馬拉松石油 (MRO) 2009 Q3 法說會逐字稿

Good day and welcome to Marathon Oil's 2009 third quarter earnings call. As a reminder, this call is being recorded. For opening remarks and introductions, I would like to turn the call over to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you, Kerry, and I would like to welcome everyone to Marathon Oil Corporation's third quarter 2009 earnings webcast and conference call. The synchronized slides that accompany this call can be found on our website, marathon.com. On the call today are Janet Clark, Executive Vice President and CFO; Gary Heminger, Executive Vice President Downstream; and Gary Peiffer, Senior Vice President of Finance and Commercial Services Downstream.

Slide two contains a discussion of forward-looking statements and other information included in this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31st, 2008 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. Please also note in the appendix to this presentation, there's a reconciliation of quarterly net income to adjusted net income for 2008 and for the first three quarters of 2009, preliminary balance sheet information, fourth quarter and full year 2009 operating estimates, and other data that you may find useful.

Slide three provides net income and adjusted net income data both on an absolute and per-share basis. Our third quarter 2009 adjusted net income of $436 million reflects a 74% increase from the second quarter of 2009 and a 78% decrease from third quarter of 2008. The increase from the second quarter was largely driven by the improvement in liquids prices and lower E&P expenses which more than offset a decrease in E&P sales volumes. The decrease from third quarter 2008 reflects income declines across all segments, the largest of which was in our downstream operations as a result of lower refining and wholesale marketing gross margins.

Slide four steps through the changes from the second quarter 2009 adjusted net income of $251 million to the $436 million earned in the third quarter. As shown in the waterfall chart, pre-tax income increased for all segments. Please note that the activities of our Irish and Gabon operations are reported as discontinued operations and have been excluded from E&P results for all periods.

As shown on slide five, we had a 136% quarter-to-quarter increase in E&P segment income, growing from $208 million in the second quarter to $491 million in the third quarter. Higher crude oil prices together with decreases in DD&A and other costs more than offset the impact of the lower [liftings] in the third quarter. Additionally, during the third quarter we began to credit certain foreign taxes that were previously deducted. Partially offsetting this positive effect was a valuation allowance recorded on certain deferred tax assets that we do not expect to realize. These items contributed to the 38% E&P effective tax rate for the third quarter.

Slide six shows our historical E&P realizations and highlights the $4.08 per BOE increase in our average realizations, which moved from $39.97 per BOE in the second quarter to $44.05 per BOE in the third quarter, driven by an $8.24 per barrel increase in liquids realizations while natural gas realizations remained relatively flat quarter-to-quarter.

Moving to slide seven, production volumes sold in the third quarter decreased 14% from the second quarter to 366,000 BOE per day as a result of the overlift we discussed in the second quarter compared to third quarter underlifts in Europe and Libya and increased natural gas storage in Alaska. Property dispositions also contributed to the decline. Third quarter production available for sale decreased 3% from the second quarter to 393,000 BOE per day primarily a result of the planned EG turnaround as well as property dispositions during the quarter, but increased 5% compared to last year's third quarter.

Slide eight shows the trend over the last seven quarters for field level controllable costs and expiration expenses per BOE. While exploration expenses were flat on a per BOE basis during the third quarter, field-level controllable costs per BOE decreased 9% from the second quarter. This decrease was primarily driven by lower liftings in the UK as well as in Norway, and the resulting change in sales volume mix compared to the second quarter. We have continued to focus on controlling costs, and as a result we have achieved a 10% reduction in operating costs per BOE for the first nine months of 2009 compared to the same period in 2008, excluding production taxes and DD&A.

Turning to slide nine, third quarter E&P segment income was $14.56 per BOE, a 172% increase compared to the second quarter of 2009, again primarily due to the higher liquids realizations, lower cost, and lower income taxes. Total E&P expenses per BOE decreased 7% from the second quarter, driven primarily by lower domestic DD&A mainly from Neptune and lower field level controllable costs due to the previously discussed change in sales volume mix. Also as discussed last quarter, the second quarter included certain expenses that did not recur in the third quarter.

Turning to slide 10, and oil sands mining segment income for the third quarter was $25 million compared to $2 million in the second quarter of 2009. This improvement was primarily driven by a $7.06 per barrel increase in our synthetic crude oil price realizations, increased sales volumes, and lower DD&A partially offset by higher costs primarily related to blue stocks and planned maintenance during the third quarter. Net bitumen production for the quarter was 27,000 barrels per day and net synthetic crude oil sales volume amounted to 33,000 barrels per day.

Moving to our downstream business, as noted on Slide 11, third quarter 2009 segment income was $158 million compared to $771 million in the same quarter last year. Because of the seasonality of the downstream business, I will compare third quarter results against the same quarter in 2008. The year-over-year decline was primarily a result of an almost $900 million decrease in our refining and wholesale marketing gross margin, which was consistent with the decreases in crack spreads in our markets and the narrowing of the sweet and sour differential over the same period. SSA's margins declined slightly primarily as a result of lower gasoline and distillate margins. However, our same-store gasoline sales volumes increased 3%, and our same store merchandise sales increased 12% compared to the third quarter of last year. The reduction in all other items was primarily the result of the disposition of our 50% interest in Pilot Travel Center in October 2008. Despite the decline in segment income, Marathon's refining and marketing operations once again outperformed our peers in the domestic market. We've been focused on controlling downstream costs, achieving reductions of approximately 9% for the first nine months 2009 compared to the same period in 2008, excluding changes in crude oil and refined product purchases, depreciation, energy prices, and other variable expenses.

As shown on slide 12, total refinery throughputs for the quarter of 1.190 million barrels per day were up 4% compared to third quarter 2008 throughputs. Turning to slide 13, integrated gas. Segment income was flat at $13 million compared to the second quarter 2009.

Slide 14 provides an analysis of preliminary cash flows of the first nine months of 2009. Operating cash flow from continuing operations before changes in our working capital was slightly over $3.5 billion. Our cash balance was reduced by working capital changes from continuing operations of $683 million. Year to date capital expenditures have been $4.4 billion and dividends paid totaled $510 million, while asset disposals generated proceeds of $573 million. Through the third quarter, we have spent $4.6 billion against the total projected 2009 capital investment and exploration spending of approximately $6 billion. With respect to project costs for the Garyville major expansion, we now expect this project to cost between $3.8 billion and $3.9 billion, primarily due to adverse weather conditions affecting construction productivity during the third quarter. As of the end of October, the project is approximately 98% complete and remains on schedule for fourth quarter start up. It is important to note that we plan an extended turnaround at the base plant early next year, and therefore, we expect the entire facility including both the base refinery and expansion to reach full capacity by the second quarter of 2010.

As shown on slide 15, at the end of the third quarter of 2009, our cash adjusted debt to total capital ratio remained 25%. As a reminder, the net debt to total capital ratio includes about $470 million of debt serviced by US Steel. Also shown on slide 15, we expect the overall corporate effective income tax rate from continuing operations to be between 54% and 59% for the full year 2009, excluding special items and the effect of foreign currency remeasurement of our tax balances. For the third quarter, our income tax provision included a $114 million foreign currency remeasurement loss which, by definition, is an after tax number. This loss, together with the tax items that we previously discussed in the E&P segment, basically offset in our third quarter consolidated tax provision.

Before we open the call to questions, I'd like to remind you of our upcoming analyst meeting to be held in New York City on Thursday, November 19th. If you wish to attend but have not yet responded, please call Bonnie Chisholm at (713)296-4171 to register. To accommodate all who wish to ask questions, we ask that you limit yourself to two questions. You may reprompt as time permits. With that, Kerry, we will now open the call to questions.

Thank you. (Operator Instructions). Our first question comes from Doug Harrison with ISI Group.

Good afternoon, everyone.

Hi, Doug.

I have a couple of questions for Gary about refining and marketing. First, on Garyville, are there any modifications to the planned crude slate that you guys have for the new facility?

Well, Doug, I need to answer that two ways. First of all, welcome back.

Thank you.

Glad to hear you on the call. For how we designed the plant, we designed it to be able to run a very heavy slate. Obviously when you look at the way the markets are and the sweet and sour differentials today, as we start to gear up, we would -- the way I look at the markets today, I tend to state that we're going to run more of a medium slate of crude on the front end, just because of where the markets are today.

Okay. And Gary, let me ask you one more question on refining. Are there any new strategic developments in the smaller plants in the system given the more challenging conditions that we're experiencing -- that is, what's on your mind on these days on Canton, Detroit, Texas City, and/or St. Paul, are there any new viewpoints there?

Well, obviously, Doug, we look every day at the crack spreads and ensure that these plants can run and hurdle the economics for the crude that's available and the markets that we're supplying. And today they all do.

Okay. Great, thanks a lot.

You bet.

Our next question comes from Robert Kessler with Simmons & Company.

Good afternoon. I was wondering with respect to Garyville, given it doesn't sound like we should expect much in the way of margin contribution until maybe the second quarter of next year, can I confirm that you would still expect mechanical completion by year end and as such get the favorable 50% tax deduction or accelerated depreciation for 2009?

Yes, Robert, we are -- as Howard said in his speech, we're 98% complete. We're already in the sequence start up of some of our units, expect crude unit to go through that sequence here mid November, followed by the hydrocracker and the balance of the units by the end of the year. The answer to your question, yes, we expect all units to be mechanically complete by the end of the year.

I'm assuming that will result in a fairly sizable deferred tax cash benefit that would show up in the fourth quarter of 2009 -- is that fair to say, somewhere on the order of $400 million to $500 million?

Janet, can you help me with that? Or Gary?

No, we've been --

Or has it been sort of ratable over the course of the year, so it won't be a big bump?

No, we've been anticipating it all year and booking it accordingly.

Okay. Thank you very much.

Thanks, Robert.

We'll move now to Paul Cheng with Barclays Capital.

Hi guys. Janet, on the international E&P, the tax rate 38%, you say because you start deducting some [amount] of that previously, you did not. Does that mean that on a going forward basis that which is also looking at the tax rate instead of historically in the 60% to 65% at least in the coming quarter would be about in the 38%?

No, no, Paul, there are a couple of things that went on here in the third quarter. We did start crediting a foreign tax previously we'd been deducting and there was a catch-up. So there were a couple years there that you will not -- so it was a bigger effect in the third quarter than it will have on an ongoing effect, but it will have an ongoing effect.

Any idea what tax rate we should assume on an ongoing basis in the international E&P?

Overall, it's 54% to 59%, Paul, that we've projected and of course that's excluding any FX effect on the tax balances. But you can look back at what we've done over the past few quarters and balance that out between international and domestic.

Howard, can we do it this way -- if I look at the first three quarters and look at what is the average for the first nine months, is that a reasonable international tax rate going forward?

Paul, it's going to depend upon the mix, where it comes from, we've got very different tax rates. Libya's 93%, [ED] 25%. So for us to project any precise rate for the international segment is highly dependent upon what happens to oil prices, gas prices, and production -- and not only that, but listing liftings in the country.

Along that line, Janet, can you tell me at the end of the third quarter how much underlift you are and where's the underlift by region?

Yes, we were underlifted 21,000 barrels a day in the third quarter and --

At the end of the third quarter, right, that is?

No, before the third quarter we were 21,000 barrels underlifted. On a year-to-date basis, we're 5,000 barrels underlifted.

Year-to-date you're 5,000 underlift. And can you tell me that 5,000, how it's spread?

We're -- at the end of the year, Paul, we're 5 million barrels underlifted, total 5 million barrels underlifted. Europe's about 1.6 million, then Libya is about 1 million, and the balance is essentially Alaska. And the Alaska's a gas storage issue, not underlift. And the expectation would be by the end of the year we will not have made up much, if anything, in Alaska, but the likelihood is we'll be closer to a balanced position in Europe and Libya where we're, as I said, about 2.5 million -- between the two, about 2.5 million barrels underlifted between those two areas.

All right. Can I have a final question, the [Troy] expense in Gary, is there any update you can give?

We're at the same place, Paul, we were at the end of the second quarter, that we stretched this project out to the end of 2012 and that's still where we are.

Thank you.

Thanks, Paul.

From Merrill Lynch, we'll move on to Doug Leggate.

Thanks, hi everybody.

Hey, Doug.

A couple things. I want to try one downstream and one upstream if I may. You made a point in your commentary that the defining earnings had been remarkably resilient compared to your peers, which is absolutely correct. However, what I'm curious about, you folks still have your midstream earnings, whereas a lot of your peers don't have midstream anymore, as they've either sold or spun off in some way. Can you give us some idea as to what's happening to the midstream earnings? Is it material? I know you won't break out the numbers, but quantitatively in terms of how much is that helping your earnings in this tough environment? And my follow-up is on the upstream.

Well, Doug, you're right, we don't break them out separately, and I can't share that data with you. I will say that our midstream earnings and our definition -- first of all go to definition, our definition of midstream is our pipeline and logistics businesses. It doesn't include any trading like some companies midstream will include trading and arbitrage on products. So ours is purely pipeline and then logistics. And they've been steady over time. That would be the best way for me to answer that.

Is it to you, Gary, or is it not that big of a deal?

This is Gary Peiffer. It wasn't that material in the quarter to quarter change.

But on an absolute basis, Gary, is it material?

As Gary said, we don't talk about breaking -- we don't break out the pipeline or the business stream assets.

I would say, Doug, the best way to look at our quarter, if you take a view of the PAD2 margins versus PAD3 margins, they were better again as we spoke in the second quarter. They were much better than they were in the Gulf Coast, that is what's led to our value. And coming back to your question around the logistics, we're able to move our product to the markets and probably have some competitive advantage because of our logistic system that helps us do that.

Well, perfect. Thanks, Gary. My upstream question is on the back end. One of your competitors has a slightly bigger acreage position. It's getting a lot more aggressive in terms of rig count for the next year or so, some very big production targets have been laid out there. I'm just wondering, first of all, why not a little more aggressive from you folks? Maybe you could lay out what your plans might be on the back end, let's say, as we look forward beyond 2009? That's it, thanks.

We are going to be adding a fourth rig here later on in this quarter. And we do our production forecast bottom up and look at our drilling schedule and look at the results, so we're pretty comfortable with the guidance we've given with regard to the rampup. To the extent that our competitors have different forecasts, you need to talk to them about theirs.

What I'm referring to, Janet, is the profitability of the back end is possibly pretty stellar in this environment. If you've got the assets with a big [hedge] position, which I'd say is not dissimilar, why would that not have a bigger call on capital for -- as opposed to some of the other assets maybe in the portfolio?

Doug, as I said -- the other thing too is we're just now going through the planning process for 2010. I think at the analyst meeting we'll be able to give you a much better in-depth discussion of that asset as well as all our capital allocation on a go-forward basis.

That's terrific. Thanks, Janet.

Sure.

Our next question comes from Paul Sankey with Deutsche Bank.

Hi everyone. The announcement on Garyville -- the fact that was in the press release suggests that it was a relatively recent decision. Is that a mischaracterization? Will it have by extension a CapEx impact next year? Are you effectively increasing your downstream CapEx above and beyond what you would have spent, or thought you'd spent? I know it's going back a long way, but back at the 2008 analyst meeting the guidance was downstream CapEx was just about half between 2009 and 2010. Thanks.

Yes, Paul. Over the last year, talking about the turnaround at Garyville, that's nothing new. That's been planned ever since we started this project, to be able to time and to be in sequence as we finish the major expansion and the turnaround. And we thought it was important that since it's a major event at Garyville, we didn't want to lead anyone on that we were going to start up immediately with both plants. We wanted to inform you that we would immediately go into a major turnaround on the base plant. That's been our planning all along. We wanted to ensure we had everyone on the same page.

So I guess --

As far as capital then, Paul, we don't see -- we're still right in line with what we said we would be on capital, significantly down from where we are in 2009 as we go into 2010.

Just to be clear on it, Gary, you're going to be running new units but taking down the originals -- so that the refinery will be not quite half but essentially half running?

That's correct.

A follow-up on the market in the quarter, it seems that marketing, I know you guys [didn't have] anything to announce, but it did seem that marketing was very strong indeed, I think is it fair to say? And I was wondering what was the driver behind that, because obviously we didn't have the big move that we would typically expect, for example, on pump prices that would generate that profitability. Any color you could provide us on -- I'd like to follow up on Doug's question -- any sort of additional granularity you can give us on what the contribution from marketing was would be great, and on top of that if you could explain some of the drivers? Thanks, Gary.

Let me explain the drivers. As you know, it's been our practice not to go into the granularity of segment reporting at this time. But the key -- going back to Howard's speech, we're up nearly 3% on same store gasoline and that was while we looked at the market. That's probably a little bit better than what some of the overall market indicators show us on a gasoline volume basis, which says we're probably taking a little share. I think we continued to improve taking some share in Q1 and Q2.

The biggest driver comes down to two things. Merchandise sales, our merchandise sales being up approximately 12% quarter on quarter, but the margin increase that comes along with those merchandise sales when you average around 25% or so is a big improvement to our retail. And lastly, I think Tony Kenny and his team have just performed from an operating expense standpoint and a control standpoint at a very, very high level. They've kept their operating expenses in check, they've been able to improve retail sales inside their stores when the markets overall are down. And I think within this sector they probably have sector-leading results. While we don't break them out, I can just share with you that my observation of how they're performing, they're sector-leading results across the entire convenience store chain.

Does that mean that the majority of the driver was in the pump retail station as opposed to in the midstream?

Well, no, what I'm just saying is they performed very, very well quarter-on-quarter, and I can't get into how they performed versus the midstream, but I can just tell you that Tony's team had an outstanding quarter.

Thanks, guys.

This is Gary Peiffer. If you looked at the waterfall that Howard described, if you look at SSA product's merchandise margin, was actually down quarter-over-quarter by $10 million, and a lot had to do with the lower per gallon margin on our [light] products. So if you're looking at margin, you're seeing that actually it was down quarter-over-quarter in SSA.

That's really due to last year there were some hurricane effects in the third quarter and some other storm effects in the third quarter led us to a little higher margin, but we have had a significant increase in merchandise sales and margins inside the stores this year. It just was in the third quarter, and we've had double-digit merchandise sales increases every quarter this year.

Okay. Thanks a lot, Gary.

We'll move to Evan Calio with Morgan Stanley.

Good afternoon, guys, thanks for taking my call. I had a question on the asset sales. I know in 2008 you guys had got $2 billion to $4 billion in asset sales as part of your ongoing portfolio review, and as of 3Q end, it's $3.5 billion -- should we assume the sale program is coming to an end or were your initial estimates conservative or better yet, higher prices than expected?

Well, if you recall, when we gave that range out about 1.5 years ago, we said that we expected that program to be announced by mid 2009. So we've achieved that objective. But as you know, optimizing the portfolio is something that you really need to be doing continuously. So we're going to continue to look at our portfolio to the extent that we have assets that aren't strategic to us, perhaps are mature, we can't add a lot of further value to that asset, or in fact if that asset is worth more to somebody else, it's an asset that we then would consider monetizing. While this program per se has been achieved, it's going to be an ongoing effort to continue looking at how do we create value by monetizing assets.

So I mean, may we expect another program or is it just considered part of continuing operations to make asset sales going forward?

I think we had -- in the three or four years leading up to the 2008 announcement, we had not been optimizing portfolio, we [had] been monetizing assets, so we had a little bit of catch-up to do. I would say on a go-forward basis, it would be more business as usual, but with a very keen eye with looking for opportunities to create value.

Great. Second question, on your cost control program squeezing 10% out of operating cost per barrel in the upstream, how much room is left there to run cost lowers or any comments on that, on a go-forward basis or cost reduction on the downstream side?

We're looking across the entire business, Evan, not just upstream, not just downstream -- we're looking across every piece of business we're doing today. So I would just say we have room to go there in moving our costs further down.

Any estimate on how far down?

I wouldn't -- I'm not going to get out ahead of us, to try to pin a number on it. I would just say we've got a sharp pencil out looking at taking costs further down.

Understood. Very well. Thank you.

Our next question comes from Faisel Khan with Citi.

Good afternoon.

Hey, Faisel.

Can you guys talk a little more about the discovery in Norway, the size of the discovery, and how many more prospects you might have in the neighboring area that you might be able to tie into online?

You're talking about the Marihone discovery that we just had. We haven't given a specific size on that to my recollection, but I'll just tell you, it's probably in the 20 million to 40 million barrel kind of number. Without giving any specifics or not, it would be a nice tieback, it's not obviously a standalone, and we have a, I'll just say several additional two, three, four additional prospects that we're going to be drilling in that area that could also be tiebacks to the Alvheim FPSO. So they're really designed to keep the FPSO at a really full level for a longer period of time than just the Alvheim and Vilje developments would do on their own.

Okay. On the Droshky development, can you remind us what you expect peak production to be at after you bring that?

Droshky will come on midyear next year in 2010, and it will peak at somewhere around 50,000, I think we put in the presentation about 51,000 will be the peak BOE a day rate.

Great. On the downstream side, you guys benefit from any discretionary blending of ethanol or some of the lower ethanol prices versus the gas prices in the quarter?

This is Gary Peiffer. Actually, when you look at the quarter, we actually were a little bit hurt quarter-over-quarter because the spot price of gasoline quarter-over-quarter was down about $1.30 a gallon. The spot price of ethanol was only down about $0.70. If you look last year third quarter versus this year third quarter, we made less money on the ethanol blending just because the ethanol prices didn't drop as much as gasoline prices did.

How about sequentially?

It would be actually a little bit lower this quarter versus last quarter as well, a little bit lower earnings.

Okay. Understood. Thanks for the time, guys.

Thanks, Faisel.

Moving to Mark Gilman from The Benchmark Company.

Good afternoon, folks. A couple things if I could. Howard, I believe you referenced Neptune as being the reason for the decline in US DD&A. What led to that, is it a decline in DD&A rate or is it a production oriented decline?

It was actually we made the comment -- we added back some reserves, we got maybe a little aggressive in removing reserves in the second quarter, and in June we put some of those back on the books. So the rate went down because of that reserve booking.

Okay. So we should assume that the rate will be stable going forward?

We still expect the US rate, overall rate now, Mark, is to be in the $17.50 to $20 a BOE rate, which is where it was in the third quarter. So, yes, we expect it to be in that range.

Okay, if I could switch to the tax area for a second. Janet, can you help me understand what it was that gave rise to the change as it related to going to a credit mode as opposed to a deduction mode? And if possible, quantify the valuation allowance which cut the other way in terms of the tax rate in the third quarter?

Mark, I'll say the important thing is that both discrete items largely offset one another along with a myriad of other small items. We have elected to credit rather than deduct that, because it's consistent with industry practice and it's the appropriate way to do it.

Why didn't you do it all along?

We did it now, Mark, I think that's the answer I can give you, okay.

Okay. Can you quantify the valuation piece specifically?

No, I don't think there's any real merit in that. Every quarter we look at our valuation and adjust them accordingly. So it's -- this kind of noise, it's in the numbers every quarter.

Okay. Given my success up to this point, let me try one more. Of the downstream cost reductions, Gary Heminger, how much of it roughly might you say actually flowed into the gross refining and supply margin versus, let's say, other areas of the downstream?

Mark, this is Gary Peiffer. I'd say roughly half.

Okay. Thanks, Gary.

Thanks, Mark.

Our next question comes from Pavel Molchanov from Raymond James.

Thanks for taking my question. Just a quick call on Angola Block 32. Obviously you guys signed a deal with the Chinese back in July, but it looks like the Angola government is trying to exercise their pref rights. Can you give us an update on that?

Well, we haven't commented on that one way or the other, other than to say that obviously just like all other operations there are preferential rights for all the partners. And our anticipation is that we will close that sometime around the end of the year one way or the other.

And if -- regardless of who the purchaser ends up being, is $1.3 billion still going to be the transaction value?

That is the transaction value that we've announced, that's correct.

Thanks very much.

Our next question comes from Neil McMahon with Sanford Bernstein.

Hi, two questions. One, actually, turning back to Angola and your relationships with the Chinese, is there anything more broadly going on there with yourselves other than your African acreage or some of your other positions such as refineries or oil plans in Canada where you could see further hookups with Chinese companies?

I guess anything's possible, Neil. I mean, but we don't comment on -- I mean, that would be pure speculation at this point to step out and say anything like that.

All right, where I was going with it was in terms of Angola Block 32, was that a relationship that started or were they just the top of the bidding list when they came to go after that acreage?

Well, there was a bidding process.

Okay. Second question was really on the exploration capitalists over the next six months. You've got some wells in the Gulf of Mexico and into next year you've got your Indonesian program maybe starting up -- maybe you could just outline certain time points we should be aware of with significant wells going down?

Well, I think you landed on the key there, that we will be drilling a handful of wells in the Gulf next year, both operated and nonoperated. And we'll drill, depending on when the rig makes it to Indonesia, we'll drill one or two wells in Indonesia. As far as timing, I think since we're just about two weeks away from the analyst meeting, I'd prefer to let Anelle Bay, I don't want to take her powder, I'd rather let her give you an update on it at that time when she and several of Dave Roberts's key lieutenants will be making presentations on their piece of the business just as Gary and his team will on the downstream.

Great. Thanks a lot, Howard. Thanks, Neil.

We'll move to Blake Fernandez from Howard Weil.

Good afternoon, thanks for taking my question. The first question I have is on strategy with regard to your North American shale plays. It seems like you have a relatively small position in three of the more attractive plays. I'm curious if there's any thought to maybe consolidating down to one or two plays with a more significant position?

Well, we've -- since we've moved into those, that we would continue looking at expanding one, two or all three of those shale plays. Is it possible? Sure, it's possible to move from one to another. I'd just say when you look at what we have in Oklahoma, there that's essentially held by production, that's an area that's grown up beneath us about 50,000 acres that is probably going to be a little harder to grow. But in the Marcellus and Hainesville, where we have respectively 75,000 and about 25,000 acres in those two areas, those are places that we're looking to expand, but looking for the right opportunity, but not in any huge hurry. We're in the process now of this year drilling probably three wells, spudding a total of four wells this year in the Marcellus, and we'll drill the first Hainesville well later this year to look at the 25,000 to 30,000 acres that we have there. So it's something that we're going to continue to look at, but we're not in any hurry.

Okay, great. And Howard, the only other one I had -- it sounded like when you were providing the retail same-store sales up 3%, it sounded like a gasoline number. Do you have a diesel comp?

Blake, this is Gary. On the diesel side, within our Speedway stores, we sell very, very little diesel. We were up 0.3%, but it's on a very, very small amount of buy. Most of our diesel, remember, we put into a combination with Pilot and sold that off. So this is just auto diesel that we sell.

Okay. Okay. All right, that's what I had. Thanks.

(Operator Instructions). We do have a follow-up question from Paul Cheng with Barclays Capital.

Hi guys. Janet, in Norway, are we still have any tax [law carry] or that is being used up now?

I think, Paul, we're going to have that pretty much used up. Your guess as good as mine, but within the next few months.

Okay. So that before the year-end will be pretty much done?

This winter for sure.

Okay. And maybe this is for Gary, Gary, why do [spend] DD&A from the second to the third quarter will be down in oil sand? Because of -- what's the reason?

Paul, that's because remember just at the end of the second quarter we had an agreement on what was known as Shark Bite. So we bought the Shark Pipe reserves ready for production, we brought those into the mix, and we just had the month of June would have had DD&A, would have had one-month affecting the second quarter for Shark Bite, and here in the third quarter it had the total effect of that.

Okay. And when I go through the very simple calculation, it look like based on your realization and your tax income, it suggests all in unit cost is about $51 to $52 per barrel of the synthetic sales compared to maybe $55 to $56 in the second quarter. The drop by about $3 to $4, is it all related to the lower DD&A or related to the cash cost [proposal]?

Let me give you a different number. I've always looked at cash operating expense, and in the second quarter of 2009 I think I mentioned that it was $35.63. Here in the third quarter is $34.56. Again, that's just our cash operating expense. And the -- when I look at those changes, we had a little more turnaround expense in the second quarter of 2009 than we've had in the third quarter. So that $1, I guess it's about $1.07 difference is -- was mainly due to lower turnaround and some improvements in reliability, which help the denominator.

I see. Great. Janet, on the 10% E&P cost saving, yield for the year from the first nine months of this year to the nine months of last year, can you tell us how much is energy and fuel-related and how much is sustainable on a going-forward basis?

This is Howard, Paul. It was about 1 percentage point that was energy-related. It would have been 9% instead of 10% if you take out the energy.

Howard, is it the remaining 9%, is it sustainable on a going-forward basis or some of that may be somewhat of a one-time benefit, may not be sustainable?

We believe it's a sustainable savings.

Okay. And out of that 9%, how much is related to industry when the negotiation, how much of them is the other [self-help] program that contribute?

I don't have it that fine, Paul, to be able to tell you. I think -- it's a combination of the two, because not everything that we're doing is actually leading to an absolute dollar cost savings. One of the examples, I don't remember whether Dave gave this last quarter or not, is the -- when we're drilling and completing wells, the completion costs are down 25% or 30%, but we're just doing larger fracs. So we're spending the same amount of money, we're just getting large production rates. It really depends on an area-by-area basis. But I would just tell you that our anticipation is that is sustainable, depending on what happens with oil prices and cost pressure. But we think it's been driven out permanently, so to speak.

We have a final follow-up question from Mark Gilman with The Benchmark Company.

Thanks guys. Gary Heminger or Gary Peiffer, R&M DD&A jumped $10 million in the quarter. Although it doesn't sound like a lot when you think about it from an annualized perspective and what the incremental and service capital would have to be, it could be a big number. What was responsible for that?

Mark, this is Gary Peiffer. I believe, I don't precisely know, I'll have to get back to you -- maybe we are starting, as Gary said, start up some of the GME units, we are getting a little bit of GME appreciation, I don't know how much of that was responsible, but that will be some of it.

Okay, Gary, thank you.

We'll get back to you, I think that's the majority, but we'll get back to Howard with the number. He can get it to you, Mark.

Thanks a lot, Gary.

Thanks, Mark.

And we have no further questions.

Okay, Kerry. I appreciate it, I appreciate everybody's attention. And again, if you have not signed up for the analyst conference that we're having November 19th, you can please call Bonnie Chisholm at (713)296-4171 to register and we look forward to seeing you then. Thank you.

Ladies and gentlemen, that does conclude today's conference. We thank you for your participation.