馬拉松石油 (MRO) 2007 Q3 法說會逐字稿

Good day, and welcome to Marathon Oil's third quarter earnings conference call. As a reminder, today's call is being recorded. For opening remarks and introduction I would like to turn the conference over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you very much, Erica. I, too, would like to welcome everybody to Marathon Oil Corporation's third quarter 2007 earnings webcast and conference call as a reminder for the telephone participants, you can find a synchronized slides that accompany this call on our website, www.Marathon.com. With us on the call today are Clarence Cazalot, President and CEO, Janet Clark, Executive Vice President and CFO, Gary Heminger, Marathon Executive Vice President and President of our Refining, Marketing and Transportation Organization, Phil Behrman, Senior Vice President of Worldwide Exploration, Steve Hinchman, Senior Vice President of Worldwide Production, and Gary Piper, Senior Vice President of Finance and Commercial Services for our downstream.

Slide 2 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 Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-Q 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.

Now turning to slide number 3, net income for the third quarter was $1 billion versus $1.6 billion in the third quarter 2006. This slide also provides a reconciliation of net income to adjusted net income by quarter for the last three years. The bar graphs on slide 4 show the quarterly net income adjusted for special items for the third quarter, which is just over $1 billion, down $528 million in the third quarter of 2006, and for ease of comparison, this slide also provides the quarterly and yearly data for 2006 and 2005. Slide 5 shows that on a per share basis, adjusted net income was down $0.67, or 31% from the year-ago third quarter level, and $0.77 per share, or 34% below the second quarter 2007. Because the Western acquisition was pending during the third quarter, there were minimal share purchases during the quarter.

Moving to slide number 6, the year-over-year decrease in third quarter net income adjusted for special items was largely a result of a lower refining and wholesale marketing gross margin, partially offset by lower income taxes. We move on to slide number 7, adjusted ne income for the third quarter 2007 was $532 million lower than the second quarter 2007, and this decrease was also primarily a result of a lower refining and wholesale marketing gross margin, again, partially offset by lower income taxes. Turning to slide number 8, upstream segment income for the third quarter increased $79 million over the second quarter 2007. This increase was the result of higher natural gas sales volumes and higher liquid hydrocarbon sales prices, partially offset by higher income taxes. Lower revenue associated with storage volumes in Ireland and higher operating costs primarily related to workovers in the Gulf of Mexico, United Kingdom and Gabon.

As shown on slide number 9, worldwide sales volumes on a barrel of oil equivalent basis increased 33,000 barrels of oil equivalent per day in the third quarter of 2007 as compared to the second quarter 2007 and the average realized price barrel oil equivalent increased $0.97 quarter over quarter. Moving on to slide number 10, domestic upstream income decreased $26 million in the second quarter, largely a result of slightly higher operating costs associated with the previously mentioned workovers in the Gulf of Mexico. As shown on slide number 11, the NYMEX price per WTI crude was up $10.13 per barrel from the second quarter, while our average domestic realized liquid hydrocarbon price was up $8.34. Our lower realizations compared to the NYMEX were primarily the result of weaker differentials for Gulf Coast and Wyoming crude streams, as well as NGL price realizations, which did not keep pace with the WTI increase. The big week natural gas price was down $1.39 per million BTUs from the second quarter, while our domestic natural gas realizations were down $1.02 per Mcf, our lower 48 realizations were down $1.13 per Mcf, primarily reflecting the relative positive movement of differentials to Henry Hub quarter on quarter.

Turning to slide number 12, third quarter domestic upstream expense, excluding exploration expense was $1.64 per BOE higher in the second quarter, primarily as a result of the higher workover expenses already discussed. Domestic upstream income per barrel of oil equivalent decreased $2.08 quarter over quarter. Moving to slide 13, international upstream income for the third quarter increased $105 million over the second quarter, as a result of higher volumes and higher realized prices, which were partially offset by higher income taxes, lower revenue associated with storage volumes in Ireland, higher operating costs, primarily from workovers in the United Kingdom and Gabon and increased DD&A due to higher EG gas sales to the LNG plant.

As shown on Slide 14, our international liquids realizations increased approximately $9.35 per barrel, while Dated Brent increased only $5.99 per barrel. This outperformance compared to Dated Brent was primarily due to higher market premiums for our light sweet sales, as well as the timing of liftings. The increase in the international natural gas realization as compared to the second quarter was a result of higher volumes and higher realized prices in Europe. These gains were partially offset by much higher gas volumes to our LNG facility in Equatorial Guinea during the third quarter, which was its first full quarter of operation. Please remember that our LNG business is reported through the integrated gas segment, so there is an additional uplift in value realized by this facility that is not reported through our upstream business.

Turning to slide 15, third quarter international upstream expense excluding exploration expense decreased $0.90 per barrel of oil equivalent over the second quarter 2007, largely a result of the higher volume of natural gas production in EG. Total income per barrel of oil equivalent increased $2.97 to $15.65, primarily due to the higher realizations.

Now, moving on to our downstream business in slide 16, third quarter 2007 segment income totaled $482 million compared to just over $1 billion earned in the same quarter last year. Because of the seasonality of the downstream business, I will compare our third quarter 2007 results against the same quarter of 2006. The most significant factor contributing downstream's lower segment income quarter over quarter was that the price of crude oil rose significantly during the third quarter 2007, while in the third quarter 2006, prices fell substantially. This was the primary reason our crude oil and other feed stock acquisition costs increased substantially more, and the change in the average price of LLS during the September 2007 quarter compared to the September 2006 quarter would indicate.

Due to these escalating prices in the third quarter of 2007, we took a charge for crude and feed stock derivative activity. This charge wasn't completely offset by changes in the value of the underlying crude and fee stock inventories and purchases. The opposite effect occurred in the third quarter 2006, when prices declined during the quarter, and we recorded a gain on crude and feedstock derivative activity. In addition, the average sweet sour differential narrowed about $2 a barrel between the periods, which also negatively impacted earnings and finally, we ran a sweeter crude oil slate in the third quarter 2007 compared to the third quarter 2006, which also increased our crude acquisition costs quarter to quarter.

In addition to the increased cost of crude and feed stocks, the increase in our wholesale sales price realizations per gallon during the third quarter 2007 over the comparable prior year period was less than the increase in the average spot market prices for the products that are used in the LLS 6321 calculation. In addition to the derivative effects I just discussed in the third quarter 2007, we had a small derivative loss related to ethanol versus a large derivative gain in the third quarter 2006. This swing was primarily due to the fact that during the third quarter 2006, we had a number of derivative contracts in place to hedge long-term ethanol purchase contracts. When prices fell in the third quarter 2006, the derivatives contracts increased in value, generating a positive income effect without any offsetting effect from the physical ethanol purchase contracts during this same quarter.

In total, Marathon's refining and wholesale marketing gross margin included derivative losses of $360 million in the third quarter of 2007 compared to derivative gains of $384 million in the third quarter of 2006. Since we have elected not to use hedge accounting for our downstream, all of our derivative activities are required to be marked to market by FAS 133. Therefore, the derivative change reflects both the realized effects of derivatives, as well as the unrealized effect of marking open derivative positions to market. In addition, derivatives used in non-trading activities have an underlying physical commodity transaction. However, the income effect related to the derivatives, and income effect related to the underlying physical transactions may not necessarily be recognized in net income in the same period.

Downstream segment also incurred higher costs in the third quarter 2007 compared to the same quarter last year, primarily because of higher planned turnaround expenses. In the third quarter 2007, the crude oil in transit effect was a negative $30 million versus a positive of $53 million in the same quarter last year. Partially offsetting these negative results was the fact that the Chicago crack spread in particular was much stronger in the third quarter 2007 than it was in the same quarter last year. The LLS 6321 crack spread on a two-thirds Chicago and one third U.S. Gulf Coast basis increased from $7.15 in the third quarter 2006 to $9.01 in the third quarter of 2007.

Our refineries operated well last quarter. Crude oil throughputs improved from 1.031 million barrels per day in the third quarter of 2006 to 1.042 million barrels per day in the third quarter of 2007. However, planned turnarounds under way at the end of the third quarter at our Catlettsburg, Kentucky and St. Paul Park, Minnesota refineries reduced our average third quarter 2006 total crude and other charge and planned stock inputs to 1.241 million barrels per day compared to 1.249 million barrels per day in the same quarter last year. 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.

As shown on slide 17, Speedway SuperAmerica's gasoline and distillate sales were up 25 million gallons, an increase of 2.9% quarter over quarter. Speedway SuperAmerica same-store gasoline sales volumes were up 1.9%. The same-store merchandise sales increased 2.6% in the third quarter 2007 compared to the same quarter of 2006. And last, Speedway SuperAmerica's gross margin for gasoline and distillate was $0.1103 per gallon compared to $0.141 per gallon in the same quarter last year.

Slide 18 provides a summary of segment data, along with a reconciliation to net income. Of note is the integrated gas segment, which had income of $52 million during the third quarter 2007 compared to $12 million in the second quarter. The increase in earnings is primarily attributable to the fact that the third quarter was the first full quarter of operations for the EG LNG production facility, which commenced primary operations in May of 2007. Slide 19 provides selected preliminary balance sheet and cash flow data. Cash adjusted debt to total capital at the end of the third quarter was approximately 11%. As a reminder, the cash adjusted debt balance includes approximately $508 million of debt, serviced by U.S. Steel. Year to date preliminary cash flow from operations was approximately $3 billion, and preliminary cash flow from operations before working capital changes was approximately $4.6 billion.

Slide 20 provides the guidance for the fourth quarter and for the full year 2007. Now, before I turn the call over to Clarence, there are a few additional comments I would like to make. This will be my last conference call with investors, as I have decided to retire at the end of the year after more than 30 years with Marathon. More than seven of those years have been spent working with investors. Nearly 40 conference calls, hundreds of meetings and literally thousands of telephone calls. While I am looking forward to retirement, I will be remiss if I did not say how much I've enjoyed the time spent with all of you. You have challenged me with questions and I have benefited from your knowledge and your insights. You kept me on my toes, and I think it's safe to say I've gained more from the experience than you. I will miss the challenge, but most of all, I will miss the relationships and the opportunity to talk with you on a regular basis.

But this is really a good news story. The timing is right. Marathon is positioned with a management team, employees and an asset base that's as good as any I have seen in my 30-year career. The good news for me is that I'm healthy and will have time to do most anything my family wants me to do. The good news for all of you is that Howard Thill will replace me. Many of you know Howard very well and recognize that he is more than qualified for the job. Howard, along with Michol Ecklund and Bonnie Chisholm will be here to meet all of your investor needs. And I can guarantee Investor Relations at Marathon will not miss a beat. In fact, the beat will probably step up a notch. So for the last time, my thanks to all of you. It's been a great ride.

Now I'll turn the call over to Clarence.

Ken, thank you so much. We still got two more months to ask you questions and challenge you a bit. I, on behalf of the company, want to thank you again. Ken, as you all know, has made tremendous contributions to Marathon for over 30 years and certainly from my standpoint, having worked with him for the last six years, you know what a gentleman he is, a man of great integrity, and he's been a great source of advice and guidance for me personally. I want to wish Ken and Peg all the best as they take on new challenges and to congratulate Howard on the job, and we look forward to working with Howard as well.

As Ken pointed out in the third quarter, our upstream business benefited from the increase in crude oil prices, while it was a challenging environment for our downstream sectors, as margins were compressed by increased crude costs. This certainly points out the volatility in our business, but also the advantage of being a strong integrated company. Despite this near-term volatility, we continue to invest in profitable, long-term growth opportunities and I think as you all recognize, our clear intent is to create long-term value through fully integrated solutions, such as the potential linkage of our recently acquired interest in the Canadian oil sands with our best in class U.S. refining and marketing assets.

And as you recognize, we just announced yesterday approval of our Detroit refinery upgrade and expansion project. When completed in 2010, this refinery project will allow us to process an additional 80,000 barrels of heavy oil and unlock additional value from our oil sands assets. And I know there's a great expectation out there about what the precise downstream value proposition is. Gary Heminger will outline for you in an illustrated fashion in just a few moments the value proposition we see using a reasonable set of assumptions.

But before Gary does that, I would like Steve Hinchman to give you an update on our production business. Steve?

Thank you. Our upstream segment had strong operational performance in the third quarter, including our new LNG facility in Equatorial Guinea, which achieved an average utilization rate of 93% of design capacity. Unfortunately on October 4 we discovered a small leak in a 2-inch drain line within the refrigeration unit requiring a full shut-in of the plant. The leak has been isolated and repairs are under way. The plant should be back online and manufacturing LNG within the next couple of weeks. This outage will impact our annualized production volumes by about 7500 barrels of oil equivalent per day, as reflected in the fourth quarter guidance.

In [Moline] FBSO construction has been completed and commissioning, although taking longer than we expected, is now nearly complete. We expect a sale out of the Augustine shipyard by mid December. We'll stop in [Annafalord], which is near [Safounder], to install the thrusters and commission the fire water and seawater pumps before sailing to location. First production is expected in the first quarter. This depends on having a weather window conducive to safely linking the vessel to the loading buoy. Our production for the year will fall within the prior guidance, 350,000 to 375,000 barrels of oil equivalent per day, but near the low end, attributable to these two events. Now, Gary Heminger will make his additional comments.

Thanks, Steve. As Clarence mentioned, we closed the Western transaction on October 18, 2007, and yesterday, we announced the approval of the Detroit upgrade and expansion project. But before I get into the linkage between these projects and the value proposition for Marathon, I would like to welcome Steve Reynish and his team to Marathon. We are excited not only to have the Western assets, but we are also pleased to have been able to retain the highly talented staff, which Steve will lead as President of Marathon Oil Canada. Steve most recently was the Executive Vice President and Chief Operating Officer of Western, and prior to that was the President and Chief Operating Officer of Albion Sands Energy, which operates the Muskeg River Mine on behalf of the Athabasca oil sands project owners. Steve and his team bring valuable knowledge to the operation of the business.

To help investors, analysts and other interested parties better understand our value proposition, we have prepared the following slides to compare our project with that of a typical Alberta upgrader. I want to emphasize that this example provides an illustrative case of the preliminary value proposition and hopefully you will recognize that we have a long way to go with the commercial negotiations around areas such as transportation and diluent, so this analysis is not intended as a reflection of our economic case for the project.

Slide 22 provides the relevant assumptions used in the rest of this presentation. While I won't go over these individually, I felt it important that you see what the basis for this illustrative case are and that they are reasonable and not based on the much higher crude prices we've seen recently, or the higher crack spreads refiners had this past summer. Moving on, slide 23 illustrates the typical value chain moving from bitumen to refined products, using the previously outlined price assumptions. This slide reflects the three value chain options to a Canadian heavy oil producer, selling Dilbit, upgrading to a synthetic crude oil, or gaining access to a refinery with heavy oil capability. As shown here and as further demonstrated in the following slides, the Midwest refinery option clearly provides the highest value.

Moving to slide 24 and using the value chain just demonstrated, the value of linking our AOSV production with our Detroit refinery is further demonstrated. This slide reflects the margin value of a Midwest refinery, heavy oil upgrading solution on a Benjamin basis. Starting with the 70/30 blend, or one barrel of bitumen and 0.43 barrels of diluents, and using the previously stated price assumptions, adding $10 per barrel for transportation refinery expenses, this refinery feed stock of 1.43 barrels is then converted into finished products valued at approximately $94.60. The result of this value chain is a margin of $21.74 per barrel of bitumen.

Slide 25 reflects the margin value calculation of the typical Alberta upgrader. This option also starts with one barrel of bitumen, but the diluent is recycled to the mine for repeated blending purposes. Other blend stocks of approximately 0.21 barrels are necessary to optimize the upgrader option. It is estimated that total costs, including fee stocks and blend stocks, transportation, operating expense and overhead are approximately $13.61 per barrel of bitumen. The resulting blend of products reflects a yield of approximately 103% as a result of the expansion that occurs during upgrading of the bitumen barrel. Product output of the upgrader consists of a mix of premium synthetic crude oil, vacuum gas oil, and heavy synthetic crude oil, which yields $63.44 of revenue for every barrel of bitumen processed, resulting in an operating margin of $19.54 per barrel of bitumen.

Slide 26 with a side by side comparison illustrates the total value advantage of a Midwest refinery heavy upgrade oil solution, compared to an Alberta upgrader using the stated assumptions. As illustrated on the previous slides, there's an operating margin advantage of approximately $2.20 per barrel. In addition, as shown here, we estimate there's an additional value of approximately $1.25 per bitumen barrel, when taking capital costs into consideration. This calculation imputes a market value for base refinery to truly reflect comparable costs.

In total, we believe Marathon's integrated solution has approximately a $3.50 per barrel, per bitumen barrel competitive advantage to upgrading at the field level. And with this solution, we are supplying refined product directly to a market that currently has excess demand. And of course we are still in the early days of our Canadian oil sands project and we will continue to explore our options for gaining value from this asset. We continue to look at other potential long-term refining solutions within our network, and we look forward to working with our partners on the promising future of the AOSV project, including discussions about technology opportunities, and options for optimizing the value of the current upgrader.

Let me finish by taking a few minutes to remark on the Alberta royalty changes outlined and Premier Stelmach's address last week. While we would have preferred that there would have been limited changes to the royalty regime, we believe there is minimal effect based on the pricing assumptions we used. It is disappointing the royalty will graduate with oil prices and that may limit upside and future capital spending. We will obviously continue to study and follow the open items still being discussed in the province pertaining to bitumen upgrading. We are confident Marathon will deliver a superior competitive solution to the integration of the oil sands with our refining system. We will update you as we continue down this path of integration.

Now I'll turn the call back to Kenneth.

Okay. Thank you very much, Gary. Erica, we will now open the call to questions. I would like to remind you to accommodate all those 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. For the benefit of all listeners, we ask that you identify yourself and your affiliations.

(OPERATOR INSTRUCTIONS) We'll hear first from Doug Terreson with Morgan Stanley.

Good afternoon, everyone, and congratulations, Ken. My question might be for Gary or maybe Clarence, and it involves the refining and marketing business and specifically the expansion that was announced yesterday, in that the strategic benefits of the expansion obviously are pretty clear, but on the financial side, I wanted to see whether or not there were any local or state tax incentives or advantages that might enhance economics of that project and if you could talk about them, could you tell us what they are?

Gary?

Sure. Yes, Doug, we have spent a lot of time working with the City of Detroit and the Michigan economic development committee and we have been very fortunate to have received approximately just north of $150 million net present value in tax advantages in this project.

Okay, thanks a lot. That covers my question.

Next we'll hear from Doug Leggate with CitiGroup.

Thanks. Congratulations, Ken and Howard.

Thank you.

I've got a couple, if I may. I'll take one and my follow-up. The first one is on ethanol. You guys are a very large blender of ethanol. Prices are at a pretty hefty discount right now. Can you help us understand how that impacts your -- I guess your earnings on the downstream outside of just the indicated crack spread that we see on the screen and maybe the outlook as your blending capacity goes up into 2008.

Yes, this is Gary Peiffer. Obviously as you stated, the current spot market prices are very attractive versus the gasoline prices. I think, as we mentioned though, at least from our particular perspective, as we mentioned last year in the third quarter, we've been able to negotiate back starting in '05 some pretty attractive contracts when the prices were relatively low for ethanol. So when you look at our specific results for us, it's had a big positive effect, but, but some of it has been muted by the fact that we had some long-term contracts we're comparing ourselves to last year same quarter. Also last year in the third quarter, as we mentioned last year, we had some -- and as Ken mentioned, we had a very positive derivative effects from some of the long-term contracts we entered into, so I guess if you look quarter to quarter, and you strip out the derivatives effects, we were pretty flat quarter to quarter in terms of our results from all the ethanol blending we've done, so, again, part of it due to the fact we were very fortunate to have some very good long-term contracts in the third quarter of last year, and we've been taken advantage on a spot basis more this year, and probably will be into the future. We have very little of our future ethanol demand, forecasted demand under contract at the moment, probably close to about 10%, so we'll be living off kind of spot differentials going forward. And probably won't have a lot of derivative activity because we don't have a lot of long-term contracts either going forward.

Gary, the [magnasheds] can you you kind of quantify, because if you look at spot versus gasoline right now -- spot ethanol versus gasoline, on a billion gallons a year, that could be quite a decent number, right?

Assuming that you get to keep the difference all for yourself and that you don't have to, which we do, discount those gallons to our marketers to have them sell it. Now, in the case of what we sell through Speedway SuperAmerica, you're definitely right. We do get to capture all that. But to the extent that we have to entice our jobber, our Marathon jobber customers, or our wholesale customers, a lot of those customers aren't inclined to go through the expense of cleaning their underground storage tanks and aren't inclined to only want to buy from one supplier, if we're the only supplier in the market.

They, like everyone else likes to have diversity of supply to ensure they have a competitive price. It's great to look at that differential that you just mentioned, but you also got to consider with a discount, especially in some markets like Illinois, where it's very competitive, we have to discount away a lot of that, that benefit, because everybody does it and everybody's giving the marketers, or trying to squeeze out a $0.01 or $0.02 of margin over and above what they would get on the gasoline. It's a big part of our business, you're right. But maybe not as big as you might expect, given the competitive pressures to sell ethanol.

And next we'll hear from Mark Flannery with Credit Suisse.

Thanks very much, and good luck, Ken. We're going to miss you.

Thank you.

And I hope Howard can keep ourselves in line there without your guiding hand. My question is to Gary Heminger on the Detroit project. Gary, how, how confident do you feel in the pricing, the capital pricing for this project, $1.9 billion is a reasonably large amount of money, but we've seen these kinds of numbers get a lot bigger, a lot, you know, a lot quicker than people expected, naming no names around the sector. So have you done a lot of detailed work there on how much the coker will cost today and not just sort of roll things forward from Garyville? Could you just--

Yes, Mark, we have. Just as we did the Garyville project, we've gone through a very detailed feed process and we have not hurried the feed. We have stayed right in line with Flor, who is our lead contractor and a very large team of Marathon engineering staff that, very similar to the way we did Garyville as we followed through the process. And then as we, we've tested the market in and around the Midwest, where we will pull the pipe fitters, laborers and welders to be able to do this work and like Garyville, we went out and procured some of the long lead equipment such as the coker some, of the heavy wall, vessels that are required, and some piping as well. So we feel very comfortable with where we sit on this project and we've also had a very renowned third party audit this, this number to make sure that we're comfortable as well.

I guess my follow-up there is, could you give us some idea of how much of the $1.9 billion will be equipment and sort of stuff and how much will be labor?

Let me break it down this way for you a little bit. About $150 million of the $1.9 billion will be pipeline and some off-site connections that we're going to have to make within the pipeline. So that leaves about $1.750 billion for the pipeline. Excuse me. I'm sorry, for the refinery project. The new construction versus the revamp is probably the best way to be able to answer that, Mark.

About $1.2 billion will be for new construction, which will be the vessels, piping, and pumps compressors, so forth. And about $600 million or so will be for revamp work. Revamp work, of course, will take more labor. I can get back to you. I do not have a, the breakdown of how many hours for each and I can have Howard get back to you at a later time, Mark.

That's great. That's good enough for now. Thank you very much.

All right.

Next we'll hear from Nicki Decker with Bear Stearns.

Good afternoon, Ken, congratulations, best wishes. Thanks for everything.

Thank you.

Just continuing on, on Detroit, Gary, you talked about the pipeline. Is this the pipeline that connects the refinery to the heavy crude infrastructure?

Yes, Nicki, the $150 million for total pipeline and off site, that would be from an area called Samaria, up to Detroit. So we will tie into Enbridge and Enbridge already has a pipe that comes down from Hardisty down and there, as you recall, they are going to expand from Superior, Wisconsin, down to Patoka and then they already have a line in place as well that we take crude into Detroit today that runs from the Patoka area up to an area called Stockbridge. So this incremental pipeline is for Marathon's piece is only for the 29 miles of pipe that we will work on from Samaria to Detroit.

Okay. That's helpful. And if I could slip one more in, would you just talk about where you are on your assessment of projects at St. Paul Park and Robinson?

Sure. Just completing this, this project feed, and in fact when you complete the feed check estimate, now we go in and have tremendous amount of procedural work to do on haz ops and further detailed design, that we still have a very high level team studying the opportunities in and around St. Paul and Robinson. I would say right now, Nicki, that they are still at a very high level feasibility stage and we have a lot to say grace over with the two major projects that we have ongoing right now.

Thank you.

And next we will hear from Neil McMahon with Sanford Bernstein.

Hi, good luck, Ken, and thanks for your help over the years.

Thanks, Neil.

I've just got one question. Really looking at production growth going into next year, this is how I'm going to make two questions out of it at least, just looking at the Libyan volumes in the third quarter, they have gone up over the first two quarters and not up to the sort of levels you got to last year, but could we see the level achieved in the third quarter as a good run rate going into 2007?

Yes Neil, are you talking just Libya, or are you talking in total?

I'm talking just, just Libya. They were down versus where they -- from where they were last year.

No, I think that's a good expectation, how we'll run into, into 2008 and with Libya. I'll remind you though, last year they were higher because we were actually making up for some historical underlift that we had as well. So if you remove that, we actually have had growth in our Libya production, primarily, primarily just a result of going in there and making the facilities a bit more efficient.

Sure, I appreciate that. That's why I was really looking at is the 50,000 a day sort of level the right level to be thinking about next year, relevant on a 40,000 a day, which has been the run rate in the first few quarters?

No, I think that's a fair, a fair estimate to make.

And just the second one, again, looking at the volumes, obviously you have mentioned that you hope to get EG back on through the middle of November, through the start of December. And also on Alfine, hopefully getting that up and running in the first quarter, which has been delayed. What's the wiggle room on those? Are you pretty confident that they are going to come in as you have outlined them?

Well, on the -- for the LNG train and EG, we're putting it back together now. So we feel very comfortable, there's always this time early in the operation of the new facility, there's always the potential for something else to crop up. So we think the wiggle room around EG startup is plus or minus two weeks or so from an operational standpoint. On Alfine, I think I feel pretty good about where we see our commissioning activity, remaining commission activity going and probably one of the biggest risks we have is that as we look to sail away in December and other locations in January there's a weather window there that's going to be the biggest risk factor. So it's just difficult to predict the weather, to give you a range on that uncertainty.

Okay, great.

Next we'll hear from John Herrlin with Merrill Lynch.

Yes, thank you. In the central gulf sale 205, you were third highest bidder, spent about $220 million. Could you give us a sense of where they were looking, one, at more miocene oriented projects versus lower tertiary, and when you expect to mature some of the prospects of the leases you got.

Yes, John, this is Phil Behrman. As you know, we won 27 blocks. The bulk of the blocks that we especially a high bid blocks were all miocene plays. We also had some of the lower tertiary, but the bulk of our activity and our leasing was in the miocene trend. As you know, we haven't been awarded the majority of these blocks, so it's difficult to pin down the time in drilling, but assuming within the next 90 days we get awarded the blocks, we would envision drilling in the 2009 to 2010 timeframe for some of these blocks. Some of them could be a little bit earlier. Some of them could be a little bit later. That's pretty much coincides fairly well with our rig contracting strategy, where we have rig capacity to go ahead and drill these opportunities.

Great, thank you.

Next we'll hear from Mark Gilman with the Benchmark Company.

Good afternoon, guys. Some things related to Western and the analysis in the packet if I could, please. First, give us an idea what kind of DD&A charge you're going to burden the income statement with, maybe it's a question for Janet.

Yes, Mark, this is Janet. As you know, purchase price allocation is something that takes a bit of time to complete. We're making good progress there, and I think that probably we're not going to get into any detail of accounting disclosure on that until we've completed that process.

Okay. Gary, in terms of the illustration that you went through, you chose a hydrogen upgrading technique. Would it be any different if you used [leg token]?

Well, yes, Mark, it certainly would, but what we used was what we see to be the most prevalent upgrading solutions going on and where we had, you know, the AOSV upgrading solution, we thought that was really the, the correct market barometer to compare against.

Next we will hear from Paul Cheng with Lehman Brothers.

Hi, good afternoon. Ken, just wanted to add my congratulations and thank you for all the years with the help.

Thank you, Paul.

I think two questions. One is for Steve, wondering if you can give us update about Bakken Shale given EOG has made some pretty optimistic comment on that.

I would be happy to. The Bakken Shale, we have roughly around 200,000 acres and of course most of this year we've really focused on evaluating our acreage. It's spread out across the basin. We drilled about 30 wells and as we look at the area that now we feel have development potential and are beginning to focus our efforts now into development, we have typically seen wells that have IPs over the first couple of days, of anywhere from 650 to 850 barrels of oil equivalent per day.

Now, what we typically report and what we've reported to you and what we report to the state are really 30-day averages, and these wells decline quite sharply and our 30-day average has been around 300 to 350 barrels of oil equivalent per day, which is pretty much in line with our expectations. So now through our evaluation process, we have a feel where we think the better parts of the Bakken are, so we're going through an effort now to look to optimize high grade our acreage position, as well as to go in now more aggressively and execute on development on the areas that we feel good about. So we're currently running six rigs. We've ramped up now to six rigs and we'll ll likely add two additional as we go into early next year. So we'll run at around eight rigs, pretty healthy pace.

Steve, what's production rate right now?

Production ought of the Bakken is a little over 2,000 barrels a day. Online.

Net to you or gross?

That would be net.

Thank you. Next question is for Gary. Gary, on ethanol blending, when are you guys going to start blending in the southeast Florida and Georgia?

Paul, we are -- in fact, we're already blending in some parts of the southeast. We are just finalizing with the state of Georgia, having just completed the state of Tennessee, on what the specs are in order to be able to meet the blending components. But we will finish by June of next year all of our terminals to have online blending in the southeast. So as I stated, we're already in Tennessee, Georgia. Cliff just joined me, are we in the Carolinas at all?

Yes, we have in Belton, South Carolina, we're blending today, and we have the facilities and the terminals in Florida. We're hopeful that maybe by the January 1, that Florida will adopt the same rules that Tennessee and Georgia have recently adopted on state gasoline specs, which would allow us to blend in Florida without putting a special grade of gasoline into that state.

(OPERATOR INSTRUCTIONS). We'll move next to Stephen Beck with Jefferies & Company.

Thank you. My question was just answered. Thank you.

And we will move next to Michael LaMotte with JPMorgan.

Thank you, good afternoon. I apologize if this question's been addressed. I did get on the call a little late. In the press release for Detroit, it mentioned 400,000 gallons per day of clean fuel capacity. I was wondering if you could address the flexibility that you're going to build into this system in terms of taking advantage of ULSD and gasoline variances and product.

Yes, Michael, and that question had not been asked. We will have the flexibility. We expect the incremental output to be very minor because this really is an upgrade project and very small expansion project, but we're expecting probably around 8000 barrels a day or so of gasoline, 3000 to 4000 barrels a day of distillate, but that still gives us a pretty good swing in asphalt. As we look through our numbers today, our modeling still suggests that asphalt is a good make in that market, but we still have flexibility to take further asphalt out of the market and run, run that through the coker and make additional distillate if the market requires that.

Okay. That's helpful. Thank you. And then just a follow-up, what kind of protections can you put in place to make sure that the throughout is not really disrupted during the expansion process? Are there increased risks of downtime?

Well, one of the things that we are doing is that we are going to time this project, and it is timed, to coincide with the big plant turnaround further down the road. So the -- we will have a, a moderate amount of revamped high end work that will be required, but we certainly have, have done a lot of revamp work in the past within our refineries and executed very well, but we'll take every precaution in that revamp work. We've acquired additional property, so that the coker, the DHT and the software complex are going to be built to the back of the refinery and on, on virgin soil, so we're going to have very little tie-in problems there.

And minimal loss time, okay. Then lastly, just sort of system-wide, where do you stand with, if you could provide an update on the benzene specs, where are you with respect to compliance and what that might mean for scheduled outages in '08 versus '07?

Right. We're just -- as you know, the MSAID rules were changed early -- well, they were changed and finalized. They were -- from where we have been expecting mobile source -- to be earlier in the year, then they were finalized I think end of the first quarter or so this year. So we are in the process right now of just starting to take these projects to feed and, Gary, do you know -- Gary might have the timeframe of over the next years on when we will have to do the work.

I believe we have to have it all completed by the end of 2010, 2011, so we haven't started any real fieldwork at this, as Gary said, we're just making sure we understand regulations and trying to cost out the, cost out the compliance costs. So at this point, we haven't done much in the way of any compliance work other than the engineering.

Okay. Great. Thank you, guys.

We have a follow he's up from Mark Gilman with benchmark company.

For one of the Garys, if I could. I know this is a confusing subject, but of the $360 million derivative figure cited in the release, does that include Gary Peiffer's prior comments regarding the ethanol piece, and how much of it was not offset in the third quarter by physical market effects?

Yes, Mark, this is Gary Peiffer. That would include the ethanol piece. I guess we have estimated that the physical effects, or the actual bottom line effect that was not offset by physicals was probably in the neighborhood of $100 million loss. You might recall last year third quarter we had kind of the opposite phenomena occur and at that time we said it was about $150 million positive. Well, this year we think quarter, third quarter '07 to third quarter '06 probably is about a negative 100 million.

Okay. Thanks. Gary Heminger, why the shift to sweet crudes late in the third quarter?

Just running all the LPs, Mark, and the way crude was priced, it gave us the best, best margin in our system.

Bottom of the barrel prices, Mark. This is Gary Peiffer. Were just not attractive, so we tried to maximize gasoline and distillate production to let the sweet-sour also gave us added incentive to go towards a sweeter slice.

Okay, guys. Thanks.

And next we have a follow-up from John Herrlin with Merrill Lynch.

Yes. An upstream question. Earlier you mentioned more workover costs both in Europe and then U.S. in the third quarter. Should we expect comparable ones in the fourth quarter, or was it just more seasonal activity?

Well, I think that in the U.S. and specifically in the Gulf of Mexico, it was failures and some interventions that we had to do, so we certainly wouldn't expect that to be repeated. In Europe, a lot of it was a focus on some workovers in our bray field which will add to production. Bray, year-over-year, nine months this year, nine months last year, we've really kept the decline relatively flat in Bray by going to lower pressure operations than by doing a more aggressive workover program in the field and it had some benefits for us.

Thanks.

And next we have a follow-up from Paul Cheng with Lehman Brothers.

Hi, real quick EG late end, is there any insurance claim associated with that, or is the contract still liable, or are you guys going to get the bill.

There's no insurance claim, but it is under warranty.

It's under warranty, so you do not have to pay?

That's correct.

There's -- there's no business interruption in insurance, that kind of thing, right?

Right.

Very good, thank you.

Won't be down long enough.

Okay. Thanks.

And we also have a follow-up from Mark Gilman.

Guys, do you have any idea what kind of percentage interest you might have in the second train at EG LNG given the way the supply alternatives were emerging? I assume it's going to be lower than the 60% from what I'm seeing.

Mark, I think it's too early to speculate on that, because, as you say, there is a long way to go in commercial negotiations, particularly on gas supply. And as you might imagine in an LNG project, particularly one that has to source, perhaps will source gas supplies from other international sources, it's important to have alignment. At this point, for us to speculate on what our ultimate interest is premature.

Okay. Thanks, Clarence.

We have no further questions in the queue. I would like to turn the conference back over to Mr. Matheny for additional or closing remarks.

Erica, thank you so much. We really don't have any additional closing remarks, so I thank everybody once again and next quarter.

That does conclude today's conference. We do thank you for your participation. Have a great day.