馬拉松石油 (MRO) 2006 Q4 法說會逐字稿

Good day, everyone, and welcome to this Marathon Oil Corporation fourth quarter and full-year 2006 earnings conference call. Today's call is being recorded. For opening remarks and introductions, I would like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you very much, Angie, and I too would like to welcome everybody to our fourth quarter conference call. As a reminder for the telephone participants, you can find the synchronized slides that accompany this call on our website at www.marathon.com. On the call today are Clarence Cazalot, he's President and CEO of Marathon. Janet Clark, Executive Vice President and Chief Financial Officer, Garry Heminger, Marathon Executive Vice President and President of our Refining Marketing Transportation organization, Steve Hinchman, Senior Vice President Worldwide Production, and Gary Pfeiffer, Senior Vice President of Finance and Commerical Services for our downstream organization.

Slide number two contains the forward-looking statements and other information related to this presentation. Our remarks and answers to questions today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included on its annual report on Form 10-K for the year-ended December 31, 2005 and subsequent forms 10-Q and 8-K, 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.

If you'll now turn to slide three, our net income for the fourth quarter was $1.1 billion verses $1.3 billion in the fourth quarter of 2005. Net income adjusted for special items for the fourth quarter was $838 million verses $1.3 billion in the fourth quarter of 2005. Moving to slide number four. Fourth quarter and adjusted net income per diluted share was $2.38 based on approximately 352.4 million weighted average diluted shares outstanding. Through January 31, 2007, we have repurchased approximately 23 million shares at a cost of just under $1.9 billion. We expect to complete our initial 2 billion share repurchase program this month. This program announced just one year ago was initially targeted to be completed in two years. As announced earlier this week, the board authorized an extension of the share repurchase program by an additional $500 million. We anticipate this extension of this share repurchase program will be completed during the first half of 2007. At the current share price in the high $80 range, we would expect to repurchase around 4 million shares during the first quarter, which would reduce the weighted average diluted share count to approximately $348 million for the first quarter.

Turning to slide number five, our full-year 2006 adjusted net income was $4.6 billion compared to $3.2 billion for 2005. On a per share basis, earnings were up $3.82 per share to $12.84 per share for the year. The increase in adjusted net income was the result of higher liquids prices and volumes, slightly offset by lower natural gas volumes and prices in the up stream and higher margins in our downstream, as well as full ownership of our downstream business for all of 2006. These were partially offset with over $2 billion in additional income taxes during 2006.

Moving to slide number six, the decrease in net income adjusted for special items of $491 million for the fourth quarter year-over-year was almost entirely a result of lower up stream natural gas prices and volumes, partially offset by higher liquids volumes and realized prices and lower margins in the downstream business. Moving to slide number seven, adjusted net income for the fourth quarter 2006 was approximately $700 million lower than the third quarter of 2006 -- pardon me make that 2005. Lower up stream liquids prices and sales volumes alone with lower margins and volumes in the downstream were somewhat offset by higher natural gas volumes and prices and lower income taxes. A reconciliation of net income adjusted for special items to net income is included on slides three. Please refer to slide two for a discussion of the use of this non-GAAP measure.

Moving to slide eight, upstream segment income for the year was up $116 million to $2 billion. The increase was a result of the higher liquids price realizations and sales volumes offset by slightly lower natural gas volumes and prices and more significantly offset by higher income taxes. Turning to slide number nine, up stream segment income for the fourth quarter was $307 million, down $265 million over the third quarter, largely a result of lower realized liquids prices and sales volumes as well as higher exploration expenses partially offset by higher natural gas sales and lower income taxes.

Turning to slide ten, the lower liquid sales volumes were mainly attributable to the third quarter lifting of approximately 2.8 million barrels in Libya that were owed to our account upon our return to operations. The higher gas sales were related to mainly higher seasonal sales in Europe. Moving to slide 11, domestic upstream income decreased $110 million for the full year. This decrease was largely a result of lower natural gas prices and volumes as well as higher exploration, DD&A and production expenses. These were partially offset by a positive impact from higher liquids prices and lower income taxes. Moving to slide 12, fourth quarter domestic upstream income was $167 million, a decrease of $51 million from the third quarter. The decrease was largely a result of lower liquids realizations as well as higher exploration expense reflecting the writeoff of the Blackwater well in the Gulf of Mexico, partially offset again by lower income taxes. As shown on slide number 13, domestic liquid realizations were down approximately $12 per barrel from the third quarter compared to $10.37 decrease in a NYMEX prompt WTI, reflecting a wider -- reflecting wider WT offsets for much of our domestic production. U.S. natural gas realizations in the quarter decreased from the third quarter, while the bid week natural gas price was essentially flat. Our lower realized natural gas prices were a result of deteriorating basis differentials for gas sold in the midcontinent and the Rockies.

Turning to slide 14, fourth quarter domestic upstream expense excluding exploration was $0.84 per barrel of oil equivalent or higher than the third quarter, primarily a result of higher DD&A expense. Domestic upstream income for barrel of oil equivalent decreased $3.59 per quarter-over-quarter, reflecting both the realized prices and higher expenses just discussed. Looking at domestic cost estimates for 2006, we expect field level costs to be in the range of $4.75 to $5.25 per barrel of oil equivalent. DD&A excluding FAS 144 impairments is anticipated to be between $9 and $10 per barrel of oil equivalent. And finally, other cash costs excluding exploration expense and production ad valorem taxes, which will vary based on price are estimated to be between $5 and $6 per barrel of oil equivalent.

Moving to slide number 15, full-year 2006 international upstream income of $1.1 billion was up $226 million verses the full year 2005, higher liquids volumes as well as positive price variances for liquids and natural gas were largely offset by higher income taxes. As illustrated on slide 16, international upstream income for the fourth quarter decreased $214 million from the third quarter to $140 million. This is mainly due to lower liquids volumes and realized prices, partially offset by higher natural gas volumes and realized prices as well as lower income taxes. The higher natural gas volumes and price realizations were a result of higher seasonal demand in Europe while the lower liquids volumes were largely a result of the previously discussed 2.8 million barrels of Libyan sales in the third quarter. Slide 17 shows that our decrease in international liquids realizations from $64.07 to $54.94 per barrel was in line with a $10 per barrel decrease in date of grant. And the $0.80 cents per MCF increase in our realized international natural gas price was largely a result of higher seasonal demand in Europe.

Turning to slide 18, international up stream expense excluding exploration expense increased approximately $1 per barrel of oil equivalent, largely a result of lower volumes and a change in production mix in the fourth quarter. International upstream income for the fourth quarter was down $11.20 to $7.79 per barrel of oil equivalent, largely a result of the lower realizations and higher costs just discussed. For 2007, our international cost estimates are as follows. Field level costs to be between $3 and $3.50 per barrel of oil equivalent. DD&A, again excluding FAS 144 impairments would be between $7 and $8 per barrel of oil equivalent. And other cash costs, excluding production taxes and foreign royalty, which will vary with price, at between $3.25 and $4.25 per barrel of oil equivalent. Total international up stream liquid sales volumes decreased to approximately 19% as a result of previously mentioned Libyan barrels lifted in the third quarter while natural gas sales increased approximately 79%, again primarily due to seasonality in the European market.

Moving on to our downstream business in slide 19. Full-year 2006 segment income was $2.8 billion compared to $1.6 billion in 2005. This increase was largely a result of more robust refining and wholesale marketing gross margins in 2006 when compared to 2005. And total refinery throughputs were up approximately 3% in 2006. Additionally, we owned 100% of the downstream for the entire year 2006 verses our 62% ownership during the first 6 months of 2005. Turning to slide number 20, downstream's fourth quarter 2006 segment income was $533 million, compared to $765 million in the fourth quarter 2005. Because of the seasonality and the downstream business, I will compare the fourth quarter 2006 results against the same quarter in 2005. The most significant factor contributing to the decrease in downstream's earnings from the fourth quarter 2005 to the fourth quarter 2006 was a decrease in the refining wholesale marketing gross margin driven by the decrease in the WTI 6321 crack spread in the fourth quarter of 2006 versus the fourth quarter of 2005. Additionally, refined product sales volumes were 8% lower in the fourth quarter 2006 as compared to the same period in 2005.

As shown on slide 21, the gross margin for gasoline and dist sales at Speedway Super America or SSA was $11.21 per gallon in the fourth quarter of 2006, down nearly $0.03 per gallon for the margin realized for the same period for 2005. Partially offsetting these lower margins and volumes for the downstream segment was a decrease in income taxes. Slide 22 provides a summary of segment data along with a reconciliation to net income. I will discuss three items of interest that are highlighted on that slide. First the integrated gas segment had a loss of $7 million during the fourth quarter of 2006 compared to a loss of $2 million in the third quarter. This was largely a result of the forgiveness of debt related to the restructuring of our contracts with Syntroleum. Second, unallocated administrative expense increased to $97 million, primarily a result of cost related to year-end accruals, mainly stock compensation expense. And third, net interest and financing income improved $37 million from the third quarter to $44 million, primarily due to favorable adjustments to interest on outstanding tax issues and foreign exchange gains of $6 million.

Slide 23 provides selected preliminary balance sheet and cash flow data, cash adjusted debt to total capital at year end was 6%, an improvement from approximately 11% at year-end 2005. As a reminder, the cash adjusted debt balance includes approximately $519 million debt of serviced by U.S. Steel. Year-to-date preliminary cash flow from operations was approximately $5.4 billion and preliminary cash flow from operations before working capital changes was approximately $5.9 billion. Slides 24 and 25 provide information from prior periods as well as guidance for the first quarter and full year of 2007. Before we take questions, I'd like to remind you that in the interest of fairness to all of those wishing to ask a question, please limit yourself to one question and a related follow-up. You may then reprompt if you have additional questions. Angie, you can now open the line to questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] And our first question today comes from Doug Terreson of Morgan Stanley.

Congratulations, guys, on another great year.

Thank you.

Thank you, Doug.

Yes. My question regards Equatorial Guinea and specifically the press release talks about that design work is underway for another phase of LNG over there and that if everything goes to plan an investment decision may unfold within the next year, maybe early '08. I know that this is preliminary, but it could be significant, obviously. And I wanted to find out if you have a preliminary time line for this plant and, meaning if construction commences next year as expected, when would you expect first production to materialize? and also I wanted to see if you had a preliminary expectation as to the most likely source of upstream production for that plant, and that you do have some, pretty attractive up stream assets in that area.

Yes, Doug, this is Clarence. I think as we said on the in the press release the feed work is ongoing now. We'd expect to complete that perhaps at the end of this quarter. We'd make a final investment decision in early '08 and that really is dependent upon us securing the gas supplies that we need for the plant. This will be a 4.4 million ton a year plant, a little larger than what we currently have in Train 1. And it's -- it will be the first plant LNG plant I think ever built based on international supplies. Because I think as we've said before, the gas supplies for this project will primarily come from Nigeria and perhaps Cameroon. There are additional gas supplies in EG. We're looking at those, as well. But those might well be better timed and better positioned to provide fill up for Train 1, as we've talked about.

Sure.

We certainly want to keep that train full for a very long period of time. So again, assuming we reach [FID] in early 2008, Doug, it would likely be the 2010, 2011 time frame. Frankly it's going to depend, as well on the nature of the gas we get. If it's already dry gas, we won't need to build some of the same kinds of condensate and other gas plants that we did in Phase II, whereas if it is wet gas, there'll be additional construction to be done. But obviously then there's a revenue stream associated with those liquids.

Sure. Okay, thanks a lot, Clarence.

Our next question is from Neil McMahon of Sanford Bernstein.

Hi. I was wondering if you could just draft the net income per barrel in the international operations in the fourth quarter. It seemed to take a bit of a nose dive from the third quarter. I'm just wondering if you could walk through, again what was behind that? and also I think, Ken you gave some guidance as to what we should be expecting in terms of running the costs into next year, year after that. Maybe if you could go through that, as well and I've got a follow-up on it too, thanks.

Steve, you want to start on that one?

Yes. No, I'd be happy to, Neil. From the third quarter of 2006 into the fourth quarter, probably, a significant was the liquid hydrocarbon price. It dropped roughly from $64 to $55 per barrel. We also had less volume. We actually produced more available for sale production primarily because of the seasonality of our European gas production. But we were relatively underlifted compared to the third quarter by almost 12,000 barrels. So we were around 6,000 barrels on a recorded sales basis, lower in the fourth quarter compared to the third quarter. We had some additional exploration expense. There was rate in the third quarter [Permento] , but then that was offset by withdrawals in Nova Scotia. And there's some other miscellaneous, mostly associated with our Alba plant in EG, had lower propane and butane prices compared -- fourth quarter compared to the third quarter. And we built some inventory in the fourth quarter relative to the third quarter. So those are the principal explanations for a lower income.

Just on -- so a lot of it could be down to the exploration expense getting back end loaded into the fourth quarter?

No, no I don't think it's due to any back loading. I mean the primary thing really is some price and volumes and the volumes are due to timing.

I've just got a quick follow-up on the international business. Have you been impacted by the OPEC quota cuts in Libya or told anything about them? And what should we be thinking about next year for Libya production?

Yes, we're thinking -- we have been impacted a bit. Libya is -- has restricted their production. It's being restricted on a pro rata basis. It's affecting us on a net basis in Libya probably roughly 2,000 to 3,000 barrels a day. And so our forecast for next year is roughly between 45 and 50,000 barrels a day coming out of Libya.

Great. Thanks.

Neil, one other point I'd throw out on fourth quarter up stream income after tax. We did have a fourth quarter true up on income tax. And if you look at the tax rate -- the effective tax rate -- for the upstream, it was significantly higher than what we've been running for the rest of the year. Because we've been a little bit low for the rest of the year. Had to make a catch up for the full prior 9 months in that one quarter. And that was primarily related to higher liftings in Libya than initially expected as we book taxes throughout the year.

So would the 77%, what's a good guidance, Janet, for next year then on international tax rate? Not 77%, I would presume?

No, I think that we've given guidance 46%, 48% overall. And we've given segment tax guidance?

I think maybe in the 60% range.

Okay. So sort of what it was like Q1-Q3 average?

Right that's a much better representation, Neil.

Okay.

We will now go to Paul Sankey of Deutsche Bank [OPERATOR INSTRUCTIONS] And hearing no response, we will now go to Kate Lucas of JP Morgan.

Hi, good afternoon.

Afternoon.

I have a quick question around Angola. There have been several announcements of late related to some successful wells. Including another one this week on block 31. What are you seeing as the timing for sanctioning of development projects in Angola in both blocks 31 and 32?

Steve, you want to touch on that?

Yes. On block 31, we're progressing in a northern area clustered development. We're in the midst of feed and we'd hope to sanction that project in 2007. In block 32, we're in, we're in feasibility and another cluster area development. And we'd expect that we would move to feed during 2007 with a sanction in 2008. We've got a number of additional feasibility studies going on on some of the other exploration discoveries, but we'll likely be in the 2008, 2009, time frame to progress those two through feed and into sanction.

I would also mention that, of course, we've got a rig drilling continuously in block 31 right now. We've got -- and will be there until almost mid 2008. We've got two rigs drilling in block 32 and they'll be there into the third quarter. And I think as our press release says, beyond the announced discoveries in our press release, there were 5 additional wells that have been drilled in Angola, we can't announce the results yet until we've got full partner and government approval. So we're completing the wells a lot faster than we can announce them with that high level of drilling activity. So we'll have, I believe in the end considerably more things to talk about than simply the projects of the developments that Steve just mentioned.

Okay. And if I could just follow up quickly on your CapEx announcement that came out indicated roughly -- it looked like roughly about $400 million for exploration expense in 2007. And it was, I think 14 to 17 significant exploration or appraisal wells. Can we assume that there's a good portion of those tilted toward Angola or would they be elsewhere?

Well, that's a very good assumption. Significant part of the drilling will be in Angola. And some drilling in the Gulf of Mexico and perhaps a well or two in Norway, but Angola will comprise the bulk of our drilling activity in 2007.

Okay, thanks very much.

We will now move on to Paul Chang of Lehman Brothers.

Good afternoon, guys.

Paul.

Quick one. I think if I can divide it into two separate. For Gary. Gary in the fourth quarter, did your ethanol contract that you purchased, is it -- the contract price is that below the spot price or above the spot price? and also how much is the contract that you [inaudible] that you guys do?

Paul, in the fourth quarter, the ethanol we purchased, some was at a contract price that we had bought earlier and some was spot, but it was below on the contractual side, it would have been below the spot price, and in the fourth quarter the percentage total that was on contract was probably in the 20-30% range of our total ethanol demand.

Gary, is the first quarter going to be still below the spot price or is going to be about the same or above?

Well, it depends on where the spot price goes, but --

Based on today's price, around $2?

But, you know, at today's price, we would be pretty much in line with where we were in the fourth quarter, below the spot price and still in that 20-30% range.

Okay, perfect. If I could ask Janet? If I look at the fourth quarter, across the divisions your effective tax rate by each division seems to be drastically different than the previous 9 months and it's not just for the international. I assume this is just a typical year end adjustment and doing catch up or is there anything unusual in the fourth quarter that leads to such a big valuation?

Well, Paul, you're right, it is the true up at the end of the year. As you know we look at effective tax rate for the year. And then as we get to the end of the year and find that some of our assumptions where we underestimated, particularly volumes for Libya that gets trued up in the fourth quarter. But in addition we did have an item related to our tax-based balance sheet exercise that we've been going through for the last year or two years that I think a lot of the companies are going through, and in fact, that resulted in about a $93 million effect to taxes to the positive. And then we did treat that as a special item because that won't effect going forward.

But I'm looking at the, I think the supplemental data that you give out. It says the effective tax rate for US [ENP] is 30% it's up 37% or 38% during the first 9 months. And how it then it drops to about 29%. Those I presume is excluding special items. Are those just normal year end or is that something that we should be aware?

No, that's related to the year-end true up.

Okay, very good, thank you.

At this time we have three questions remaining in the queue. [OPERATOR INSTRUCTIONS] We'll take our next question from Mark Gilman of the Benchmark Company.

Guys, good afternoon. I'm a little bit puzzled by the tax rate guidance full year '07, at least if I'm interpreting the back slide correctly. It would appear you're suggesting on an effective basis 46 to 48% for the year '07 that would be above the effective rate by my arithmetic for full-year '05. '07 will have, will not have the 2.8 million Libyan overlift. And therefor the [agress] mix effect there. It will also seemingly benefit from the Norwegian tax loss carried forward. Can you help me understand why the guidance is for a rate that's quite that high?

Well, the 46-48% compares to this year, effective tax rate of about 45% that did get the benefit of the $93 million tax basis balance sheet adjustment. We will get a benefit from Norway as we do have an NOL against that, but based on our business plan and looking at the mix of production and refining profits and LNG output that we expect to see, it looks like it'll be in that 46% to 48% range as an effective tax rate for the corporation.

Well, Janet, if I could follow-up. Is there anything else from the standpoint of statutory rates that's changing that would offset from a mix perspective the absence of the Libyan overlift and offset the benefits of zero on a pretty good slug of Norwegian income?

Well, you don't have zero on Norwegian income, you'll have the effect -- the 35% U.S. federal income tax rate against that.

Oh, just not the full Norwegian effective rate?

That's correct.

Okay. Thank you.

We are moving on to John Herrlin of Merrill Lynch.

Yes, hi. Two quick ones. In terms of your CapEx for 2007, in the U.S. it looks like you're going to spend about $1.3 billion between production, exploration, and exploitation. I was wondering if you could give us a sense of what your unconventional resources would be of that total for the PF Barnett?

Steve, do you have that information with you?

Well, roughly, I can tell you that roughly we'd expect to spend in those three resource plays, roughly about 15 to 20% of our total capital program of the number.

Okay. That's fine. Next question for me is on [EG]. For the second you were talking about Nigeria being a source of gas. Seems to be that their no flare policy is taking longer. Were you assuming you were going to get nonassociated gas or associated gas from Nigeria.

Whichever one we can get will make sense, but there's quite a bit of associated gas that isn't being flared, but is being reinjected. And right now I won't go into the specific fields that we're discussing, but right now the primary targets are reinjected gas.

Okay. Thanks, Clarence.

We will take our next question from Doug Leggate of Citigroup.

Thank you. Good morning, or good afternoon, everybody. Couple from me if that's okay. First of all, at Garyville, I don't want to beat this particular horse to death, but clearly the project has been sanctioned, but in light of the state of the union address and the clear aversion to gasoline demand growth in the U.S. I'm just curious, is that going to be revisited? Or are we full steam ahead, very happy to be going ahead with that project?

Gary, you want to take that?

Yes, Doug, we are as we've mentioned right after the state of the union address to ensure that we understand the message and the proposal, we're going back and revisiting what we believe to be the supply demand. And you have to look at it globally. And you have to look at all of our big projects just to ensure that we look at the proper mix, how much could be alternative fuels by 2017, 2020 in that range and how much still what incremental demand would be out there for refined products. So yes, we're going through that exercise, Doug, as we speak.. And I'll be reporting to Clarence here soon after we finish that to make sure we have all our numbers correct in our models.

Is the project temporarily on hold, Gary or just continue as normal?

We're continuing on. We're still finishing up the feed work. We have all the estimates and all that is complete. We have, we had already preordered a significant amount of the material. So we're into the detailed engineering and design that's moving forward, finishing up our permit work, and so -- nothing is slowing down on the project. The project team is fully engaged. It's just we're revisiting to ensure we're still comfortable.

Doug, I would only add that you'll recall when we talked about the project about half the incremental output is going to be diesel. And I think diesel actually under the -- what was talked about in the state of the union address may actually benefit in terms of greater agricultural need. But that's a real benefit. And I think at the end of the day, frankly low cost complex plants are where you want to be. And certainly, I think Garyville will be at the top of the list there.

Great. Thank you. Try one on ethanol. Gary Heminger again. Just a follow-up to Paul's earlier question. Clearly where spot prices are right now. What I'm kind of curious about is what's happening to discretionary ethanol blending on those incremental spot volumes? Clearly it would appear in conventional gasoline to be uneconomic. How are you dealing with that situation? Are you slowing it down or no change? No, and Paul, that's a great question. I should have mentioned that in answering Paul's question, but I mentioned 20-30% that we have kind of purchased long-term contracts. So we every day we make a decision on the discretionary blending. And whatever opportunistic blending we can do. We have the ability to speed up or slow down. So when it is not economic, we certainly slow it down. But as I mentioned, we have a good amount of volume that we have purchased longer term that is still very economic for us and we are blending, but also the benefit of having Speed Way and controlling Speedway we can move in and out of Speedway on a discretionary blending at a very short time frame. We have very little contracted on a spot basis.

Okay. My final question is probably a little bit ambitious, but I'm going to try any way. You've always given us some pretty good guidance on the earnings outlook for the integrated gas business, '07's obviously very different from previous years for obvious reasons. Any potential chance of getting a number there for the outlook for 2007?

I'm sorry, Doug, are you looking for the integrated gas segment as a whole?

Yes, obviously with the LNG business involved.

No. You know we don't project earnings for any segment. I would only say as you well know at the November analysts meeting we did give an indication of what the earnings and cash flow potential is for Train 1 at $6 Henry Hub, but of course that was on a full-year basis without start up and all that. So that's about the best I can give you.

Okay. Thought it was a little ambitious but thanks any way.

It was. But it was worth a try.

Our next question is from Mark Flannery of Credit Suisse.

Hi, yes. I have -- two questions. And firstly I think that's the first time I've heard Doug's name pronounced correctly on a U.S. conference call. But the diesel. You mention, you allude to the half the output of Garyville, the incremental output, being diesel. Diesel's in the news. Is there any way you're going to revisit any of your other capital or upgrading projects the next few years, and see if you're going to shift your mix more towards diesel aside from the Garyville plant?

Right. Doug, in order to be able to make more diesel, we can shift about around 8% or so of our slate we can shift to diesel or back to gasoline. But as far as capital investment, of course, that'd be somewhere down to the hydrocracking type of investments that would go in. And that is certainly a part of the big study work that we have going on around Canadian Oil Sands in the integrated opportunities we see there would lend to produce more diesel generally than it would be gasoline. So we're looking at that. As far as any other big projects, we don't have any slated at this time, but diesel continues to be very, very strong in the marketplace today. And we will visit that.

And in the same area, a 29% tax rate in the refining and marketing segment this quarter. That -- is there anything particular behind that? Is it just another one of these true up things? What should we think about the tax rate for 2007?

That's right, Mark. That was just a fourth quarter true up to get the effective tax rate for the year the right number.

So we'll get it back to the high 30s for 2007?

Yes. I think we're at 36%, 37% effective tax rate for the downstream.

Okay. Thank you.

We now have a follow-up question from Mark Gilman of the Benchmark Company.

I wonder, Clarence or Steve if you could give us some color on the reserve bookings and adds in '07 contributing to the 107% by region or area?

Steve?

Yes, I'll take care of that, Mark. We had 107% reserve replacement without dispositions or acquisitions. So 143 million. 122 million of that was international, 21 million was domestic.

Steve, can I push you to talk about a split at the international?

The big part of the international came out of Equatorial Guinea and in Libya, roughly around 69 million barrels in Libya.. Primarily due to performance as we had an opportunity to get in and watch those assets from the inside. And around 21 million coming out of Equatorial Guinea, both on performance and looking to sell more gas during the life of that field under contract. Those are the two big ones internationally.

Okay. Clarence, can you give us an update on where things stand in terms of the RFP for oil sands venture?

Yes. I think, Mark, the process is proceeding as planned. And as we've talked about before, as you know we went out for proposals. We received the responses in January. We've now narrowed the list down to a handful of companies and now have exchanged more detailed data. And going through that evaluation, my expectation is that if indeed there's a viable transaction to be done here, we should be at a point of concluding something by mid year. So I would say on track, working the details, Mark, stay tuned.

Okay, thank you, Clarence.

And we will now go to Paul Chang for a follow-up question with Lehman Brothers.

Hey, guys. Clarence, Looking at the second LNG train for Angola. Do you already receive a preliminary commitment from the producers?

No, Paul, it's the second train in EG. We don't have a by we I should say EG LNG does not have a preliminary commitment from the producers. What you may have seen in the news was that the government of EG has signed heads of agreements with both Cameroon and Nigeria about supplying gas to this second train. So government to government, there has been an HOA, which still needs a lot of details filled in around it, that certainly foresees the export of gas to EG. But beyond that, there will need to be obviously detailed gas sales agreements formulated and negotiated along with who's going to build the infrastructure that will then transport that gas to Bioko Island.

So, Clarence, from [inaudible] in order for you to feel comfortable to sanction the project. It means that -- if all that need to be in place and also also will you wait for to get a firm commitment or signed a contract with natural gas producer in Angola or Cameroon or [inaudible] or whatever that you found. And also that also sell [inaudible] or sign the long-term gas sales contract to sell LNG Congo before you will sanction the project.. How is that process will work for you?

Two different questions there, Paul. I think to your first one, you're absolutely spot on. And that's the reason why despite the fact that we'll finish the feed here at the end of the first quarter, we're basically saying it's going to be a year from now before we're able to sanction the project. And that's because we really do, indeed need to line up the gas and know the terms and the volumes and the quality of the gas as I said before depending upon the quality of the gas, that will potentially change what we have to build. So you're absolutely right. That all has to be in place. And to our satisfaction before we sanction the project. Your other question about what do we do in terms of marketing the LNG is really one that I think presents a lot of opportunities for us. I think if you look at the Atlantic basin today and indeed into the future, the real shortage out there is LNG. Our view is there's going to be more than ample regas capacity in the 2010, 2011, 2012 time frame we're talking about here. So indeed we think we've got multiple options. We can certainly do what we've done on Train 1, sell it FOB or indeed we can integrate through shipping and right into the marketplace if we so elect. That's something that's within our decision making within our control. The gas sales contracts obviously involve third third parties and we've got to get that lined up first.

Can I just sneak in with one more question? For the EG LNG, it going to start in the second quarter. How quickly the output going to ramp up?

Steve?

Would you like me to take that, Clarence? You know, that's always an uncertainty as you're going through your commissioning and your start-up. But we have a range there that we believe it will be up to full utilization. Probably on the low end in three months and high end of six months to get the full utilization.

Wow. That quick. Okay. Very good, thank you.

And it appears there are no further questions at this time. Mr. Matheny, I would like to turn the conference back over to you for any additional or closing remarks.

Okay, thank you very much, Angie. I would just like to point out before we do sign off, we were able to give you a headline on our reserve replacement this year for an answer somewhat to Mark's question and for any others listening. We will be putting out a more fulsome reserve replacement press release probably within two weeks with a lot more detail and putting some cost information for you. With that I'd like to thank everybody for your participation and sign off.

This concludes today's conference. Thank you for your participation. Have a great day.