Marathon Oil Corp. Q2 2007 Earnings Call Transcript

Jul.31.07 | About: Marathon Oil (MRO)
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Marathon Oil Corp. (NYSE:MRO)

Q2 2007 Earnings Call

July 31, 2007 9:00 am ET

Executives

Kenneth L. Matheny - Vice President, Investor Relations and Public Affairs

Clarence P. Cazalot - President and Chief Executive Officer

Gary R. Heminger - Executive Vice President

Janet F. Clark - Executive Vice President and Chief Financial Officer

Philip G. Behrman - Senior Vice President, Worldwide Exploration

Steven B. Hinchman - Senior Vice President, Worldwide Production

David E. Roberts - Senior Vice President, Business Development

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Analysts

Doug Legatte – Citigroup

Doug Terreson – Morgan Stanley

Arjun Murti - Goldman Sachs

Neil McMahon - Sanford C. Bernstein & Co. LLC

Nicole Decker – Bear Sterns

Paul Cheng – Lehman Brothers

Dan Barcelo – Banc of America

Mark Gilman – The Benchmark Company

John Herrlin – Merrill Lynch

Eitan Berstein - Friedman, Billings, and Ramsey

Ronald Oster - A.G. Edwards

Katharine Lucas – J.P. Morgan

Jessica Resnick-Ault - Dow Jones Newswire

Katherine Seret - Scotia Capital

Bruce Lanni – A.G. Edwards & Sons, Inc.

Mark Flannery - Credit Suisse

Presentation

Operator

Good day everyone and welcome to this Marathon Oil Corporation second quarter Earnings Call. Today’s call is being recorded. For opening remarks and an introduction I would like to turn this call over to Mr. Ken Matheny, vice president of investor relations and public affairs. Please go ahead sir.

Kenneth L. Matheny

Thank you very much Brendan. I too would like to welcome everyone to Marathon Oil Corporation’s second quarter 2007 earnings web cast and teleconference. I am sure by now you have seen our press release announcing our acquisition of Western Oil Sands. 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 at 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 world wide exploration, Steve Hinchman, senior vice president of world wide productions, Dave Roberts, senior vice president of business development, and Garry L. 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 its annual report on form 10-K for the year end at December 31 2006. 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 adjust the 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 provides the quarterly and yearly data for 2006 and 2005 for means of comparison.

Adjusted net income for the second quarter of 2007 was up slightly from the $1.515 billion recorded in the second quarter of 2006.

Slide five shows it on a per share basis. Adjusted net income was up $0.17 or 8% from the year ago second quarter level and a $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 dollars.

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 of refining the 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, world wide sales volumes on our BLE basis were relatively flat in the second quarter 2007 as compared to the first quarter 2007, while the average realized price for BLE increased $2.13 quarter over quarter.

Moving to slide number ten, 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 nine mets top 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 (inaudible) differentials for golf coast sour and golf coast sweet grades were more than offset by a higher Wyoming asphalted discount.

The bid-weak 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 percentage of the Henry Hub first to month index price, decreased from the first quarter 2007 primarily due to weaker basis differentials per 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 a result of the lower volume. Domestic upstream income for barrel of oil equivalent increased $2.66 quarter over quarter reflecting those higher realized prices.

Moving to slide number 13, international upstream income for second quarter was essentially flat with the first quarter. Higher volumes and liquids prices along with higher income from our LPG plan 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 less than the increase in the price of dated Brent. International crude realization help perform dated Brent, primarily due to the timing of listings, however our reported NGL realizations have 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 the commencement of gas sales to the liquefied natural gas facility in Equatorial Guinea. Please remember that our LNG business is reported 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 BLE over the first quarter 2007 largely a result of the increase volume of lower cost natural gas production in Equatorial Guinea.

Moving to slide 16 in our downstream business, second quarter 2007 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 down stream’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 of most light sweet available to refiners in the U.S. Gulf Coast and in the Midwest. Because of this, we have switched to marker prices utilizing light Louisiana sweet or LLS as it’s commonly called. Crude oil prices which better represent the actual cost of light sweet crudes available in both the U.S. Gulf Coast and the Midwest. The LLS 6321 crack spread, on a two-thirds Chicago and a one-third U.S. 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 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 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 what the second quarter 2006 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 LSS prices, which on average actually decreased $1.41 per barrel quarter to quarter, resulted in a relatively higher charge in other blend stock costs, and would have resulted just based on the change in LLS prices quarter to quarter.

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

As shown on Slide 17, Speedway Super America, or SSA’s gasoline and distillate sales were up 12 million gallons, an increase of 1.5% quarter over quarter. SSA’s same store gasoline sales buyings were up 0.9% and same stores merchandise sales increased 3.4% in the second quarter 2006, 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 in 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 cargos 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 planned 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 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 capita 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 included approximately $510 million of debt serviced by United States deal.

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 to 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, delay in production from Alvheim/Vilje to the fourth quarter, results in our 2007 production forecast, now being 350,000-375,000 barrels of oil equivalent per day. Despite this delay, our strong portfolio development opportunities continue to underpin our 2006-2010 average production growth rate of 6-9% per year. I’ll now turn the call over to Clarence.

Clarence P. Cazalot

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 fullest extent possible.

In integrated gas, we completed commissioning of the Equatorial Guinea LNG facility, and made our fist 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 project in Norway. Due to commissioning delays, which Steve Hinchman outlined last quarter, we now expect first production to occur in the fourth quarter. As Ken just outlined, we’ve 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 6-9% production growth between 2006-2010, and again, this is an apples to apples comparison, and does not include an production from Western Oil Sands, which would simply be added to our production profile.

Let me turn to this acquisition. As you know, we have 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, U.S 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’ll find the forward looking statement associated with the following presentation. Moving to Slide 2, 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 multi-phase 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…

[Interviewer finds]. 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’re acquiring Western Oil Sands for a total consideration of about 6.5 billion Dollars Canadian, or 6.2 billion U.S. using the mid-day exchange rate and Marathon’s closing share price as of July 27th. It also includes Western Oil Sands’ debt of approximately $650 million U.S. at June 30. Western Oil Sands shareholders will receive approximately 3.8 billion Dollars Canadian in cash, and 34.3 million shares of Marathon common stock.

This acquisition will significantly increase our access to resource, providing 2 billion barrels of net resource from mined bitumen (inaudible), 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 nine years to 12 years, and increase our crude reserves by over a third to 1.7 billion barrels [of oil].

In addition to the mining and in-situ assets this deal encompasses, it also includes a 20% in the Scotford Upgrader, which creates additional value by processing the AOSP bitumen into higher values synthetic products. Currently, Western Share and the upstream operations of AOSP produces 31,000 barrels per day of mined bitumen, and as 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’d now like to have Gary Heminger share with you additional information on our planned integration of these assets, Gary.

Gary R. Heminger

Thank you Clarence. As we likely have many Western Oil Sands shareholders and analysts on the call, I’d 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 1 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, including the construction of a 28,000 barrel per day heavy oil poker, 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 upgraded capacity in Alberta.

Not only will this be at a substantially lower cost, as I just described, it will also provide higher value consumer products, such as gasoline and diesel, rather than synthetic crude oil, which, as Clarence already mentioned, will 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 the 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 form 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 U.S., 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 the integrated oil value chain with Western Oil Sands, and seeking the proper additional pipeline solutions needed. And with that, I’ll turn back over to Clarence.

Clarence P. Cazalot

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.

Kenneth L. Matheny

Okay, thank you very much Clarence. Brendan, we will now open the call to questions. I’d like to remind people to accommodate all who want to ask questions, we ask that you limit yourselves to one question plus a follow up. You may re-prompt for additional questions as time permits, and for the benefit of all listeners, we ask that you identify yourself and your affiliation. Go ahead Brendan.

Operator

Question and answer session will be conducted electronically. (Operator Instructions) And we will take our first question from Doug Leggate with Citigroup.

Doug Legatte – Citigroup

Good morning gentlemen, congratulations. Can you hear me okay?

Unidentified Company Representative

We got you Doug.

Doug Legatte – Citigroup

Great. 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 commitments you’ve made for share buybacks you’ve made as well this morning?

David E. Roberts

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

Doug Legatte – Citigroup

Sorry, is there a break up fee?

David E. Roberts

Yes sir, sorry I missed that Doug. There is a break up fee of Canadian 200 million.

David E. Roberts

Thanks.

Janet F. Clark

And Doug, to your question on debt levels, pro forma for this transaction net debt to total cap will be in the mid 20% range, 26 %, and I think it’s also important not to look just at book capital, but also on enterprise basis, our net debt to enterprise value is closer to 13%. And if you look at some other measure of credit capacity, debt to EBITDA performance of this transaction, without giving any credit for EBITDA from the transaction itself, is around 50%, or .5. So I think that we’re 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 to about $1 billion a year.

David E. Roberts

And that includes Detroit.

Janet F. Clark

Including Detroit Coker. Absolutely.

Doug Legatte – Citigroup

Great, thanks very much.

Operator

Our next question comes from Doug Terreson with Morgan Stanley.

Doug Terreson – Morgan Stanley

Good morning everybody. On Western, while the strategic rationale for the transaction is pretty clear, my Western 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 if you could quantify some of the financial benefits that you envisioned from integration of this transaction, that is, while the upstream benefits are pretty obvious from Western’s financial statements. 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.

Unidentified Company Representative

Ok Doug, I’ll tackle part of it and then Gary or Janet is really free to jump in. You know 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. I think in terms of describing any downstream benefit, you know, one of the great things about this is that 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.

While we refer to Detroit as the nearest term and the most likely solution we can see it indeed, as that refinery having the capability of handling the heavy synthetic and regiment net production coming out of the AOSP for us through about 24 teams. There is still a lot of optionality as Gary indicated. We can underwrite conditions, actually barge this crew to Garyville, which we have done this year when the economic, well not necessarily this crew, but the Canadian crew, when the conditions were right.

I am not prepared to give any returns or whatever, but the value creation I think is around a much lower cost that we can commercialize as that. 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 that they are upgrading and I will guarantee you that our costs are substantially less than that.

Doug Terreson – Morgan Stanley

Good point.

Unidentified Company Representative

And again I think that just the commercial value around what we can do moving these volumes to where we see the most value.

Doug Terreson – Morgan Stanley

Okay.

Unidentified Company Representative

I don’t know Gary, do you want to add anything to that?

Gary R. Heminger

That was perfect Mark?

Unidentified Company Representative

Thanks a lot guys.

Operator

And our next question comes from Arjun Murti with Goldman Sachs

Arjun Murti - Goldman Sachs

Thank you. I just want to clarify a few things. The phase one expansion for (inaudible) I believe goes to the Scotford Upgrader. Does the (inaudible) opportunities for the future phases?

Unidentified Company Representative

Well really Arjun, what comes out of the upgrader today is a variety of products. One of those products is actually an Albion heavy that we can begin taking at Detroit today. The volumes are around 25,000 barrels or something like that. There are volumes that can 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.

Arjun Murti - Goldman Sachs

Gotcha. And the 80,000 barrel opportunity, that probably is for future phases in terms of the Detroit coker?

Unidentified Company Representative

Ya, Detroit would come on stream, Gary?

Gary R. Heminger

Detroit would come on stream at the end of 2010 Argon. And our plan is, looking at what Western is producing today, in fact we can take some of those barrels today if need be into our system, but as we bring that covert op in 2010, the next expansion in 2012 time frame, we believe that Detroit will have the appetite for the heavy crews that come out of the next expansion well into the middle of the next decade before we need to consider any further solutions. We can C class those solutions down the road with the rest of our refiners.

Unidentified Company Representative

I would just add Arjun, it’s not just the refiners’ solutions, but by the middle of the decade we think the transportation solutions, particularly whether or not gold coast transportation has materialized or not, would be much more obvious and allow us the fact that it’s our decision making. Next question.

Operator

Question from Neil McMahon, with Sanford C. Bernstein & Co.

(Inaudible)

Neil McMahon - Sanford C. Bernstein & Co.

Maybe, just to follow up on your point there on the pipeline, where are you in getting capacity in new pipeline expansions both to take crews down to the Gulf Coast and to the Midwest, given the fact that now you now have got a good handle on what your output is from the oil plans back at the (inaudible) follow up section as well?

Unidentified Company Representative

Ok, Gary?

Gary R.Heminger

Yes, 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 is 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 markers. So we will be finalizing and formalizing those transportation options here over the next year as we go forward.

Looking at the options to the Gulf Coast, there are 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 Grayville if we were to elect to go over to that direction.

Neil McMahon - Sanford C. Bernstein & Co.

Ok, a follow up that is associated with the deal I suppose. Maybe coming from Phil Behrman or (inaudible) Why was the Curtis San oil opportunity not what would have been the package, obviously its not connected to the refining aspect, but I would have thought from an exploration point of view it was something of interest to the exploration team?

David E. Roberts

Ok Neil, this is Dave Roberts. I’ll take this one on. Marathon just took the view that we were very focused on creating an integrated batting solution through the oil sans. Again what we are focused on is what we do best and that is one of the things that have been a key strategic theme for us. So we were very focused on that. The (inaudible) that Western oil sans placed on (inaudible) was superior to what we could imagine. We think that we created the best commercial transaction by allowing them to see that value independently while we are going to focus on the maximum value solution for Marathon shareholders.

Neil McMahon - Sanford C. Bernstein & Co.

Great, thanks.

Operator

Our next question comes from Mark Flannery with Credit Suisse.

Mark Flannery - Credit Suisse

Yes, Hi. I would just like to clarify something on the expansion phases. Western oil sans does not participate in the upgrading expansion, is that correct? So after phase one, or from expansion one onwards you get the right to the (inaudible) is that right?

David E. Roberts

That’s absolutely correct Mark, that the parties have agreed through expansion one to upgrade the existing Scott ford upgrade, but with expansions two on, our parties are on their own as to how they commercialize their respected share.

Mark Flannery - Credit Suisse

Right, and my follow up I guess is, how are you feeling about the costs of expansion one and the operator should we say has not had a stellar record at controlling costs at this asset, so what are the current estimated costs of expansion, per flowing barrel if you’d like, and how comfortable are you that that’s how they are going to stay?

David E. Roberts

Well Mark, one of the things that was attractive about this transaction, quite frankly we are pleased to be partners with Shell and Chevron in the acrobat project. So from a perspective standpoint, your comment 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 recognizing (inaudible) pressures in the Alberta Province. So from that particular perspective we feel very good about the technical capability of Shell to deliver this project. Now on a gross basis, Shell has talked about U.S. 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 commitment and quite frankly, we think that those project costs are very comparable with what you’re seeing in space today, and we believe that we will be completely aligned with Shell in terms of managing those costs on a go-forth basis, so all in, we did a lot of diligence on this, we feel very good about the decisions that we’ve made, and quite frankly we’re looking forward to working with Shell in the future.

Operator

Thank you. Next we’ll hear from Nicole Decker with Bear Stearns.

Nicole Decker – Bear Sterns

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

David E. Roberts

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

Nicole Decker – Bear Sterns

Okay, and thank you. And just for my follow-up question, the resources or the reserves that you talk about, are those SCC reserves or are there some mining reserves in there as well?

David E. Roberts

No, I think we’ve tried to outline that which is mine able, so when we refer to the 436 million barrels of crude reserves, that is mine able, so those would not fall under our required oil and gas disclosure. So the mine ables would not fall under SEC guidelines, but ultimately, the in-situ, or SAGD, would. But right now, that’s resource, that’s not yet proven reserves.

Nicole Decker – Bear Sterns

Okay, I understand, thank you.

Operator

We’ll take our next question from Paul Cheng with Lehman Brothers.

Paul Cheng – Lehman Brothers

Hi guys. A couple of questions. Gary, you talked about the Detroit Plan. With this particular acquisition, does it change the outlook for Robinson and Catlettsburg?

Gary R. Heminger

With this, you know, we’ve always had Detroit, kind of in first position and doing our engineering work, and yes we have talked about Robinson and Catlettsburg in the past, and we will continue on, and we expect 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. Really coinciding with what Clarence mentioned, Patoka is going to become the new hub for, you know, Oil Sands in the U.S., and we’re 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, you know, competitive advantage on transportation costs, you know, probably a couple hour advantage over even the Chicago area, to be able to get crude into St. Paul. We’re looking at that on a smaller scale and as an option as well.

So lastly, the Catlettsburg. We’ve really stopped work for the time being on Catlettsburg, because of the substantial transportation costs. It’s about 400 miles, Paul, 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 PADD II, transportation options might open up down the road. As Clarence mentioned, that really helps us in the middle of next decade to determine what is the next best project to go forward with, and we think transportation options will really carry the day on that decision.

Paul Cheng – Lehman Brothers

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

Gary R. Heminger

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 the 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 2012-2013 or 2014 time frame, is kind of the window we’re looking at right now if that were to be a project we would consider.

Paul Cheng – Lehman Brothers

OK, and I just have a somewhat separate question. Clarence, just wondering, in this particular transaction, I mean, who approached who. Did you guys approach Western or did Western approach you? Can you describe the process a little bit more?

Clarence P. Cazalot

I don’t want to go into the particular details right 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.

Operator

Dan Barcelo, with Banc of America, your line is open.

Dan Barcelo – Banc of America

Yes, good morning, it’s Dan Barcelo with Banc of America. A question regarding upstream a little bit. If at the second quarter stage, if you could basically provide a little bit of an expiration update, and 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’s been very good at lower F&D, controlling production costs, good growth, expiration led, and I just wanted to know how, going forward, we as analysts and investors will look at Marathon’s upstream strategy. Does the Oil Sands growth basically preclude other growth you may look, and how you way those difference between current resources?

Philip G. Behrman

Dan, this is Phil Behrman. I’ll start with the exploration side. Present time in the Gulf of Mexico, of course, we finished all the Droshky work in second quarter. Plans in third quarter are to drill flathead well. We’ll 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’ll drill an appraisal well in our spuds discovery in the fourth quarter, starting in the fourth quarter. In Angola Block 31 we currently have one rig active and 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’ll lost 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.

Clarence P. Cazalot

Yeah, I guess Dan, I would only say that if you think about the Western acquisition you have 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’ve employed in the rest of the upstream. So you know, it’s a very low risk but steady level of reserve ads, over many years to come, that we’ll 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. But our upstream business will come into play, certainly around the in-situ assets, where it were the steam-assisted gravity drainage technology is an upstream technology. So we will certainly be setting those assets and determining what’s the best way for us to capture that. You know, 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’ll continue to grow through integration, and employing particularly gas commercialization technologies, whether it’s growing our LNG business, whether it’s gas to fuels, that I know Dave Roberts just 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. So it really is not a new component, it really was a component that we have built into our strategy for some time.

Dan Barcelo – Banc of America

OK, thanks very much.

Operator

And we’ll take the next question from Mark Gilman with Benchmark Company.

Mark Gilman – The Benchmark Company

Alright guys, good morning. 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.

Clarence P. Cazalot

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’d prefer to have that discussion with you after the transaction closes.

Mark Gilman – The Benchmark Company

Ok, by way of a follow-up, I assume all of the resource numbers that appear in the release and that you’ve quoted, Clarence, are on un-risked numbers for all categories?

Unidentified Company Representative

That’s true Mark, 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, you could reach out and touch these things, and so as Clarence has already said, there’s significantly less risk involved in terms of those recovered resources that we’re looking at in our numbers.

Unidentified Company Representative

The other point I would make, Mark, is that the production chart we’ve shown you, only carries through Expansion 5, ok, I think if you go out on the website for AOSP, I believe they actually carry, or talk about the other expansions. And we’ve not factored in anything for additional expansions, we’ve not factored in, as I’ve said before, into our analysis or into those production charts, anything for the SAGD resource. So you know, I think it is risked in terms of we’ve assessed those projects 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 of the resource, it’s a matter of controlling the cost, both the investment side and the operating cost side.

Mark Gilman – The Benchmark Company

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

Gary R. Heminger

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

Operator

John Herrlin with Merrill Lynch

John Herrlin – Merrill Lynch

Yeah, hi, couple quick ones. One, when would you expect to book SAGD reserves? Two, I think Janet said you’d be spending combined upstream and downstream on Western Oil Sands about 900 million to a billion a year. What about on just the upstream side?

Unidentified Company Representative

OK, John, I’ll take the first question. It’s premature for us to speculate when we would book them, there’s evaluation 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. Janet?

Janet F. Clark

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

John Herrlin – Merrill Lynch

OK, last one for me is Phil, you didn’t mention anything on the Balkans and Peons. Is anything going on there that’s new and different?

Steven B. Hinchman

Hi John, this is Steve Hinchman, I’ll take that. You know the Peons we’re just getting started. In fact we just have a rig now that just began to spud just a week ago, so we’re just getting really started, so there’s no update on the Peons. In the Balkans, we’ve roughly drilled about 18 wells, we’ve been evaluation 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’ll look to use that information to high grade our acreage position. We’re currently producing around 1,200-1,300 barrels a day net, and the response that we’re seeing on average up there is still pretty much within the expectation, around 300 barrel equivalent per day, 30 month average, and looking at a year, we’re still on the order of 300,000 barrels per well.

So no major surprises for us and we’re going to be moving from, in particular from an evaluation phase to a more aggressive in the acreage that we like.

Operator

As a reminder to our audience, you may press *1 to ask a question at this time. We will take our next question from Eitan Bernstein with Friedman, Billings, and Ramsey.

Eitan Berstein - Friedman, Billings, and Ramsey

Good morning, congratulations on a good quarter. Just a real quick follow-up I think it was to the first quarter, there’s a no-shop clause, but do the Athabasca partners have a right of first refusal on this deal?

Unidentified Company Representative

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

Eitan Berstein - Friedman, Billings, and Ramsey

Excellent, thank you very much.

Operator

We’ll take our next question from Ron Oster with A.G. Edwards.

Ronald Oster - A.G. Edwards

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

Unidentified Company Representative

I’m sorry, the change in asset mix?

Ron Oster - A.G. Edwards

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

Unidentified Company Representative

We’ll 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’re still looking at how this will get captured in our reporting.

Janet F. Clark

If you want to view it that way, it certainly would shift the balance more to the upstream than to the downstream.

Ronald Oster - A.G. Edwards

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

Janet F.Clark

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

Ronald Oster - A.G. Edwards

Can you refresh me on what those parameters are?

Janet F. Clark

Uh, I don’t think we’ve made those public.

Unidentified Company Representative

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

Operator

We will next hear from Katharine Lucas of J.P. Morgan.

Katharine Lucas – J.P. Morgan

Hi good morning. 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 the Scotford Upgrader or do you have an opportunity potentially to send that elsewhere if you’d choose to do so at a later date?

Unidentified Company Representative

All of 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.

Unidentified Company Representative

Do we have any more questions?

Operator

Follow up question from Neil McMahon with Sanford Bernstein.

Neil McMahon - Sanford C. Bernstein & Co

Hi, Neil McMahon from Bernstein. This is a question for Dave Roberts. Just wondering if there is if you could provide us with any idea of what you’d 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.

David E. Roberts

Good question Neil and I think the short answer is that this was not done on a comparable transaction and just trying to match up. What we tried to match up again was what we bring to the table and what Gary’s talked about is the value of our downstream solution. What I’ve said repeatedly both publicly and privately in Calgary is we were not prepare to dilute our downstream advantage and what this transaction allowed us to do was to maintain that value to (inaudible) shareholders throughout the value chain. So we could bring various value on the upstream but there’s 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.

Unidentified Company Representative

And I would just say Neil, you know we have continually said as we have looked at integrated joint ventures that the difficulty we always face was ensuring that there was comparable valuations on the resource side with the downstream side and I think that’s 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 that 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’d say is a lot of the other deals that you’ve probably looked at in the past, people were buying resource that yet hadn’t been permeated or there were no definitive development plans for. This is an asset that’s up and running today, gone through all the initial startup and regulatory issues, is in an expansion mode and so to us is a much better valuation.

Neil McMahon - Sanford C. Bernstein & Co.

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

Unidentified Company Representative

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

Operator

And we’ll take our next question from Doug Leggate with Citigroup

Doug Leggate – Citigroup

Thank you. I wanted to change tack a little bit here because the focus obviously this morning (inaudible) 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 six. However, you haven’t talked much about Angola recently other than the stream of press releases on exploration success. In November last year you stated you had more than $250 million of resource but since then there’s been a number of discoveries. Could you give us an update where you see that resource number? How that potentially changes your conventional resource depth and the (inaudible) reserve life and any update on expected wells that are currently (inaudible) or you are expecting to announce at some point in the future.

Philip G. Behrman

Yeah Doug this is Phil Behrman. Just to give you a sense of it, in fact Steve Hinchman and I are a kind of tag team a little on it. We are not at this time prepared to update you on the overall resources that we have discovered in Angola but as you know we’ve got 24 discoveries in Angola on blocks 31 and block 32 and its split 15 discoveries on block 31, nine discoveries on block 32 that we’ve announced to date. We’re continuing to drill as I’ve noted, with two rigs running on the two blocks, one on each block. In addition to that we have two wells which are (inaudible) in that upon government and partner approval we’ll continue to make more announcements. On the development side we’re moving forward as we told you towards year end with sanctioning our first project which is the Angola block 31 northeast area. That feed is completed and our expectation is by year end roughly we’ll have that sanctioned. Of course we book more reserves until we’ve sanctioned the project.

We have other developments which are undergoing really about eighteen months, maybe two years behind that which is the little area of block 31, southeast area of block 31 as well as our block 32, what we call our east central area. And so we are continuing to drill wells, add resources to these potential areas, but they’ll be roughly eighteen to twenty four months behind that in terms of sequencing these developments.

Doug Leggate – Citigroup

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

Philip G. Behrman

I think the easiest way to look at this is we create a lot 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 our exit summaries. That’s all simply options that we create but we’ve created that value once we’ve found it and we’ll certainly move forward with more value creation as we reduce (inaudible) certainly with the development. So indeed those are all the options which we could consider.

Doug Leggate – Citigroup

Thanks

Operator

And our next question comes from Jessica Resnick-Ault with Dow Jones Newswire

Jessica Resnick-Ault - Dow Jones Newswire

Hi, this is Jessica Resnick-Ault with Dow Jones Newswires. I’m interested in going back to some of the transportation questions for Canadian crude that are posed by this acquisition and in particular interested in the previously proposed Alberta Texas high speed pipeline. I’m trying to figure out whether that plan could be shifted to run toward Louisiana toward the Garyville oil refinery as I know from Marathon executives that previously suggested and I’m wondering if there’s been any move toward changing the pattern of that pipeline or of any other proposed projects to accommodate Garyville.

Gary R. Heminger

Jessica, this is Gary. As we are, I think I visited with you back earlier 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 did 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’s substantial amount of discretion going on about the tremendous demand up and down the whole US Gulf Coast. So I just say stay tuned and as we continue and now that we have made this transaction public we’ll be able to work closer with the pipeline companies to determine the future routes.

Jessica Resnick-Ault - Dow Jones Newswire

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

Gary R. Heminger

You’re very welcome

Operator

This question is a follow up from Mark Gilman with The Benchmark Company

Mark Gilman – The Benchmark Company

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

Gary R. Heminger

No, that would be on the incremental as we’ve said in our remarks we expect to run it incrementally. 80,000 barrels a day of heavy crude and that’s a very good question you know Mark that’s sometimes a difficult benchmark to use. You really have to add in all the downstream process units. So that would include the coker, the hydro treating work, the expansion of the crude unit, that would improve all of that cost in order that we could run it incremental at 80,000 barrels a day heavy crude.

Mark Gilman – The Benchmark Company

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

Gary R. Heminger

On the incremental piece, yes.

Mark Gilman – The Benchmark Company

Ok, and to just check my arithmetic on something. I’m coming up with annualized second quarter western cash flow in the neighborhood of $300 million which would make this a better a deal at about twenty times the second quarter cash flow. Am I in the right ball park?

Clarence P. Cazalot

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.

Mark Gilman – The Benchmark Company

Ok, Thanks Clarence.

Operator

The next call is from [Katherine Seret] with Scotia Capital

Katherine Seret - Scotia Capital

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

Unidentified Company Representative

No

Katherine Seret - Scotia Capital

And the other question, you also commented that you were looking forward to closing but it takes a couple of months before this transaction can close. Do they have to file an F4 to register the share issue distributing?

Unidentified Company Representative

We have to register an SEC filing yes.

Katherine Seret - Scotia Capital

Ok, thank you very much.

Operator

Bruce Lanni with A.G. Edwards

Bruce Lanni – A.G. Edwards & Sons, Inc.

I just have a quick follow up on the new production guidance for this year. Does that also impact your year end asset rates for the year and if so I would assume that would bring down your ’08 guidance excluding today’s acquisition? If you could just please comment on that.

Unidentified Company Representative

With our time it will have some amount of lap up schedules so it will mildly affect our exist ramp but we have expected the facility in 2008 we are going to be forward (inaudible) so accept that has no real impact on our 2008 guidance.

Bruce Lanni – A.G. Edwards & Sons, Inc.

Ok, great, thanks.

Operator

And there are no further questions at this time. I would like to turn this call back over to Mr. Ken Matheny for ay concluding or additional remarks.

Kenneth L. Matheny

No, we don’t have any additional remarks. We’d like to thank everybody for their participation.

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