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Marathon Oil Corp. (NYSE:MRO)

Q2 2009 Earnings Call

August 3, 2009; 2:00 pm ET

Executives

Clarence Cazalot - President & Chief Executive Officer

Janet Clark - Executive Vice President & Chief Financial Officer

Gary Heminger - Executive Vice President, Downstream

Dave Roberts - Executive Vice President, Upstream

Garry Peiffer - Senior Vice President of Finance & Commercial Services, Downstream

Howard Thill - Vice President of Investor Relations & Public Affairs

Analysts

Doug Leggate - Howard Weil

Ryan Todd - Morgan Stanley

Paul Cheng - Barclays Capital

Faisal Khan - Citigroup

Pavel Molchanov - Raymond James

Mark Gilman - Benchmark

Paul Sankey - Deutsche Bank

Ann Kohler - Caris & Co.

Mark Caruso - Millennium Partners

Operator

Good day everyone. Welcome to Marathon Oil’s 2009 second quarter earnings conference call. As a reminder today’s 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.

Howard Thill

Thank you Erica and welcome Marathon Oil Corporation second 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 Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Executive Vice President, Downstream, Dave Roberts, Executive Vice President, Upstream; and Garry 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 it’s Annual Report on Form 10-K for the year ended December 31, 2008 and subsequent Forms 10-Q and 8-K cautionary language identifying the 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 note that in the appendix to this presentation is a reconciliation of quarterly net income to adjusted net income for 2008 and the first two quarters of 2009, preliminary balance sheet information, third quarter and full year 2009 operating estimates and other data you may find useful.

Moving to slide three, this provides net income and adjusted net income data both on an absolute and per share basis. Our second quarter 2009 adjusted net income of $251 million reflects the 5% increase from the first quarter of 2009 and a 71% decrease from the second quarter of 2008.

The increase from the first quarter was largely driven by the improvements in liquid prices and increased E&P sales volumes, but higher income tax provision almost entirely offset these positive impacts. The decrease from the second quarter of 2008 was primarily result of the decline in commodity prices partially offset by higher E&P sales volumes.

Consistent with our reporting practice we excluded the small mark-to-market gain on you on U.K. gas sales contracts and gains and lose on our more significant asset sales from adjusted net income. However, the adjusted income net of $251 million or $0.35 per share, as certain items included that investors and analyst may not have been aware of or are normally, excluded from their calculations.

The E&P segment included a $38 million increase for DD&A for Neptune over the first quarter and charges totaling $28 million for an impairment of an East Texas field, a Bakken rig cancellation and a loss on the sale of a small asset. These items total about $66 million pre-tax or $41 million after tax.

Also as stated in our interim update, 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 a deferred tax balances.

For the second quarter, the effective income tax rate was 68%, which included a $94 million foreign currency remeasurement loss which by definition is an after tax number. Excluding this loss, the effective tax rate would have been 59%, the first quarter included a $28 million remeasurement gain resulting in a $122 million change quarter-to-quarter.

The previously discussed E&P charges and the current quarter foreign currency remeasurement loss together result in an after tax impact of $135 million to the second quarter.

Slide four steps through the changes from the first quarter adjusted net income of $240 million to the $251 million earned in the second quarter. As shown in the Waterfall chart, pre-tax segment increases in E&P, Oil Sands Mining, and our RM&T were almost entirely offset by a higher provision for income tax.

Please note that the activities of our Irish businesses, which we recently exit, have been reported at discontinued operations and excluded from E&P result for all periods. As shown on slide five we had a 159% increase in the E&P segment income growing from $85 million in the first quarter to $220 million in the second quarter. Higher crude oil prices and increased lifting’s during the second quarter were partially offset by higher income taxes, lower natural gas prices and higher DD&A.

Slide six shows our historical realizations and highlight the $9.87 per BOE increase in our average realizations, which moved from $30.16 per BOE in the first quarter to $40.03 for BOE in the second quarter.

Moving to slide seven, production volumes sold in the second quarter increased 11% compared to the first quarter to 436,000 BOE per day, as a result of higher international lifting’s. During the same period, production available for sale decreased 3% to 411,000 BOE per day, primarily as a result of turnarounds in Norway and Alaska, as well as property dispositions during the quarter, but still reflected a 12% increase over the second quarter of last year.

Our U.S. liquid sales volumes for first half of 2009 have increased about 2,100 barrels per day over the prior year to 65,000 barrels per day, primarily due to the startup of the Neptune development and increased activity in the Bakken. It is also important to note, that we have retained our production rate in the Bakken at approximately 8,800 BOE per day during that period and still expect an exit rate of 9,500 BOE per day for 2009. Despite the fact that we have reduced our rig counts from seven to three.

Slide eight shows the trend over the last six quarters for field level controllable costs and expiration expenses per BOE. While expiration expenses continue to decline on a per BOE basis during the second quarter, field level controllable cost per BOE increased 22% over the first quarter. This increase was primarily driven by higher lifting’s in the U.K., as well as in Norway and the resulting change in production mix compared to the first quarter.

Turning to slide nine, second quarter E&P segment income was $5.56 per BOE, a 133% increase compared to the first quarter of 2009. Again, primarily due to the higher liquids price realizations and increased liquids sales volumes. Total E&P expenses in the second quarter increased $131 million over the first quarter primarily due to higher lifting’s.

As a result, total E&P expenses per BOE increased only 3% from the first quarter despite the previously discussed higher domestic DD&A per BOE. Excluding the increased DD&A for Neptune, expenses for BOE were flat. Also as previously discussed, second quarter results reflected expenses related to an asset impairment in East Texas, a loss on the sale of small assets and a rig cancellation. This is expected to be the final rig cancellation for 2009.

Turning to slide 10 and Oil Sands Mining, segment income for the second quarter was $2 million, compared to a segment loss of $24 million in the first quarter of 2009. This improvement was primarily driven by $16.53 per barrel increase in our synthetic crude oil realization, partially offset by slightly higher costs primarily related to blend stocks and the decline in other sales, which was primarily related to the derivative gain recognized in the first quarter while derivatives had a minimal impact on the second quarter.

Net bitumen production for the quarter was 26,000 barrels per day and net synthetic crude oil sales volumes amounted to 30,000 barrels per day. During the second quarter, we elected to participate in three additional AOSP leases. As a result, reclassified about 190 million barrels of contingent resource with 168 million barrels added to proved reserves and 22 million barrels added to probable reserves. These additional reserve barrels brought our oil sands mining DD&A rate per barrel down by approximately 40% beginning in June.

Moving to our downstream business, as noted on slide 11; second quarter 2009 segment income was $165 million, compared to $158 million in the same quarter last year. Because of the seasonality of the downstream business, I will compare our second quarter results against the same quarter in 2008.

Our refining and marketing operations not only saw improved earnings during a very difficult quarter for refiners, but appear to be setting the pace for domestic peers. The increase in RM&T segment income primarily reflects improved refining and SSA margins over the second quarter of 2008. Improved SSA margins reflect both increases in our retail light products, margin per gallon and total sales volumes year-over-year.

Our same-store gasoline sales volumes increased 3%, compared to an estimated demand decline in our market area of 2% and our same-store merchandise sales increased 14%. These positive margin impacts were partially offset by the reduction in all other items, which primarily resulted from the disposition of our interests in Pilot Travel Centers in October 2008.

As shown on slide 12, total refinery throughputs for the quarter of 1.158,000 barrels per day were down 4%, compared to second quarter 2008 throughputs, primarily due to turnaround activities.

Turning to slide 13 and the integrated gas at the segment; second quarter segment income was $13 million, down from $27 million in the first quarter of 2009. A quarter-over-quarter decrease was primarily attributable to lower LNG price realizations.

Slide 14 provides an analysis of preliminary cash flows for the first half of 2009. Operating cash flow from continuing operations before changes in our working capital was slightly over $2.3 billion. Our cash balance was reduced by working capital changes of $611 million. Year to-date capital expenditures have been $3 billion and dividends paid, totaled $340 million, while asset disposals generated just over $400 million.

With respect to our 2009 capital investment and expiration spending or CapEx, we now expect total CapEx to be approximately $6 billion, compared to our original budget of $5.7 billion, largely related to the increase in forecasted project cost for the Garyville Major Expansion.

We now expect this project to cost approximately $3.7 billion. The project is over 91% complete and remains on schedule for a fourth-quarter startup. Through the second quarter, we have spent $3.1 billion against the total projected CapEx of the approximately $6 billion, I just mentioned.

As shown on slide 15, at the end of the second quarter of 2009, our cash adjusted debt-to-total capital ratio was 25%, which because of rounding was actually less than a one percentage point increase from the first quarter of 2008. As a reminder, the net debt-to-capital ratio includes about $470 million of debt service by U.S. Steel.

Before we open the call to questions, I’d ask you to please add our analysts meeting date to your calendar. We will hold the meeting in Midtown New York on Wednesday, November 18, from 8:00 am through lunch. You will receive a more formal invitation shortly.

Now we ask that to accommodate, all who wish to ask questions, you limit yourself to two questions. You may refile for additional questions as time permits.

With that Erica, we will now turn the call over to you for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Doug Leggate - Howard Weil.

Doug Leggate - Howard Weil

I’d like to go back to the first-quarter conference call and I’m sure that Dave Roberts gave to a question relating to DD&A and related to Neptune. If I’m not mistaken, what Dave said at the time was that, you had just about 2 million barrels at out of Neptune and you had written the asset down to about 2 million barrels.

So, I’m trying to understand, why the DD&A is still in the books for Neptune? If you could give a little bit of an update as to how the project is performing? What that DD&A should look like going forward and I have one follow-up.

Clarence Cazalot

I’ll start and then Janet may want to jump in. Your numbers are accurate in terms of what we said the asset was just to recap. We had taken the reserves down from 12 to roughly two and so the DD&A rate for the quarter went up substantially, and that was as a result of the reservoir performing worse than our models indicated.

What we said at that time is we thought the reservoir was more compartmentalized than our models were predicting. I will tell you that, this month we’re going to add back about 0.5 million barrels of reserves and that should then take our DD&A rate down about 30% in Q3 from Q2.

So it will get us back to a more normal rate and the figures that Howard quoted for Q1 will be what we expect on a go-forward basis. The critical aspect here in terms of why this asset wasn’t completely written-down is you understand the write-down test is an economic test. It’s not a financial test and it also considers things on a perspective basis, go forward basis.

We still believe that there’s on the order of 10 million barrels of total resources net to Marathon and there is additional potential on the north flank of the field that it’s not included in those volumes, and we believe that there is potential for this value to be realized and, therefore, we have not elected to take a complete write-down of the asset at this time.

Doug Leggate - Howard Weil

If I could ask a follow up for clarity, so just to be clear, the run rate going forward somewhere in the $17 range for the U.S. is what you’re implying?

Clarence Cazalot

Well, I think what we had said earlier in the year for the DD&A rate in the United States, we had given a range at the beginning of the year of $17.50 to $20 and we will be comfortably within that range for the year.

Operator

Your next question comes from Ryan Todd - Morgan Stanley.

Ryan Todd - Morgan Stanley

Just had a couple of questions on refining for you, you gave an update at the Garyville refinery there. You still targeting a 4Q startup, is that correct? Then also on the Detroit refinery, is that still targeted for mid-2012 as stands?

Gary Heminger

Yes, Ryan. On Garyville, we are still targeting a fourth quarter startup. In fact, we’ve already started to turn over the waste water treatment plant and the sulfur plant will be soon after that as we start to sequence through Garyville. So fourth quarter startup is still on board and Detroit, as we’ve said in the previous conference call, we’re looking at possibly stretching it a little bit. It will probably end up being a little bit later in 2012 than mid-year.

Ryan Todd - Morgan Stanley

If I might follow-up on refining, obviously you performed great in a difficult environment here in the second quarter. Particularly for heavy, light, and sweet/sour spreads. Is it possible to give an update on the incremental benefit that we might see from Garyville if it were to come up in the current environment?

On the heavy/light spread, do you think it’s a matter for heavy/light recovery, that’s with a matter of OPEC barrels coming back into the market, or is there greater structural press that we see there in differentials?

Gary Heminger

The first thing I would see is, we need a return of the diesel market. I think a return of overall diesel demand as you’ll recall, we have engineered Garyville to be approximately 50/50 gasoline/diesel type refinery. We believe that diesel is really the precursor to some more heavy barrels coming back into stream and to the overall economy.

So as the overall economy improves, I should say as diesel improves, that is I think a pretty good indication that the economy is starting to improve. We have given numbers in the past. I don’t have a number calculated here if we were to look at today’s sweet/sour spread or the lack thereof and today’s crack spreads, but if you’ll recall looking back at kind of the ‘03 to ‘07 picture we’ve given before and we said that, if you were to look at 2008.

Garyville and look at 2008 by itself, we would have somewhere in the vicinity of $700 million of cash and $800 million in cash flow. I’m only talking about GME incrementally here. So, today’s sweet/sour differentials are significantly behind that number. I would say rule from, you could probably say about half of that $700 million of income for the incremental piece, alone if you looked at time to today’s numbers and I think that was a very, very conservative number.

Operator

Your next question comes from Paul Cheng - Barclays Capital.

Paul Cheng - Barclays Capital

Gary, maybe I have to apologize coming in little bit late. When we look at the Garyville, is there anything have changed in the last three months? Why that all the sudden we raise from 3.2 to 3.7 or is just in the first quarter conference call you already noted that it’s going to be higher, you just don’t know how much, that’s why you didn’t say it.

Secondly, that in the Oil Sands, I was surprised that it looked like per unit costs have moved up from the first quarter about $51, $52 per barrel to about $55, $56 and with the operating environment is actually Nash Hash in the second quarter when we thought the unit cost would be going lower, not going higher. Anything going there that may make it somewhat unique in this quarter why they’re going up or that this is the power trend we will continue to expect?

Gary Heminger

First of all, I’m sorry if you missed it, at the end of the first quarter, we did make an announcement that in fact I think it was closer to the end of last year we made an announcement from the 3.2 up to 33.50 at that time. The change here to 3.7 is due to higher fabrication costs than we had expected and just some delays. What we have learned, Paul, since the major hurricanes of lost year, some of the fabricators had much longer delays than we had expected.

Paul Cheng - Barclays Capital

Gary, you said the last three or four months in certain or up currents or this has been happening so we should know it back in April? My guess is that I’m trying to understand that from April to now what may have changed.

Gary Heminger

First of all, I was explaining that we had raised the number from 3.2 up to 33.5. So just in case you missed that number. Secondly, as I was explaining, what we learned was the fabrication costs as you enter the last stages of a major project like this and look at the hours left to complete, there’s been no change in scope.

We’ve had great availability of workers and resource, it’s just the productivity and being able to hook up and commission the last pieces of pipe and fabricated vessels. So, that you’re right, has transpired over that four month period of time and that’s why I wanted to bring this to your attention today and not wait still the third or fourth quarter this year.

Now turning to Oil Sands Mining and to look at it on a cash cost basis, Paul, I think is the best way to really look at this and you are right if you look at Q1, the number was $34.49 on a cash operating expense per barrel process and went up to 35.63 here in the second quarter, but if you take the effect of foreign exchange out, there’s about a $2.15 negative effect of foreign exchange.

Our real number would have been down to $33.48. So, we have continued to show an improvement in our operating expense number taking out the foreign exchange from Q1. If you look at that same number last year, Q2 versus Q2 this year, we had gone from $44.75 down to about $35.63. So, we continue to make improvement on the Oil Sands operating expense.

Operator

Your next question comes from Faisal Khan - Citigroup.

Faisal Khan - Citigroup

Just a quick question on the Bakken you said you reduced your rig count from seven to three, but you still expect production to ramp up. Wondering if you could comment on why you think that’s happening and if you will continue going forward given maybe some rig efficiency? I have a follow up after that.

Clarence Cazalot

Faisel, I think what we’re seeing is we have improved some of our completion technologies. We’ve seen some better wells here of late. I think we’re just getting comfortable in the play. I think after 130 wells, our drilling efficiency is going up, completions are improving. So we’re starting to see some of the incremental efficiencies you expect, when you get voted down in one of these plays.

Faisal Khan - Citigroup

Just following up on the mining question on operating costs that the 215 FX effects that you guys talked about, that’s different from the FX charge you guys talk about in your tax line, is that correct?

Janet Clark

Yes.

Operator

Your next question comes from Pavel Molchanov - Raymond James.

Pavel Molchanov - Raymond James

A couple of point about the Bakken, are you guys looking to test the prospectively of the Three Forks being a potential separate reservoir from the Bakken as some other operators have done?

Clarence Cazalot

Yes. We’ve actually had one test of that, and we continue to evaluate all the different stringers in the Bakken, because as you maybe aware there’s three to five different stringers beyond the middle Bakken. Right now, all of our success is coming from the middle Bakken, but that’s the reason we continue to be encouraged about the 300,000 plus acres that we have out there, because we have opportunities in other reservoir lenses and also down spacing.

Pavel Molchanov - Raymond James

Then in terms of takeaway capacity, are you having to rail any of your production at the moment? Do you see any type of constraints over the next couple of years?

Clarence Cazalot

No, our crude handlers do a great job for us. We basically gather in central locations and then truck. One of the things that we’ve enjoyed an advantage of other operators in the area is we typically don’t see handling and quality discounts outside of the range of $5 to $7. I don’t think there’s going to be a constraint in the future.

Operator

Your next question comes from Mark Gilman - Benchmark.

Mark Gilman - Benchmark

Two quick ones, regarding the additional oil sands leases, is there any front end payment associated with that? How did that work?

Clarence Cazalot

Mark, this really was a part of the original agreements that had been put together between the AOSP partners. It was intended that these leases eventually would be included in the overall Muskeg River mine and Jackpine mine. There was a de minimus amount of investment to finalize that transaction, but it was very small in this deal, so nothing at all to be alarmed about.

Mark Gilman - Benchmark

Just one other one if I could. Janet, can you give us an idea, where we stand with respect to the tax loss carried forward on the Norwegian’s Petroleum tax. What your expectations might be as to when a current price level that would be absorbed?

Janet Clark

There’s two pieces to that the 28% and the 50%. We’ll run through the NOL protect to 28% regular tax after about $500 million of taxable income. We expect that we will do that this year. So we are anticipating that and making estimated tax payments related there too. I think that the subsequent $500 million will probably run through by early next year.

Mark Gilman - Benchmark

Janet, I didn’t understand what you said about the subsequent $500 million. What does that relate to?

Janet Clark

You’ve got the 28% regular corporate tax and the 50% special tax on petroleum. So we’ll continue to be shielded from that 50% through probably spring of next year.

Operator

Your next question comes from Paul Sankey - Deutsche Bank.

Paul Sankey - Deutsche Bank

Just a follow-up on tax, can you remind us what the tax is for Garyville to be started by the end of the year? How that will flow through the books?

Janet Clark

Basically, we’re set the deferred tax. So from a cash perspective it is protecting or shielding cash tax payments in the U.S. this year. It’s about 50% of the refinery addition costs. So, whatever that number ends up being to say its $3.5 billion, there’s the pipeline assets that aren’t considered, that’s $1.7 billion or so of cash taxes that would shield this year.

Paul Sankey - Deutsche Bank

Obviously, that means its 2009 effect, and there wouldn’t be any effects beyond this year shield?

Janet Clark

Well, we’d be continuing to depreciate, the assets next year and beyond.

Operator

Your next question comes from Ann Kohler - Caris & Co.

Ann Kohler - Caris & Co.

A question regarding, you certainly made a comment that you expected or didn’t expect to see an improvement really in some of those differentials until you started to see an improvement in diesel demand. Have you started to see that yet? Then I have a follow-up.

Gary Heminger

No, Ann. Unfortunately, the overall diesel demand market is still off in the 10% to 11% range and most of that, I’m talking about it would be over the road diesel. So, it appears as though it has bottomed, but we’ve not started to see an increase in demand yet.

Ann Kohler - Caris & Co.

Then you did have very nice increase as you mentioned in both your same-store sales and certainly you volumes. Was there anything specific? Was there a change in your strategy there that enabled you to capture that versus your competitors?

Gary Heminger

No. We did not have any change in our operating philosophy or pricing philosophy. I would just say that, we operated very, very well. The Speedway Supermarket Group had outstanding performers in merchandise sales in same-store gasoline sales, but we have not changed any of our pricing philosophies or operating philosophies.

Operator

Your next question comes from Paul Cheng - Barclays Capital.

Paul Cheng - Barclays Capital

Gary, have you given an update of what Detroit. I mean just given what we’ve seen in Garyville. Is there any indication to the Detroit spending level? Second question is for Dave.

With Angola, the exploration activity is winding down in for the next one or two years. Should we assume your exploration activity is going to be lower as a result and if not, where as to increase to sort of a fuel type gap? What region it’s going to be? Thank you.

Gary Heminger

First of all on Detroit and when we announced the budget in the January timeframe or so this year; we had announced that we were stretching Detroit out to mid-2012. At that time we raised the Detroit number to $2.2 billion, and we remain on that number. With all of the engineering being complete or finishing up, we still feel confident in that number.

Paul Cheng - Barclays Capital

Is this even after the latest increase in Garyville, in terms of you saying that just takes you longer and also more expensive that for the last minute to complete. So, is that already being taken into consideration of the $2.2 billion or that is not really?

Gary Heminger

No. We have taken that into consideration.

Paul Cheng - Barclays Capital

But that is the only happening after the first quarter and that one was increased at the end of last year.

Gary Heminger

The other thing to look at is the two completely different projects, Paul. In Detroit we’re building a lot of Detroit modular, where we’re building it offsite and bringing it in. We don’t have near the man hours, the productivity concerns you have in a major project like building, if you will stick building Garyville.

So we’re bringing many things in modular. Wherever they have the majority of the civil work done and I’ve been over this in great detail and I feel very comfortable with that.

Dave Roberts

Because we are very happy with what’s happened in Angola, but obviously looking forward to the future. As I’ve indicated in a number of talks, next year it’s kind of a coming out year for us and some of our other exploration activities. You’ll see us probably drill six wells in the Gulf, four exploration and at least two appraisals.

We’ll drill two wells in Indonesia on our pass value block and we’ll probably have at least three exploration wells in Norway around the Alvheim complex so, very busy year out of West Africa into the rest of the world.

Operator

Your next question comes from Mark Gilman - Benchmark.

Mark Gilman - Benchmark

Gary, I believe we had kind of a critical point regarding the GTL pilot around the middle of this year. Probably a little update on what’s happening there?

Dave Roberts

You’re absolutely correct. Actually we had hoped by the end of last year to reach a commercial declaration. As you’ll recall, I think we talked either at the very beginning of this year or the first quarter that the facility was delayed in completion. It was completed towards the latter part of last year, and we’ve been running our testing protocols there. Things are progressing nearly as we planned, and we’re going to be in a position at the end of this year to declare commerciality or not on that particular technology.

Mark Gilman - Benchmark

While I have you, what is Neptune actually producing right now?

Dave Roberts

It’s the circa 5,500 barrels a day net to Marathon.

Mark Gilman - Benchmark

Your expectation that can be sustained?

Dave Roberts

There’s always going to be a decline in the Gulf of Mexico, but we are certainly seeing pressure support for that production, but I would think that you could expect it to continue to decline to, say, circa 5,000 by the end of the year.

Operator

Your next question comes from Mark Caruso - Millennium Partners.

Mark Caruso - Millennium Partners

Just two quick questions, I’m sorry I got on late. Could you just give us your updated thoughts on the Marcellus and opportunity to expand there? The second is just sort of, you have the Marcellus, you have Haynesville want to see, if you buys have been looking at the Eagle Ford Shale at all? Thanks.

Clarence Cazalot

I’ll take the second one first, Mark. We’ve been pretty specific that we have highlighted or focused on just a few of the resource plays and presently the Eagle Ford is not in our plans. Although we recognize it’s very attractive to a number of industry players.

The Marcellus, just as an update, we’re actually building locations there. So we will actually start drilling this year on our acreage. We do believe there are opportunities to expand there, but obviously I’m not going to go into detail because it’s commercially sensitive.

Operator

Your next question comes from Doug Leggate - Howard Weil.

Doug Leggate - Howard Weil

I was actually trying to get my second question in. Cash flow, I just wondered if you guys could help me a little bit. The cash flow numbers were enormous. Can you help us with the moving parts as to how we ended up with well over $2 billion of pre-working capital cash flow and were there any cash tax payments in the quarter?

Janet Clark

Yes, Doug, there were cash tax payments in the quarter in Norway and not Norway. That would be in July. We have big cash tax payments to Libya, every month and we also had a tax payment in EG for the full year 2008 in the month of May.

Doug Leggate - Howard Weil

How did you get, Janet, from the net income line adjusting for depreciation up to such a huge pretax or pre-working capital cash flow number?

Janet Clark

Let me just get this…?

Clarence Cazalot

Yes, that’s probably detail that’s better left for when we file the Q later this week, Doug, when we give more than just a sampling of the balance sheet and cash flow statement.

Doug Leggate - Howard Weil

Okay, but there’s no one set of unusual item in there that you could highlight?

Clarence Cazalot

I don’t think there’s any, not one single item, no.

Operator

We have no further questions in the queue at this time.

Howard Thill

Okay. Thank you, again. Thank you, everyone, for listening in. We look forward to our next call and to the analysts meeting November, 18, in New York. Thank you and have a great evening.

Operator

That does conclude today’s conference. We appreciate your participation.

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