open seasons on both the southern access and the keystone expansion that's going on, and then there will be additional pipelines that will be laid out of the Chicago market that will go east towards Detroit and possibly some other markets. So we will be finalizing and formalizing those transportation options here over the next balance of this year as we go forward.

Looking at the options to the Gulf Coast, there have been many discussions and at this point we have had some of those discussions but have not formally nominated any barrels to those projects yet. But we will look at those now and determine whether or not we would want any space. The direction we would need to go would be to the New Orleans corridor, most of the pipelines that have been discussed to the Gulf Coast have been particularly to the Houston refining ship channel area. So we would need a solution to be able to get barrels over to Garyville if we were to elect to go that direction.

A follow-up associated with the deal, I suppose. Maybe a comment from Phil Behrman or indeed Clarence, why was the Kurdistan oil opportunity not within the package? Obviously it is not connected to the refining assets, but I would have thought from an exploration point of view it was something of interest to the exploration team.

I'll take this one on. Marathon just took the view that we were very focused on creating an integrated value solution through the oil sands. Again, what we are focused on is what we do best, and that's one of the things that has been a key strategic theme for us. So we were very focused on that. The value that Western Oil Sands placed on Kurdistan was superior to what we could imagine and we think that we created the best commercial transaction by allowing them to seek that value independently while we are going to focus on the maximum value solution for Marathon shareholders.

Great. Thanks.

Mark Flannery, Credit Suisse.

Yes, I just would like to clarify something on the expansion phases. Western Oil Sands does not participate in the upgrading expansion. Is that correct? So after phase I or from expansion 1 onwards you get the rights to the bitumen. Is that right?

That's absolutely correct, Mark, that the parties have agreed through expansion 1 to upgrade the existing Scotford Upgrader but for expansions 2 on all parties are on their own as to how they commercialize their respective share.

Right, and my follow-up I guess is how are you feeling about the costs of expansion 1, and the operator should we say has not had a stellar record of controlling costs at this asset. So what are the current estimated costs of expansion either per flowing barrel, if you like it, and how comfortable are you that that is where they're going to stay?

Well, Mark, one of the things that was attractive about this transaction is quite frankly we are pleased to be partnered with Shell and Chevron in the Athabasca projects. Just from a perspective standpoint your comments probably would have been taken as more correct a year ago but quite frankly, Shell has been proven to be a leader in terms of recognized (technical difficulty) cost pressures in the Alberta Province. And so from that particular perspective we feel very good about the technical capability of Shell to deliver this project.

On a gross basis Shell has talked about US values for this phase of the project around $11 billion. We spent a lot of time getting comfortable with those numbers in terms of what our commitments were going to be. And quite frankly we think that those project costs are very comparable with what you are seeing in this space today, and we believe that we will be completely aligned with Shell in terms of managing those costs on a go forward basis. So all in we did a lot of diligence on this. We feel very good about the decisions that we made, and quite frankly we are looking forward to working with Shell in the future.

Great. Thank you.

Nicole Decker, Bear Stearns.

Good morning. Just wondering given the relatively lengthy ramp up period on the production side, does this field completely satisfy your objectives on your integration ambitions?

Nikki, no, I would not say it completely satisfies our objectives on overall integration if you are referring to a global basis. I think with respect to the strategy we've had around Canadian oil sands yes, I think this is certainly a significant amount of resource. And when we've only been talking about AOSP here there is the in situ resource that we will be looking at and determining what is the best way to commercialize that. So we are going to have our plate full, I think, in terms of Canadian resource and creating value from that. But we will certainly look at other integration opportunities on a global basis.

Thank you. And just for my follow-up question, the resource or the reserves that you talk about, are those SEC reserves, or are there some mining reserves in there, as well?

I think we've tried to outline that which is mineable so when we refer to the 436 million barrels of proved reserves, that is mineable, so it would not -- those would not fall under our required oil and gas disclosures. So the mineable would not fall under SEC guidelines, but ultimately the in situ or SAGD would. But right now that is resource. It is not yet proven reserves.

I understand. Thank you.

Paul Cheng, Lehman Brothers.

Couple of questions. Gary, you talk about the Detroit plan. With this particular acquisition does it change the outlook for Robinson and Catlettsburg?

With this, we have always had Detroit kind of in first position and in doing our engineering work and yes, we have talked about Robinson and Catlettsburg in the past. And so we will continue on, and we expect Robinson to be -- excuse me -- Detroit to be first out of the blocks as we go forward with upgrading our refineries. We are in the feasibility stage still at Robinson and looking at opportunities there. With really coinciding with what Clarence mentioned, the transportation options is really -- Patoka is going to become the new hub for oil sands in the US. And we are only 80 miles to the east, so Robinson has a competitive advantage from a transportation standpoint. And I would say that Robinson is probably going to be second in line as we look right now. However, we've added St. Paul to the list and have talked publicly about St. Paul in the past because, again, competitive advantage on transportation costs probably a couple dollar advantage over even the Chicago area, to be able to get crude into St. Paul.

We are looking that on a smaller scale but as an option, as well. So lastly to Catlettsburg. We really stopped work for the time being on Catlettsburg because of the substantial transportation cost; it is about 400 miles from Patoka to get to Catlettsburg. Now, depending on how changes may be in the industry and how some of the pipelines may come across that would service Detroit, and maybe some other refineries in the eastern part of [patu] transportation options might open up down the road. And as Clarence mentioned that really helps us in the middle of the next decade to determine what is the next best project to go forward with and we think transportation options probably will really carry the day on that decision.

Gary, if Detroit you may come to a final investment decision by the end of the year, what kind of timeframe for Robinson?

Robinson, we will determine at the end of the year the feasibility phase whether we want to go into a feed stage. So it would be probably first quarter next year before we would get that work done to determine if we want to go to the next stage there at Robinson. And Robinson would be a much more complex project, and it would be in a probably 2012 to 2013 to 2014 timeframe is kind of the window we are looking right now if that were to be a project we would consider.

Can I just have a somewhat separate question? Clarence --

Last one, Paul, thank you.

Just wondering that in this particular transaction, who approached who? Did you guys approach Western, or Western approached you? Can you describe the process a little bit for us? Thank you.

Paul, I don't want to go into the details now. I think ultimately, that gets laid out in a document and it will all be out there, but let's just say it was a meeting of mutual benefit.

Dan Barcelo, Banc of America.

A question regarding upstream a little bit. At the second-quarter stage if you could basically provide a little bit of an exploration update. But then as a follow-up on the upstream, I really wanted to know if you could touch on the upstream strategy as it relates to the integration of this Western Oil Sands deal. Basically, downstream integration makes total sense to me, but when I think upstream, I think the Company has been very good at lower F&D, controlling production costs, good growth, exploration led.

And I just wanted to know how going forward we as analysts and investors will look at Marathon's basically upstream strategy. Does the Oil Sands' growth basically preclude other growth you may look, and how you weigh those differences between different resources?

I'll start with the exploration side. At the present time in the Gulf of Mexico, of course, we finished all of the Droshky work in second quarter. Plans in third quarter are to drill Flathead well. We are still working on the timing of that. But roughly in the third quarter, we should see a spud. And lastly, in the Gulf of Mexico we will drill an appraisal well in our Stones discovery in the fourth quarter, starting in the fourth quarter.

In Angola Block 31, we currently have one rig active, and we will be active not only in third quarter, but also through the fourth quarter. In Angola Block 32, we have one rig active, and it will be active in the third quarter, and we will lose that rig at the end of the third quarter. And lastly, in Norway we plan to drill one additional well in the fourth quarter of 2007.

I guess, Dan, I would only say that if you think about the Western acquisition, you have to view it from two components. One is certainly the mining side, that in terms of our upstream business, doesn't have the same kind of below-ground risk or even employ the kind of technologies we employ in the rest of the upstream. So it's a very low risk, but steady level of reserve adds over many years to come that will certainly factor into our production growth profile.

But our real focus there, as you've already said, is going to be around capturing the commercial value and downstream value from those assets. Where our upstream business will come into play is certainly around the in situ assets where the steam-assisted gravity drainage technology is an upstream technology.

So we will be certainly be studying those assets and determining what is the best way for us to capture that. How does it impact the rest of our business? I think this has been a part of our strategy for a long time, an integrated approach around Canadian oil sands. We will continue on our upstream business to grow through successful exploration, as Phil has already outlined. We will continue to grow through integration and employing particularly gas commercialization technologies, whether it is growing our LNG business, whether it's gas to fuels that I know Dave Roberts has talked about before, and employing those kinds of technologies to commercialize stranded gas.

So we've got -- we've had as you know a pretty robust growth profile through 2010. This production will continue that growth for a long time, and we want to continue to add and enhance on to that. And so it really is not a new component. This really was a component that we have built into our strategy for some time.

Thanks very much.

Mark Gilman, Benchmark Company.

I wonder if you could talk for just a second about the quality of the in situ resource as you believe it to be at this point.

You know, Mark, I think to a certain extent we want to be careful until the transaction is completed. I think what we've tried to do with respect to these assets, and we have signed confidentiality agreements with Western, is not get into specific details that reflect our thinking that go beyond what they have already disclosed to their shareholders on the website. So I would prefer to have that discussion with you after the transaction closes.

Okay, by way of a follow-up, I assume all of the resource numbers that appear in the release and that you quoted, Clarence, are unrisked numbers for all categories?

That's true, Mark, but one of the things I think you need to focus on here is one of the attractive aspects of oil sands is particularly with the mining assets, is you can reach out and touch these things. And so as Clarence has already said, there is significantly less risk involved in terms of those recovered resources that we are looking at in our numbers.

The other point I would make, Mark, is the production chart we've shown you only carries through expansion 5. I think if you go out on the website for AOSP I believe they actually carry it or talk about the other expansions and we've not factored in anything for additional expansions. We've not factored in, as I said before, into our analysis or any of those production charts anything for the SAGD resource. So I think it is risked in terms of we've assessed those projects that we think have the highest likelihood of going forward, and again as you know with the mining side, this isn't a matter of estimating how much recovery you get. You get all the recovery in the resource. It is a matter of controlling the costs, both the investment side and the operating cost side.

Gary, do you have a cost number for Detroit yet or at least a ballpark that you can speak with us about?

We really want to wait until we get the FEED done, but we believe, as we said in our remarks, it will be less than half. It's going to be somewhere probably in the 20 to 25,000 barrel of capacity barrel basis. That is a big spread, but we feel we are being conservative in those numbers, and we will be able to give you a really good flavor of that at the end of the year.

John Herrlin, Merrill Lynch.

A couple quick ones, one, when would you expect to book SAGD reserves? Two, I think Janet said if you spend and combined upstream downstream on Western Oil Sands about $900 million to $1 billion a year. What about just on the upstream side?

John, I'll take the first question. It is premature for us to speculate when we would book them. We are just -- there is a valuation of those leases underway both by Western as operator of some of the leases and Chevron as operator of the others. So at this point we've got a lot of work to do in understanding the commercial value of those assets. So premature for us to comment on that.

I don't have the exact numbers right in front of me at this point, but -- and we don't have the precise numbers on the downstream in any event, but we really wanted to give you a sense of the kind of capital we would be spending between now and 2011 when that Detroit coker comes on and expansion 1 is fully on.

Okay, last one for me is, Phil, you didn't mention anything on the Bakken and the Piceance. Anything going on there that is new and different?

This is Steve Hinchman. I'll take that. The Piceance we are just getting started. In fact, we just have a rig now just began to sludge just a week ago, so we are just getting really started so there is no update on the Piceance. In the Bakken we've roughly drilled about 18 wells, we've been evaluating 10 prospect areas, so we've identified some areas that we like. We've identified some other areas that aren't as good and we will look to use that information to high-grade our acreage position. We are currently producing around 12, 1300 barrels a day net, and the response that we are seeing on average up there is still pretty much within the expectation around 300 barrel oil equivalent per day, 30 month average and looking at EOR still on the order of 300,000 barrels per well. So no major surprises, and we're going to be moving from in particular from an evaluation phase to a more aggressive development in the acreage that we like.

(OPERATOR INSTRUCTIONS) Eitan Bernstein, Friedman, Billings, Ramsey.

Congratulations on a good quarter. A real quick follow-up, I think relates to the first quarter. There is a no-shop clause, but do the Athabasca partners have a right of first refusal on this deal?

No, they do not because it is structured as a corporate transaction they will not have a right of first refusal.

Excellent. Thank you very much.

Ron Oster, A. G. Edwards.

I was just wondering if you could comment on the change in asset mix between upstream and downstream we might see before the acquisition and on a pro forma basis post acquisition.

I'm sorry, the change in asset mix before and after --

Just in terms of an upstream and downstream mix on a percentage basis.

In terms of capital employed or --?

Exactly.

We are looking here real quick.

It isn't necessarily (inaudible)

We will have to get back to you on that, but I think as Janet just pointed out, this will not necessarily be in the upstream segment. We are still looking at how this will get captured in our reporting.

Of course if you want to view it that way it certainly would shift the balance more towards the upstream than to the downstream.

Okay, and then in terms of the financial metrics we were a little surprised at the limited amount of detail. Were there any -- is there any guidance you can give us in terms of the testing parameters or the cost in terms of oil prices or refining margins that you kind of factored into your analysis on this deal?

Well I can tell you that in terms of the analysis we basically used our pricing credits for our 2008 budget cycle, which we are just kicking off. So we looked at this project just the same way we look at all of our investment opportunities.

Can you refresh me what those parameters are?

I don't think we've made those public.

I would only say that our (inaudible) price forecasts take into account the situation we see in the world today where there is both tight access to new resource and supply is struggling to keep up with demand. Particularly as the resource is held increasingly by the national oil companies, and there is clearly not sufficient investment being made to grow, I think both production and refining capacity to keep pace with demand. So we certainly believe that we are in a stronger pricing environment than we saw a year ago. But I would tell you that the pricing we are using is pretty well below strip prices today. So we are not using strip. We are using from a light heavy differential projections that are consistent with what we've seen historically. So we think they are very reasonable projections based on the conditions as we see them today.

Okay. Thank you.

Katherine Lucas, JPMorgan.

Can you just tell me whether the production from the first expansion and the current production from Muskeg River Mine is under obligation to go to the Scotford Upgrader? Or do you have an opportunity potentially to send that elsewhere if you choose to do so at a later date?

All of the production from the base mine and expansion 1 are committed to the existing upgrader and then expansion 1 will expand the existing upgrader. So there is no flexibility with respect to those initial volumes.

Neil McMahon, Sanford Bernstein.

This is a question for Dave Roberts. Just wondering if there is a -- if you could provide us with any idea of what you benchmark this deal against since Marathon as a company has been studying these options for the last two years. I was wondering is there a particular acquisition you were looking at in the past as a benchmark? Or indeed what you took as sort of your stake in the ground to assess the value to your shareholders by doing this deal?

Good question Neil, and I think the short answer is that this was not done on a comparable transaction or just trying to match up. What we tried to match up again was what we bring to the table and what Gary has talked about is the value of our downstream solution. And what I've said repeatedly, both publicly and privately in Calgary is we were not prepared to dilute our downstream advantage. And what this transaction allowed us to do was to maintain that value to Marathon shareholders throughout the value chain. So we could bring -- there is value on the upstream but there is enhanced value on the downstream. So there wasn't a comparable transaction metric that we used for this. It was just what's the total value creation for Marathon.

And I would just say, Neil, we have continually said as we have looked at integrated joint ventures that the difficulty we always faced was ensuring that there was comparable valuations on the resource side with the downstream side. And I think that has been the challenge all along. And you've seen recent statements by some of the Canadian players about the fact that they want to see US refining values come down so they can acquire the assets at a later date. We still believe a great deal of the value is in the downstream, and what you really do to commercialize this resource.

So the other thing I would say is a lot of the other deals that you probably looked at in the past people were buying resource that yet hadn't been permitted or no definitive development plans for. This is an asset that is up and running today going through all of the initial startup and regulatory issues is in an expansion mode, and so it to us is a much, much better valuation.

I would presume that you would be pretty surprised if anybody was to beat this offer given the synergy value if I put it that way, that you get from the downstream addition from the upstream assets.

That is obviously, Neil, that is not something we can control. We think we've got a solid transaction here that is good for both sets of shareholders and what happens in the next two months is not something we control.

Doug Leggate, Citigroup.

Apologies for the follow-up, folks. I wanted to change type a little bit here because the focus obviously this morning on the oil sands has been about resource and you mentioned the reserve life issue, Clarence. If you take out Equatorial Guinea which did not produce last year, obviously, your reserve life for the existing 350 or thereabouts production was less than 6. However, you haven't talked much about Angola recently other than the (inaudible) press release is on exploration success.

In November last year you stated you had more than 250 million barrels of resource, but since then there has been a number of discoveries. Could you maybe give us an update where you see that resource number, how does that potentially changes your conventional resource debt and associated reserve life and any update on expected or wells that are currently at TD that we are expected to announce at some point in the future?

Just to give you a sense of it, in fact Steve Hinchman and I will kind of tag team a little on this, we are not at this time prepared to update you on the overall resources that we discovered in Angola. But as you know, we've got 24 discoveries in Angola on blocks 31 and block 32. And it split 15 discoveries on block 31, 9 discoveries on block 32 that we've announced todate. We are continuing to drill. As I noted with two rigs running on the two blocks one on each block.

And in addition to that, we have two wells which have reached TD and then upon government and partner approvals we will continue to make more announcements. On the development side we are moving forward, as we've told you, towards year-end with finishing our first project, which is the Angola block 31 northeast area. That FEED is completed, and will move and our expectation is by year-end roughly we will have that sanction. Of course we book no reserves until we sanction the project.

We have other developments which are undergoing maybe about 18 months maybe two years behind that, which is the middle area of block 31 southeast area of block 31, as well as our block 32 kind of what we call east central area. And so we will continue to drill wells, add resources to these potential areas, but they will be roughly 18 to 24 months behind that in terms of sequencing these developments in.

Given that these are somewhat long dated beyond the northeast sanction potentially, do these become trading assets at all? Is that something you are considering, or are you quite happy to participate fully in oh, four, potentially five developments?

I think Neil, pardon me Doug, the easiest way to look at this is we create of value by finding the resource through the drill bit. Once we've completed a lot of our exploration work, we create more value through the development or we can simply trade or exit some areas. That is all simply options that we create. But we've created that value once we found it, and we certainly move forward with more value creation as we reduce some of that uncertainty with a development. So indeed those are all options which we could consider.

Great. Thanks.

Jessica Resnick-Ault, Dow Jones Newswires.

I'm interested in going back to some of the transportation questions for Canadian crews that are posed by this acquisition and in particular I am interested in the previously proposed Alberta Texas high-speed pipeline. I am trying to figure out whether that plan could be shifted to run toward Louisiana toward the Garyville refinery, as I know some Marathon executives had previously suggested. And I am wondering if there has been any move toward changing the pattern of that pipeline or of any other proposed projects to accommodate Garyville.

Jessica, as we I think I visited with you back early in the year, talked about that as an option. The transportation routes to the Gulf Coast, whether it be the Houston corridor or the New Orleans corridor is very dynamic. We continue to work with the pipeline operators on different options going forward. I would say that today I certainly don't want to mislead -- today we do not see an option as drawn out on the board that is looking to bring a new pipeline to the New Orleans area. But there is a substantial amount of discussion going on about the tremendous demand up and down the whole US Gulf Coast. So I will just say stay tuned as we continue and now that we have made this transaction public we will be able to work closer with the pipeline companies to determine the future routes.

Thank you, Gary, and thank you for allowing media to ask questions today.

A follow-up from Mark Gilman, Benchmark Company.

I got cut off in trying to clarify your comment regarding the Detroit coker. I think you said 20 to 25,000 per daily barrel, and I wanted to know whether that is on the 15,000 crude expansion and including the coker cost.

No, that would be on the incremental, as we said in our remarks we would expect to run an incremental 80,000 barrels a day of heavy crude. And that is a very good question you have, Mark. That is a sometimes a difficult benchmark to use. You really have to add in all of the downstream process units. So that would include the coker, the hydrotreating work, the expansion of the crude unit, that would include all of that cost in order that we could run an incremental 80,000 barrels a day of heavy crude.

So in getting to a total cost number per your estimate at this point anyway, the 20 to 25 is on an 80,000 number?

Yes, on the incremental piece, yes.

Okay, and just check my arithmetic on something. I am coming up with annualized second quarter western cash flow in the neighborhood of $300 million, which would make this about a deal at about 20 times second quarter cash flow. Am I in the right ballpark?

You know, Mark, I don't think so. I remember a number having read their earnings release but I would refer you to that but I think you are quite high on that number.

Okay. Thanks, Clarence.

Catharine Sterritt, Scotia Capital.

Good morning. I just wanted to follow-up with your comments that you were looking forward to working with Shell on Athabasca, the Western Oil Sands acquisition going forward. Did you have access to them during the due diligence process?

No.

And one other question, in the -- you also commented that you were looking forward to closing or that it takes a couple of months perhaps before this transaction can close. Do you have to file and S4 to register the shares you are distributing?

Yes, we have to register SEC filing, yes.

Thank you very much.

That was Richard Horstman, assistant general counsel, if you didn't recognize the voice.

I appreciate that.

Ron Oster, A.G. Edwards.

I just had a quick follow-up on the production, new production guidance for this year. Does that also impact your year-end exit rate for the year? And if so, I would assume that that would bring down your '08 guidance excluding today's acquisition, if you could just please comment on that.

With Alpine it will have some amount of ramp up schedule. So it will mildly affect our exit ramp, but we would expect the facility in 2008 we're going to be bull and we would still expect that. So it has no real impact on our 2008 guidance.

Okay, great. Thanks.

And there are no further questions. At this time I would like to turn the call over back over to Ken Matheny for any closing or additional remarks.

No, we don't have any additional remarks. We would like to thank everybody for their participation. Gary Heminger who is not in this room after we disconnect this, would you please call back on this same line so we can have a follow-up discussion?

That does conclude today's conference. Thank you for your participation, and have a great day.