馬拉松石油 (MRO) 2010 Q3 法說會逐字稿

Good day and welcome to the Marathon Oil's 2010 third 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, sir.

Thanks, Cynthia and welcome to Marathon Oil Corporation's third quarter 2010 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 on its annual report on Form 10-K for the year ended December 31, 2009 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 note that in the appendix of this presentation, there is a reconciliation of quarterly net income to adjusted net income for 2009 and the first three quarters of 2010. Preliminary balance sheet information, fourth quarter and full year 2010 operating estimates, and other data that you will find useful.

On slide three, you'll see that our third quarter 2010 adjusted net income of $711 million was a 10% decrease from the second quarter of 2010, but a 63% increase from the third quarter of 2009. The decrease from the second quarter was largely driven by the effect of reduced RM&T segment income. The increase in the year over year third quarter earnings reflect improved business results, while most segments, the largest of which was the improvement in our downstream operations as a result of increased refining and wholesale marketing gross margins, and higher refining volumes.

Slide four provides details on the changes which resulted in the 10% decrease in second to third quarter adjusted net income. Pretax income increased for all three upstream segments, while RM&T saw a decrease. Income taxes and other items netted to a nominal negative impact.

As shown on slide five, we had an 18% quarter to quarter increase in E&P segment income. As a result of higher hydrocarbon sales and lower expiration expenses, partially offset by higher DD&A. Higher income from lower tax jurisdictions contributed to the lower E&P effective tax rate of 53% for the third quarter.

Slide six shows our historical E&P realizations and highlights the $1.13 per boe decrease in our average realizations, driven by the $0.73 per barrel decrease in liquids realization, while natural gas realization increased $0.08 per Mcf quarter to quarter.

Moving to slide seven, production volumes sold in the third quarter increased approximately 3% from the second quarter, and 9% from the third quarter last year. Third quarter production available for sale increased to 8% from the second quarter and over 3% from the same quarter last year. During the quarter, we were under lifted in Europe by 12,000 boe per day and over lifted in EG by about 4,000 boe per day. As of the end of the quarter, on a cumulative basis, we were 700,000 boe under lifted in Europe and 2.4 million boe under lifted in Alaska, with the rest of our operations being in a relatively balanced position.

Turning to slide eight, third quarter E&P segment income per boe increased 13%, compared to the second quarter of 2010 and was down slightly from the year ago quarter.

Slide nine shows the field level controllable costs for boe and remain relatively flat the last several quarter, while expiration expenses per boe dropped significantly this quarter, primarily driven by lower dry well expense in the Gulf of Mexico.

Turning to slide 10, the improvement in the Oil Sands Mining segment income, third quarter to second quarter, was primarily a result of higher volumes and lower turn around costs. The third quarter saw the return of a full quarter of operations at the Muskeg River Mine, as well as production from the Jack Pine Mine, which began a phase startup in the third quarter. The negative $61 million change in derivatives reflects the change from a gain of $53 million in the second quarter to a loss of 8 million in the third quarter.

For our downstream business, starting with slide 11, I will compare third quarter results against the same quarter in 2009 because the seasonality in that business. Third quarter 2010 segment income increased 80% from the same quarter last year. This was driven by higher margins and volumes, as well as better results at SSA. Partially offset by income taxes and other miscellaneous expenses.

Slide 12 provides the details for both volumes and margins in the refining side of this business. The quarter's year over year crude oil and other FEED stock costs were lower than the change in average price of LLS, primarily due to the increase in the sweet sour differential of $2.44 per barrel. Our total through puts were up over 21% quarter over quarter, primarily because of the Garyville major expansion. Our refining and wholesale marketing gross margin of $0.0921 per gallon is based on a total consolidated refined product sold of 1,681,000 barrels per day, or about 6.5 billion gallons for the quarter. We estimate that the Garyville major expansion contributed approximately $0.011 per gallon to this margin, which is in line with our previous projections based on the Mars 2-1-1 crack spread. To finish out segment reporting, the integrated gas segment income was $41 million, compared to the $24 million recorded in the second quarter 2010.

Slide 13 provides an analysis of preliminary cash flows for the first nine months of 2010. Operating cash flow from continuing operations before changes in our working capital was slightly over $3.5 billion, which is net of a $240 million pension fund contribution. Our cash balance was reduced by working capital changes from continuing operations of $560 million, primarily driven by downstream operations. However, we expect to generate positive cash flow from working capital in the fourth quarter. Year to date, cash capital expenditures have been $3.6 billion, disposals generated proceeds of $1.4 billion, dividends paid have been $526 million and debt repayments for the year have been $628 million. The cash balance at the end of the third quarter stood at slightly over $1.6 billion.

As shown on slide 14, at the end of the third quarter of 2010 our cash adjusted debt to total capital ratio was 21%. As a reminder, the net debt total capital ratio includes about $235 million of debt service by US Steel. We expect the overall corporate effective income tax rate from continuing operations to be between 49% and 54% for the full year 2010, excluding special items and the effect of foreign currency remeasurement of our tax balances. I'll now turn over the call to Clarence for some additional comments.

Thank you, Howard. As you've now seen, Marathon's operating and financial performance in the third quarter was strong, registering a 63% increase in adjusted net income over the same quarter of 2009. And while we talk primarily about earnings and margins and volumes, I want to credit our employees for their continued focus on safe, reliable operations, and controlling costs. We are, of course, disappointed by a more rapid than expected production decline at Droshky and Dave Roberts will address that in some detail with you in just a moment. I think it is important to view this one disappointment in the context of our overall solid upstream business, which was still achieved our promised 4% compound average growth rate in production from 2008 to 2011.

I know some have been concerned about a lack of visibility for our production beyond 2011, we are now able to forecast an additional 5% organic growth, and that's primarily liquids, from 2011 to 2012. As Dave will tell you in a moment, this growth is from ongoing projects, assets and opportunities in our portfolio. But we're not standing still. We continue it build our position for organic growth beyond 2012 in key assets like the Bakken, the Anadarko Woodford, and other unconventional liquids plays, and in new exploration areas like Poland and Kurdistan.

As for our 2010 capital and exploration spending, we expect to spend our budgeted amount of about $5.2 billion. While we won't announce our final capital plans for 2011 and beyond until our board approves them in January, I can tell you we expect ongoing CapEx to be in the $5.5 billion dollar per year range that we've outlined for you before. Consistent with what we've done in the past, we're continuing to high grade our upstream portfolio and may sell or joint venture certain assets to reduce risks and/or generate funds for redeployment. And to the extent we generate free cash flow in excess of our spending, our priorities continue to be maintaining a strong balance sheet and to return cash to our shareholders. Now I'll turn it over to Dave for more details on Droshky and our overall upstream business.

Thanks, Clarence. The success in delivering the Droshky project in July, well ahead of our planned date and 30% under the sanctioned budget, has been tempered by poorer than expected reservoir performance form the development. An inherent risk in the project of this type, reservoir compartmentalization, as well as an apparent lack of aquifer support have been larger factors than anticipated. The Droshky development was modeled based on a nearby analog field, Aspen, that we had direct evidence was in pressure communication with our field. Based on the pressure, flow and aquifer support history at Aspen, we anticipated similar reservoir performance at Droshky. The analysis we've done and continue to do shows the initial and subsequent engineering to be carried out in a professional and quality manner, and I'm at present hard-pressed to offer a could have, should have, would have scenario for this development.

As our pressures have fallen more rapidly than anticipated, we recognized our recoveries are going to lower and our volume projections will have to be modified as well. Droshky averaged net 21,000 barrels oil equivalent per day in the third quarter, and is estimated to average net 31,000 barrels of oil equivalent per day in the fourth quarter. As a result, we expect as reported our full year of 2010 upstream production to be approximately 413,000 barrels of oil equivalent per day. A testament, I think, to the overall strength of our global portfolio.

In 2011, Droshky is expected to produce an average of net 15,000 barrels of oil equivalent per day and we are guiding to $70 per barrel as a representative DD&A rate for the remainder of 2010. We'll give further guidance for 2011 as appropriate. Importantly, however, our portfolio is increasingly robust and as Clarence said, our ability to sustain our production growth is intact.

I've included slide 15 in the pack to reflect our previous commitment to production growth of at least 4% over the period 2008 to 2011, a commitment we will meet. To address some apparent confusion over this slide, we consistently measure our production projections based on our ongoing business, removing the effects of A&D. This methodology ensures or business remains focused on profitable growth and continued portfolio management for value. 2008's upstream production, excluding divestitures, was approximately 380,000 barrels of oil equivalent per day and with our projected growth actuals gives a CAGR of 4.5% for 2008 through our mid point 2011 projection.

More importantly, turning to slide 16, we show that we expect production in 2012 to grow by 5% over 2011, with a majority of this growth being liquids. The production increases will come from our existing positions in Canada, the Bakken and Angola, as well as beginning contributions from new positions we're taking in both existing and new unconventional oil plays in North America. And, we are positioning the Company for further growth into the future.

Turning to slide 17, I'm pleased to report that Marathon has, in 2010, increased its acreage in the Anadarko Woodford play, mostly in the liquids rich portion to almost 75,000 acres. With further line of sight to over 100,000 acres in the near term. We've also acquired over 120,000 acres in the Niobrara play in the DJ Basin of Colorado and Wyoming. In addition, we've increased our Bakken position to almost 400,000 acres.

As we said before, one of the attractions of these unconventional plays is the ability to dial up or dial down activity as needed. The large and growing number of future locations we list on this map is a great well stock, one that today we're using eight rigs to prosecute, but we could expect the number to potentially double in the next two years. And as opportunities remain, our acreage acquisitions continue in all these plays, as well as others in North American unconventional liquids. We are in many ways transitioning the portfolio. Balancing the large projects we have in our international business, and those we expect to deliver from impact exploration, with repeatable and sustainable unconventional businesses, largely in North America.

Finally, on slide 18, I highlight our most recent impact exploration play, the Kurdish region of Iraq. The opportunity offers both near and long-term potential to Marathon with two wells currently drilling in our license areas, the potential for production as early as 2016 is achievable. And we believe a minimum success case could yield 50,000 barrels of oil equivalent per day net by the end of this decade, with total exposure for Marathon of over 400 million barrels of net resources. Also in the area of impact exploration, many of you will certainly be wondering about our Indonesian program and our progress there. We continue to drill the Bravo prospect, a high risk but large structure on the passing guiding block. We have been slowed at first because of mechanical issues on the rig which have been remedied and then by geologic challenges, which similarly impact the Romeo prospect suspended in September. On Bravo, we are now roughly at half the well's total depth at this point and expect the conclusion of this well later this month.

All in, it's a quarter of considerable success tempered by Droshky. What we are most pleased with is the resilience our base of assets provides us in terms of meeting our goals and the continued evolution of our business as we add more exposure to unconventional plays, especially those rich in liquids and new impact areas in exploration. Both of which add confidence to our projection that we can sustain 3% to 5% growth well beyond 2012.

Thanks, Dave. Appreciate those comments. As a reminder, before we turn it over for questions, to accommodate all those who wish to ask a question, we ask you to limit yourself to two questions. You may reprompt as time permits. With that, we'll now open the call to questions, Cynthia.

(Operator Instructions) Our first question will come from Doug Leggate with Banc of America Merrill Lynch.

Thank you. Good afternoon, everybody. I'm going to try a couple of questions both related to production at Droshky. The first one is I guess as you look at you are production guidance, it really hasn't changed a heck of a lot since your strategy date, on the additional color in 2012 is appreciated, but one of the key things that we watch is the margin associated with these borrows. Particularly in light of Droshky, if we look at your margin in the US this quarter, it basically traveled. Some help from exploration, but when asked the margin Droshky played a part. As you look at your incremental production growth over the next year or so, the top line growth is one thing, but you have a portfolio dominated by very low margin assets, Libya, Norway, EG Gas, I guess. What is the top line growth, how does it translate to margin at the bottom line in terms of how you see the contribution from Oil Sands, Angola and so on? And I have a follow up.

Doug, I think obviously with the subtraction of the Droshky barrels, the key driver next year is going to be largely Oil Sands Mining, so you would expect that margin to be a big driver from 2010 to 2011. But we do have substantial growth out of the Bakken as well, which are better margins, but obviously that is going to feature. From 2011 to 2012, what we would say is that our -- top to bottom, the top five growth areas year to year are going to be Angola, the Woodford play, Bakken, Ozona and followed lastly by Oil Sands Mining. Four of those five years we think are going to be much stronger. 2010 to 2011, I take your point, but 2011 to 2012 and beyond, particularly as we view the strengths of the liquids unconventionals in the United States, we think we're going to have pretty good margin growth as well.

Great stuff. My follow-up then is on Droshky. Obviously, this was always going to be a very high decline asset, Dave, obviously a little faster than you thought by the sounds of things. Can you give us an idea what your trajectory is through the year next year? What is it right now? What do you expect the exit rate 2010 to be and what's your expectation through the course of 2010? I'll leave it there.

Well, I think if you think about this thing, like I said in the fourth quarter being 32,000 barrels per day net, that 31,000 barrels a day net gives you an idea of we expect the exit rate to be in that neighborhood. And so the 15,000 barrel a day average next year should give you an idea of with a typical 10% to 15% Gulf of Mexico decline, how this thing is going to play out over the year.

When does the fourth well come on, Dave?

We should get that work over sometime in the first quarter, so my guess February or March.

All right. Thanks very much.

Blake Fernandez with Howard Weil has our next question.

Hi, good afternoon. Thanks for taking my questions. My question is on the Bakken, I know you have six rigs running currently, that's obviously going to become an increasing factor in your production growth going forward. What opportunity do you have to increase that rig count, if any?

I think we have opportunities. What we have said consistently is that we manage our rig count in these plays in order to maximize the return potential of them and of course the macro conditions in the Bakken are pretty significant. There's -- the basin is now running close to 150 drilling rigs. I think Marathon has said consistently, we think this is a basin that is more comfortable in the circle 100 area and so that pressure is putting a lot of cost pressure and you've seen this from some of our competitors in the basin in terms of being able to acquire and the cost of services. So, we're going to be very prudent about trying to accelerate our growth there. We're happy with the growth that we're getting and right now, we're very comfortable with the logistic service profile that we have out there in terms of being able to deliver our program. So, building rate is a secondary concern to us.

Okay. Great. Thanks. Then on Clarence's comment regarding a strong balance sheet and returning cash to shareholders, obviously we've got a fairly hefty divestiture coming here in the fourth quarter with the Minnesota downstream. I'm just curious, any ideas on uses of cash, obviously potential increases of dividends with share repurchases on the table and maybe M&A?

I would say M&A is not on the table, Blake, but I think certainly as we've said, dividend is a very high priority for us. As you know, we increased our dividend early this year. It's considered every quarter by our board and it is a very high priority for us. Stock buy backs we have done in the past, I wouldn't rule them out in extraordinary cases where we have considerable excess cash, but at this point, obviously, we have an outstanding capital program going forward, driving the organic growth that Dave talked about, that's our first priority and then again, to the extent we have cash in excess of our spending, we'll look to distribute that to shareholders.

Okay. Thank you very much.

Moving on to Evan Calio with Morgan Stanley.

Good afternoon. I have a question for Dave, if you could walk me through Indonesian exploration, maybe give us some color on why Romeo is suspended if you intend to reenter the well, and if we look out towards 2011, any other wells in Pasangkayu and the expected spud dates for -- in your your Bone Bay Block.

Okay, Evan, I guess what we would say without getting into too much technical detail, what we brought into in Indonesia is essentially a rubble field. So, you can imagine an unconsolidated formation of fairly large rocks and this is somewhat unusual to be below the surface, but it's roughly 6,000 feet of depth is where we've encountered this. That's caused some of our drilling concerns as we move forward. We basically moved off of Romeo and will return to that prospect, probably in a different well bore. We believe we're past it in Bravo now and we will be back to normal drilling. The next couple of weeks will tell that tale. We've learned a lot about how to deal with that, and so we will move forward.

For 2011, we have two slots on the rig that we have contracted. One of the things that we will look at is whether we will drill additional wells around Bravo, depending on what the results are. We certainly would anticipate going back to Romeo with one of those slots, and we look at getting into Bone Bay either late next year or early 2012.

Okay. And then a question, similar exploration question, with regard to Iraqi Kurdistan. I was wondering if you could give me some timeline. I believe the [tush 1], I think it was spud in October, is your expectation that's a February result and I'm not sure what [surrang] when the expected TD is there or any other exploration with your other two blocks there.

We basically started the first well, or our partners did in July, August, and as you called the last one was started in October. It's early days for us in terms of the information we're getting, so it would not be proper for me to comment on how long it's going to take. These things tend to progress in a very prudent fashion. We'll be able to give more color as we get a little bit more familiar with it on a go-forward basis. On the two blocks that Marathon has, we've got a three-year period of time where we'll be doing geologic studies, seismic, before we actually get on the ground drilling our wells. Again, early days for us, but we are pleased that we actually have two wells going down in brand new exploration blocks.

Great. Thanks.

Moving on to Edward Westlake with Credit Suisse.

Good afternoon, everyone. Just maybe on firstly on volumes. Are you able at this point, given the number of well locations that you've identified in the presentation, to kind of a give a long run volume for each of the three plays that you are focused on in the North American business, Niobrara, Bakken and Woodford?

Well, Ed, what we've tried to do there and to try to make our presentations more consistent with others, we've used some industry averages for the resources per well that are available in these plays. I think we've been pretty consistent on projecting where we think the Bakken is going to get to over the intervening period of time, so that's the only one that we're comfortable, right now, projecting volumes on. Niobrara is just way too early. We won't actually be getting out there until next year and drilling it. We would hope that we would be able to build the same type of profile that we have in the Bakken, but again, it's too early to try to promise that kind of thing. And again we've got our initial wells going down in the liquids rich portion of the Woodford, so too early to project where the production growth is going to go there.

Okay, great. Just as a follow-on a separate area, 1.2 billion barrels, I think, unrisked in the Gulf of Mexico. Can you talk about your plans to get back to work there and how excited you are about your portfolio in the Gulf after Droshky?

Yes, I think we are still very excited. I think one of the things that is an obvious question is does Droshky shake your confidence and the fact of the matter is that the mining sands plays segment as they are in Droshky and to a similar degree in Neptune, have given us a lot of information in terms of how we should evaluate these things on a go-forward basis, but our view is that we still have good prospects, 20 plus that we need to drill in the Gulf of Mexico. We'll see what they look like in terms of being continuous or discontinuous and we remain very upbeat about the potential that we have in that portfolio.

We have submitted regional plans to the government to start the process of getting back to work and specific repermits for our Innsbrook, which is the well that we suspended at the start of the moratorium, as well as some of the work that we need to do to permit Ozona, because that is obviously something we need to do in terms of getting that development ready to roll into 2011, and we'll follow suit with other permits. I think the other thing that we would say is the rig that we have under contract is in the Gulf, under going acceptance trials and we'll see how that rig does in terms of its performance and our view is that we would like to be able to get back to work shortly, but a lot of that depends on how the permitting goes. And the acceptance trials of the Noble Jim Day.

Thank you.

And Paul Cheng with Barclay's Capital has our next question.

Thank you. Dave, before I ask my two questions, can I just clarify, I may have misheard, the Droshky, did you say $70 barrels or $17, one seven?

7-0.

7-0. So, you expect Droshky you're only going to recover about 12 million, 13 million barrel?

We have taken a write down, yes, Paul, we had 26 million barrels and right now the proved reserve on the books we're showing 14 with some upside for a water flood case and the well work over that we're going to do in February.

Okay. All right. On Droshky and on the tune that you say you learn a lot. When you look back as in hindsight, is there any difference that you may have done in terms of deevaluating on those two fields or in your development designs?

No, Paul, I think I was pretty clear. I've -- we've obviously looked at this pretty closely leading up to this decision, and subsequently as the well rates have fallen off and we think the use of the analog was a correct thing. Obviously, the one thing that could have been different here is if you had the ability to do some production testing earlier, but we didn't have that option, and so if you had that capability, that would have been a way to figure this out early, but again, I think what we did what we could do and we're pretty comfortable with the technical work that was done here.

Okay. A final question on the unconventional shale plate for the three, can you give us the number of rig for 2010, 2011, 2012 either by basin or together?

Well, I think what I talked about is we're currently running six in the Bakken and my view would be that, that number is going to be consistent, either similar to the question that I answered from Blake a little bit earlier, because we're comfortable with that as a pace. We have two running in the Woodford. That number could easily double or go higher and the Niobrara will obviously start with one next year, and depending on success, it could go dramatically higher. As I said, if you take the eight, I could see that easily doubling over the next couple of years across the three basins.

So, Dave, when you talking about --

We'll need to go to our next caller. You can requeue. Thank you.

Moving on to Faisel Kahn with Citigroup.

Good afternoon. On the 2011 to 2012 growth rate, looking at the 5%, what is your expectations for Norway? Because I thought that would be a -- we start to see declines in that field in Alvheim and Vilje in that time frame. Looks like maybe that's keeping pace.

Well, Faisel, we're running circa 80,000 barrels a day net out of our Norway businesses. We are going to see declines there, but they are going to be minimal, 4% to 5% a year. So, those will be declining businesses over the period that you're talking about, so they will not be added to our production, but certainly not a significant decline, either.

Okay. Great. On the refining side of the equation, were you able to take advantage of the lower -- the wider Canadian differentials in the quarter and also the diesel exports?

Yes, Faisel, we were. In fact, if you look at the differential, I believe the differential this quarter versus same quarter last year was about 244 better, I would say a good portion of that have would have been the Canadian.

Okay. Great. Diesel exports?

And diesel exports, yes, we certainly have -- we are participating and sharing in the market of diesel exports with the, with the new GME project and being able to meet the European spec. We have been a big player in the diesel export market and we expect to continue.

Okay. Thank you.

Mark Polak with Scotia Capital has our next question.

Quick question for you on the oil sands with expansion coming on line right now and shale docking and shifting a bit more to the In-situ side. Could we expect the same from you, would we maybe see -- hear a bit more about Namur and Birchwood as we head out in the next couple years? And as a follow up to that, would love to hear your outlook, both short and long term, for heavy differentials and how that plays into decisions on developing those assets or future downstream opportunities.

Mark, I'll let Gary speak to the differential outlook because obviously from our comments earlier, we're bulls on liquid price, so we believe that these plays are going to be -- continue to be viable and valuable on a go-forward basis. I think you're exactly right. One of the things that we're going to be doing this Winter is engaging in a pretty thorough deliniation drilling program around our Birchwood assets, so we'll have some information that we will put in our reservoir team's hands beginning the late Winter, Spring of next year to determine what we actually have there. We think a, it's a hundred percent, we think it's a pretty good prospect from what we have seen once we get some of the drilling done, we'll be able to see if that actually is going to feature heavily on our plans on a go-forward basis. We're pretty keen to pursue the In-situ agenda in Canada as well.

I'll take the differentials. Mark, if you go back and look at the first and second quarter this year when the industry was filling up the keystone pipeline and the [invert] pipeline, there is a lot of incremental demand. That incremental demand, in our opinion, helped to narrow the differentials. We expect going forward and we don't see any pipeline expansion or really market expansion beyond those two pipelines probably for at least three to four years, depending on when any expansion might go south of the Wood River fishing market. But we would expect with additional production coming on and you have to look at the production, how much of it is going through an upgrader in Canada versus how much will be a dill bit that comes through the market. We would expect those differentials to widen back out as we go forward.

And is it percentage terms, is there something in your view a good assumption long-term?

Well, you look here recently, they've been in the 15% to 20% mark here recently and take you back a few years and they were north of 30%. I believe the markets have opened up with a couple new pipelines and more coking being available in the Midwest that I don't see those wide spreads that we had back in the 2007, 2008 period, but I I certainly think you'll be in the 20% or a little bit greater type of a discount.

Thank you very much.

Moving on to Pavel Molchanov with Raymond James.

Thanks for taking my question. First, just kind of a macro point about the gulf, we've seen a mixed bag of youth from operators about what they think will happen to future cost because of the spill. Just wanted to get your perspective on this.

Well, Pavel, I don't think there's any question that we think costs are going to go up. There's going to be costs relative to protecting against liability, whatever kind of insurance consortium or individual insurance is required. There's no question that the participation in some of the needed containment consortium is going to add cost to our business, but I think more importantly is right now, the lack of understanding for what the pace of available permits is going to be. We're going to put more time into the system and time is money in the Gulf of Mexico, so I would anticipate the costs are going to go up. The real question is for us is we're anxious to see the rules and the activity settle so we can understand what that is, because obviously that's going to impact our future decisions in that problem.

Okay. And then on Kurdistan, I realize it's early of course, but can you give a sense of the kind of infrastructure you would need if you ultimately moved into development mode?

I think there's a -- there's actually more oil field service companies in the province than is probably broadly known, but I think what we would say is we're hopeful that as companies like Marathon make an entry into this play that more companies that provide oil field services will -- and larger companies, will flow into this arena giving operators broader choices and service providers and also cost options. So, that's part of the issue around infrastructure and one that we're not you uncomfortable with now, but certainly we would like to see improve, just like we do in all the basins we like to operate in. I think the key thing is going to be export capacity and how ultimately Kurdistan either accesses the pipelines in broader Iraq or comes up with alternatives that will allow them to secure their own export routes. There's no question that all this stuff is going to continue to go north to the Turkish lines that run across, that's been the historic province there, certainly one that we support, but that's going to be the critical issue in terms of developing oil and gas export infrastructure.

Okay. I appreciate the call. Thanks.

(Operator Instructions) And we'll move on to Mark Gilman with The Benchmark Company.

Good afternoon. Dave, can you give us an idea what your incremental acreage costs in the unconventional plays are running? You mentioned the 120 in the Niobrara, some additional acreage in the Cana and Bakken as well.

Mark, we've -- without giving too much color, we've basically been able to access our acreage or additional acreage in the Woodford sub $2,500 an you acre and in the Niobrara, we're still under $1,000 an acre. So, both plays we're very comfortable with what we're doing in terms of acreage acquisition there.

Okay. On Kurdistan, have you paid the $165 million and is your deal at all sanctioned by the Iraqi government?

I'll answer the second first, it's our view that the Kurdish regional government has the authority under the Iraqi Constitution to have entered into this agreement and it's an agreement that I signed with the Prime Minister of the Kurdish Regional Government. We expect to ultimately that these contracts will be consistent with Iraqi law, reviewed by a central commission, but we also have high confidence they'll ultimately be approved. We have not yet made the transfer of funds.

When will that occur?

Contractually we're obligated to do that within a 90-day period of time. So, we would expect to do it by the end of the year.

Let me sneak in just one more quick one. Block 31 in Angola, there are two prominent players in that block, both of whom Total and Exxon Mobil, are attempting to divest their interest. Do you know what's going on there?

I think I would call [Paris or Los Colinas], but what I would say is their percentage is probably relative to the size of their aggregate portfolios is not as meaningful as the 10% block 31 is to us. Still an outstanding development on track in terms of being able to deliver it in 2012 and there's not too many 150,000 barrels a day developments that are available in the world today.

Okay. Thanks, Dave.

Now a follow-up from Edward Westlake from Credit Suisse.

Yes, just a follow up on that Angola question. I think it is some of the sub-C contractors are saying there are some delays for the next phases of the development, so the initial phasing might be outstanding, but the second phases might be slower? Can you make any comments on that? And just the under lift in the quarter, do we have a dollar million number for that? Thanks.

We don't have a dollar number on the under lift. What we give is the volumes, Ed, that we went through in the speech itself. I can go through those again offline with you.

No worries.

With respect to Angola, we would direct any questions about the pace of future developments to BP. We are very satisfied with what they are doing in progressing the first development, and what we would say is that they have a very sharp eye on future costs and obviously trying to manage the existing development, future developments in terms of what the existing cost environment is.

And maybe if I could just sneak one more in, just on the strategy in the upstream, are you signalling more strongly a non-shore focus as opposed to global exploration with these moves?

I think what we've said is we -- we have proven our capabilities in the Bakken. We needed some balance in terms of creating this fly wheel of activities that you get in the unconventionals. We like the fact that there's a number of these that are liquids focused in the United States, particularly in areas that we're very comfortable operating in and we think it provides an appropriate balance, not only to our large scale projects internationally, which are, as you know, huge cash flow drivers and earnings drivers for our business, but we think by signalling our intent to go into places like the Kurdish region of Iraq, we've committed to the fact that we're going to be impact exploration players as well. Marathon is still committed to the track that we've said consistently is we think we can deliver value through multiple channels.

Ed, this is Clarence. I think what you're seeing is our intent to build what is a defined, sustainable, predictable, as Dave said, scalable portfolio driven by these unconventional resource plays, primarily domestic, but at the same time, have a component of our activity around big E exploration, which a good deal of which will be Gulf of Mexico and international, that gives us the opportunity to drive impact value through success there. So, it really is complementary. They're not mutually exclusively. We think they are complimentary of one another.

Thank you.

And now a follow-up from Doug Leggate with Banc of America Merrill Lynch. Mr Leggate, please go ahead.

Sorry, folks. I had my mute button switched on. Can you hear me okay?

We can hear you, Doug.

Great stuff. I had a follow-up on one of the comments that Dave made on the Droshky if you don't mind. Dave, $70 DD&A. Looks like about 5 million barrels of reserves next year produced on your target. If you had 25 million barrels that you've now written down to 15, your gross was originally 60, what's the new gross?

Yes, I don't have my mute button on, Doug, but I'm actually -- the, the net resource that we're focused on right now is about 19 and we would compare that to 34, so we'll have to get back to you on how that compares to the 60 previous.

Okay. So, if we apply a 25%, let's say decline in 2012, you'll have pretty much written off the bulk of the expenditure. I'm just trying to get a feel for what the DD&A looks like in the future production years of this field.

Yes, we'll get back to you on it, Doug. I think the issue is that we have some incremental investments that we want to make, both with this work over that we're going to do and then we are going to try to implement a water flood out there as well that will change the core quarter DD&A next year. So, we'll give some more color on that, as I indicated earlier.

All right. Thanks, Dave.

Moving on to Kate Minyard with JPMorgan.

Hi, everyone. Just a quick questions on your production guidance range for 2011. It just looks like between the low side and the high side, it's a bit of a wide range. Was just wondering if you could give us a little bit of insight into maybe some of the factors driving the width of that range, and I guess more specifically, whether there's anything we should be looking for earlier in the year that would help us narrow that range or if you just expect it to narrow as the year progresses. Thank you.

Kate, I think we tend to always give ourselves a little room so we can look at how projects are going to be delivered. But I think the critical thing to think about for next year, since it's largely going to be driven by Oil Sands Mining, the real issue is when the upgrader is delivered for the project and when do we get through the shakedown period of time in terms of when that thing actually starts ticking over. Just to give an example, towards the latter part of this year, the new mine up there, we think could produce anywhere on a gross basis of bitumen between 10,000 and 20,000 barrels a day. That's a pretty big range just because its a start up process and as the upgrader comes in, the real question is how quickly do you step up to that hundred thousand barrels a day there. I would say once we get a little more clarity on that in the first quarter of next year, my guess is the ranges will start coming in because there's not a lot of other moving parts.

Great, thank you.

Moving on to [Xavier Cronin] with Energy Intelligence Group.

Yes. I wanted to confirm, 26 million barrels for Droshky on the books you had originally and you are now showing 14 million, is that correct?

Reserve, yes.

And that's a million barrels per day?

Million barrels equivalent.

Okay.

Reserves are in those numbers.

And also on the diesel issue, just real quick, could you talk more about the GME project meeting the Euro specs regarding your diesel exports, please? Thank you.

Yes. Prior to GME's new construction, our diesel units within all of Marathon's refining, we did not have the ability to meet the European spec and now we can do that and now we're exporting a significant amount of our variable diesel to the foreign markets.

Does that include ultra low?

Ultra low would be a part of that, yes.

Okay. Thank you.

We only make ultra low out of Garyville, but there's also an additional spec to be able to meet European specs.

Thank you.

A follow-up from Paul Cheng with Barclay's Capital.

Hi, Dave, on your production guidance for 2012, what's the underlying base [decline here] that you're using?

Paul, we've not changed from our views that we can maintain a 6% to 8% base decline across our assets (Inaudible).

And when you talk about the 2012, I think you on the order of the contribution to the production of Angola, Woodford, Bakken, Ozone, and then Oil Sands, do you have a number that you can tie to each region that the five that you mentioned, what is the production growth that you expect for 2012?

Well, I think Paul, we typically would shy away from that granularity, but just broadly I would say they're all in the 5,000 barrels a day equivalent range per day. And the only reason I'm giving you that kind of guidance is because it kind of goes to what we're talking about here, the depth and breadth of our portfolio where we aren't overly dependent on single projects.

All right. Thank you.

And a follow-up from Mark Gilman with The Benchmark Company.

The impairment, folks, that was taken in the quarter, does that mean you're no longer pursuing the GTL opportunity?

GTF?

GTL, Howard.

Okay.

Our gas to fuels project and we continue to pursue that technology in terms of the research that we're doing in our lab, but basically what we've gone into and I think I've talked about this previously is we're into more of a design phase of what it would take to actually scale this up, so we have not abandoned the technology.

Okay. Just one other one, if I could. The relationship or I guess I should say the net bitumen production guidance for the quarter, in the 28 to 34 range, I guess I have a little bit of trouble understanding that operationally if you're not going to be selling any bitumen and the upgrader is not going to be coming on until some time early 2011. Has anything changed in terms of your strategy on this?

No.

Well, Mark, what we've said is the upgrader can actually take more bitumen than we're capable of mining from the base mine, from the Muskeg River Mine. So, that's why it's ramping because because we're taking what bitumen we can to the initial upgrader and then as the second upgraders comes on stream, we will ramp up the mining operation even more, which is also why Shell came out a couple weeks ago and we reiterated in our release, that we see the upside of somewhere around 85,000 barrels a day of mining capacity, because we think the upgraders have that much more capacity in them.

Okay. Thanks.

We have no further questions in our queue at this time. I would like to turn the conference back over to you, Mr Thill for any closing remarks.

Okay. Well, Cynthia, we appreciate it and thank you all for your interest in Marathon and wish you a great afternoon.

This does conclude our conference call today. We would like to thank you for you participation.