馬拉松石油 (MRO) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Marathon Oil Corporation first-quarter 2011 earnings call. My name is John and I'll be your Operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

I will now turn the call over to Mr. Howard Thill. Mr. Thill, you may begin.

Thanks, John, and good afternoon, everyone, and welcome to Marathon Oil Corporation's first-quarter 2011 earnings webcast and teleconference. 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 2 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 31, 2010, and subsequent Forms 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 to this presentation is a reconciliation of quarterly net income to adjusted net income for 2010, and first quarter of 2011, preliminary balance sheet information, second quarter and full-year 2011 operating estimates and other data that you may find useful.

Slide 3 shows that our adjusted net income of almost $1.2 billion was 52% higher than the fourth quarter of 2010, and 276% increase from the first quarter of 2010. Slide 4 shows the components of the increase in adjusted net income compared to the fourth quarter 2010. The increase from the fourth quarter was largely driven by higher commodity prices and higher refining and wholesale marketing gross margin, partially offset by lower E&P production sold as a result of the suspension of Libyan production operations and the down time associated with the Droshky side track completion during the quarter. Pre-tax earnings increased in all segments.

Slide 5 shows the various impacts which led to a 35% increase in E&P segment income, higher liquid hydrocarbon prices and lower DD&A were partially offset by the lower sales volumes just discussed along with higher income taxes. Slide 6 shows our historical price realizations. Our first-quarter average price realization increased $9.39 per BOE, compared to the fourth-quarter 2010. Our liquid hydrocarbon realizations increased $14.29 per barrel, compared to an increase of $9.36 per barrel increase in the NYMEX prompt WTI price. Above -- about 65% of our global liquid hydrocarbon sales volumes were priced off of Brent, which increased substantially more than WTI during the quarter.

Slide 7 shows the production volumes sold in the first quarter of 2011 were down 4%, compared to the fourth quarter of 2010, to 400,000 BOE per day, while production available for sale decreased 5% to 398,000 BOE per day. As previously noted, the largest contributor to these decreases was the suspension of Libyan production and the down time associated with the Droshky sidetrack completion during the quarter The difference in sales volumes and production available for sale was the result of an overlift for the quarter of approximately 975,000 BOE in the UK, Norway and Alaska, offset by an underlift of 782,000 BOE in Libya and EG.

Slide 8 demonstrates the 18% growth in E&P production available for sale since the beginning of 2010, excluding Libya. For the full year 2011, we now expect production available for sale to be between 345,000 and 365,000 BOE per day, which includes the first-quarter production available for sale from Libya, but excludes any additional Libya production for the year. This is about a 7,000 BOEPD increase to our previous guidance when excluding Libya.

Turning to slide 9, field-level controllable costs for BOE returned to trend from the higher fourth-quarter level when we had higher workover costs in the Gulf of Mexico. 2010 domestic field-level controllable cost was $7.10 per BOE, and for 2011 we expect it to be in the range of $7.25 to $8.30 per BOE. In international E&P, the 2010 field level controllable costs were $2.95 per BOE, and for 2011, we expect a range of $3.20 to $4.40 per BOE, with the largest portion of the increase due to the loss of the Libya production.

Exploration expense increased as a result of the approximately $159 million in dry well costs during the first quarter. This is attributed to costs associated with the Gulf of Mexico Flying Dutchman well and the Romeo prospect in Indonesia which encountered water-bearing carbonates. In March 2011, we completed our evaluation and determined the options to develop the Flying Dutchman were not viable.

Total expenses per BOE as shown on slide 10 increased $0.59 per BOE from the fourth quarter, primarily driven by the higher exploration expense and DD&A, partially offset by lower field-level controllable costs. First quarter E&P segment income was $18.54 per BOE, a 43% increase compared to the fourth quarter of 2010, again, primarily due to increased realizations.

Turning to slide 11, and Oil Sands Mining, the segment income for the first quarter was $32 million, an increase of $23 million from the $9 million earned in the fourth quarter 2010, largely driven by higher synthetic crude realizations. Marathon's first-quarter 2011 net synthetic crude sales which is bitumen after upgrading, including blend stocks from the AOSP mining operation, was 37,000 barrels per day, compared to 38,000 barrels per day in the fourth quarter. Average realizations increased $10 per barrel from their fourth-quarter level.

Turning to slide 12 and the Integrated Gas segment. First-quarter segment income was $60 million, an increase of $27 million from the fourth quarter of 2010. As a result of a turnaround in the fourth quarter of 2010, methanol sales volumes increased.

Moving to our Downstream financial results, as noted on slide 13, RM&T's first-quarter 2011 segment profit totaled $527 million, compared to a $237 million segment loss in the same quarter last year. Because of the seasonality of the Downstream business, I will compare our first quarter 2011 results against the same quarter in 2010. Primary factors contributing to the increased segment income for the first quarter 2011 included a wider sweet/sour crude differential, increased sales volumes and lower manufacturing costs resulting from decreased planned turnaround and major maintenance expenses compared to the first quarter of 2010.

In addition, during the first quarter of 2011 the Company was able to take advantage of the wider than normal crude oil differentials between WTI and other light sweet crudes such as LLS and Dated Brent, which resulted in relatively lower crude oil acquisition cost versus the comparable quarter last year. Sales volumes increased as a result of higher first-quarter 2011 refining throughputs compared to the same quarter in the previous year.

Primarily because of operating a fully integrated Garyville refinery for the entire first quarter 2011, our total throughputs were up approximately 20% quarter-over-quarter, in spite of the December 1, 2010 sale of the St. Paul Park refinery. In addition, some other work which we recently completed in our refineries to enhance the efficiency of our fluid catalytic cracking units also improved last quarter's results over the first quarter 2010, as well as the higher prices we realized in the first quarter of 2011 on our FCCU gains.

Our manufacturing and other expenses were lower in the first quarter 2011 compared to the corresponding quarter last year primarily because we had much lower planned turnaround and major maintenance expenses and other major downstream project costs in the current quarter. Partially offsetting these positive improvements quarter-over-quarter, the average LLS crack spread decreased from $3.03 per barrel in the first quarter 2010, based upon 57% of our production in the Midwest and 43% in the US Gulf Coast during that quarter, to $0.71 per barrel in the first quarter 2011, based upon 53% of the production being in the Midwest market and 47% in the US Gulf Coast. In addition, our average wholesale price realizations did not increase as much as the average of the spot market gasoline, distillate and 3% resid prices used in the LLS, 6-3-2-1 crack spread calculation in the first quarter 2011, versus the comparable quarter last year.

Total refinery, crude oil throughput averaged 1,114,000 barrels per day in the first quarter 2011, compared to 1,003,000 barrels per day in the same quarter last year. Total throughputs were 1,321,000 barrels per day in the first quarter 2011, compared to 1,100,000 barrels per day in the first quarter 2010. Speedway's refined product and merchandise gross margins was about $23 million lower in the first quarter 2011 compared to the first quarter 2010. This decrease was primarily due to a reduction in the number of outlets as a result of the Minnesota asset sale in December 2010. On a per gallon basis, Speedway's gasoline and distillate margins increased from $0.1195 per gallon in the first quarter 2010, to $0.1308 per gallon in the first quarter 2011. Speedway's same-store merchandise sales increased approximately 2%, while same-store gasoline volumes were comparable in both quarters.

Slide 15 provides an analysis of preliminary cash flows for the first quarter of 2011. Operating cash flow before changes in our working capital was $2.2 billion. Our cash balance was increased by working capital changes of $436 million. Capital expenditures during the quarter were approximately $1.1 billion. Proceeds from disposals of assets were $212 million, and dividends paid totaled $178 million. The slide also reflects the financing activities carried out during the quarter in anticipation of the spinoff of our Downstream business at June 30 this year.

Slide 16 provides a summary of select financial data. At the end of the first quarter of 2011, our cash adjusted debt to total capital ratio was 10%, a 4 percentage point reduction from the fourth quarter of 2010. The effective tax rate for the first quarter of 2011 was 43%. We expect our effective tax rate for the year to be in the range of 42% to 47%. As you may recall, these tax rates reflect a full year as an integrated Company. Both the quarter and estimated annual rates are lower than expected, primarily due to the suspension of production operations in Libya, where as you know our effective tax rate is over 90%. The inclusion of only 2 months' Libyan income and associated taxes in our estimated annual effective tax rate accordingly reduced the effective tax rate applicable to the first quarter. With that, I will turn it over to Clark Cazalot for a few comments.

Thank you, Howard, and just a brief comment. By the time we announce second-quarter results, we expect to be separate Companies. So this will likely be our last earnings conference call as an integrated Company and so I want to take the opportunity to thank Gary Heminger and the entire Downstream team for the outstanding contributions and results that they've achieved as part of the MRO team. And I know that they will ensure that MPC remains the gold standard of the US Downstream business and obviously we wish them all the best. So with that, Howard, back to you for questions.

Okay, Clarence, thank you. To accommodate -- John, before we open this up I just want to remind people that to accommodate everyone who wants to ask a question, we'd ask you to limit yourself to 1 question plus a follow up, and then of course you can reprompt for additional questions as time permits.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Doug Leggate from Merrill Lynch. Please go ahead.

Thank you, good afternoon, everybody. I'm going to try 2 very strictly the same questions if you can you hear me okay?

Two defined questions.

Okay. The first one is if you exclude Libya, it appears that your revised production guidance for the year has moved up by somewhere north of 10,000 barrels a day. If you could help us understand what's going on there? And my second question is if you could perhaps just give us an update on the economics in the Oil Sands, given that that is going to becoming a fairly significant part of the production outlook as we move forward? And I will leave it there. Thank you.

Okay, Doug, this is Dave. I think the first question in terms of the increased guidance, which we would say is in the range of 5,000 to 10,000 barrels a day, largely is a result of our focus on reliability over the last several years that we believe has finally yielded some significant results, expressed in the first quarter. And that's specifically we saw 100% reliability out of our Equatorial Guinea complex and we saw 95% reliability out of our Alvheim complex. Both of those, for the type of assets they are, are world class results and what we're forecasting is -- while we can't expect to achieve those rates even though that we will certainly strive for that, we are expecting to achieve industry-leading reliability in those assets, which should allow us to show production increases for the remainder of the year. In addition, we obviously are showing continued growth from our resource plays, particularly in Oklahoma and the Bakken, and we do expect to bring Ozona on stream as expected during the remainder of this year. So that I hope takes care of the first question that you had. The second question --

It does, thanks.

Okay. The second question, with respect to Oil Sands, what I will say is that we're very excited and Shell has made the announcement today that the tenth of 11 units in the upgrader has been delivered and so basically we are fully on schedule with the upgrader being able to match the mine performance. Essentially what that allows us to say is that we now have the capacity to actually produce this asset on a gross basis at 255,000 barrels a day. Marathon has a 20% share of that, obviously.

And what we expect is that our operating costs will now start to continue to decline as we have this larger fixed production against the fixed cost base. And so while we talk about operating expense being in the circa $55 per barrel range in the first quarter, we'd expect that that would continue to fall through the year to give us a year range in that particular asset of maybe $35 to $45 a barrel, with continuing to try to push down to lower levels. We already are seeing some outstanding production performance for the mine and then obviously with the fact that syncrudes are essentially trading at a par to Brent, with those operating cost numbers you could see what the economic power this asset is going to be for us we think on a prospective basis.

That's great, thanks a lot, Dave. I'll leave it there.

Evan Calio from Morgan Stanley. Please go ahead.

Hello, good afternoon, guys. Thanks for taking my question.

Hi, Evan.

I'll start with a question for Gary, the Downstream. You drove today's beat, so we'll kind of move to the Downstream first. You're beginning to see various midstream companies and refiners respond with capital investment to capture what are wider and appear to be sustainably wider TLIS and TI Brent differentials. Do you-- what-- can you describe or talk about the scale of potential investment opportunities that you see in your midstream system to avail more profitability, whether it's in pipeline, barge, rail, terminals, any which way? And I have a follow up, please.

Yes, Evan, and you hit on all of the above. We're working on all of those opportunities, pipeline, rail, barge, in fact, we've been able to optimize our system as Howard indicated in his presentation to avail ourselves of a bigger percentage of WTI benchmark type crudes here in the first quarter versus prior quarters, using all of those systems.

Right to the point, though, of incremental investment, yes, there's been a lot of announcements in the midstream space about different pipelines being built from point A to point B. I think that remains to be seen how many actually get complete. But we are in a very good position to be able to take advantage of those crudes through our current system, through some rail, through the barging and some incremental barging that we've been doing. And -- but we do not have any major expansion plan at this time, Evan.

Okay. That's great. Thanks. And my second question on the Upstream and it's a bit of a broader question, maybe Clarence, I know your production guidance is driven off your existing CapEx and year to date Brent's almost 32% higher, your crude differentials for mid-con have never been wider, which you of course capture. With 5 months on the books, when do you revisit your capital spending guidance from January, if prices at least remain higher than where you budgeted, and do see the abilities, as do some your peers, to pour more capital into the lower 48 liquids growth? And I'll leave it there. Thanks.

Yes, I think, Evan, we continue to increase our acreage holdings. In fact, I think when you look at the earnings release, we give some specific numbers around what we're doing in the Eagle Ford. Obviously, we're not sitting still in some of the other liquids-rich plays, we continue to step up our acreage acquisition to the extent practical. Again, in terms of making sure what we're doing is value accretive.

We're also of course looking at what we can do in some areas to accelerate drilling and you may well see that become part of our program. It won't be, obviously, an instantaneous ramp-up but certainly something that we would transition into over several months. Again, given the opportunity set that we're building in the liquids-rich resource plays. So that certainly is something that we're focused on.

Okay. Thanks for taking my question.

Thanks, Evan.

Paul Sankey from Deutsche Bank. Please go ahead.

Hi, guys. Very best of luck to you and God speed to you in your separate ways. If I could ask Gary a question on refining. Gary, what are your latest observations on the demand side of the picture in light of gasoline prices and diesel prices, and I'm thinking not only of US and your core markets but also what you're doing on the export side and how strong that looks? Thanks.

Okay, Paul, a timely question. As we illustrated in the documents or in the slide presentation, we are about flat on first quarter same-store volume. However, I've said many times in presentations over the first quarter here that we expected if you get to around $3.75 or higher range that that's when you would start to see a reduction in volume and that has been the case. In fact, it started at the last week of March, we started to see a degradation in volume and we're down month to date here in April right around 5%.

Now, let me add, I don't believe all of that is demand from price across the biggest part of our market. We've had about 25 straight days of rain which has completely shut down the farm and planting season and a lot of the outside contractor work as well. So 5%, if you take into account weather and we're up against a quarter last year that -- I mean up against an April last year that was a very, very good weather season. So somewhere probably I would say maybe half and half, Paul of demand versus weather, somewhere in that range. As far as --

Could I just interrupt on the mix there between gasoline and distillate and diesel, how's--

Yes, I was going to go to diesel next, then.

I beg your pardon. I was thinking you might go on to exports. But go ahead, I beg your pardon.

Yes, I'm sorry. As far as diesel, we're seeing about a 3% to 4% increase in diesel across our system and that's US diesel, so that'd mainly be over-the-road. And again, diesel has also I think been tempered by the weather and the very, very late agricultural season kicking in this year.

Then on exports, we've been averaging about 65,000 barrels per day of exports which is a little higher than what we had expected when we built Garyville and that's all diesel exports. So that's a little bit higher than we expected when we built the new system. And our diesel demand has been strong for the export market.

That's great. And then my brief follow up, you mentioned that Garyville full quarter for the first quarter, what's the outlook for utilization rates into your new start as a Company in the second half? And I'll leave it there. Thank you.

Well I tell you, that's a timely question, Paul. You'll recall in 2010, we had a very strong turnaround season, mainly in the first quarter, some of it slipped into the second quarter with the new Garyville plant as well as big turnarounds at Robinson, Catlettsburg and Texas City last year. We just completed the Canton turnaround a week or so ago, that's behind us. And we had the normal turnaround that we have every January at Garyville to do some crude exchange work and I would say that we're in a very, very strong position operationally as we kick off the new season.

Thank you.

Ed Westlake from Credit Suisse. Please go ahead.

Hi, this is actually Rakesh Advani for Ed Westlake. Just had 2 questions. Regarding the international E&P tax rate, it was 48% this quarter, just wondering with Libya removed, is that kind of like a normal run rate to look at going forward?

Well we don't project by segment. What we gave you for the total Company is really, Rakesh, all I can give you at this point.

Okay. That's fair enough. Just the other question is can you give some comments I guess about your exploration calendar that's coming up, any catalysts?

We're-- this is Dave, we're in the midst of drilling a well in Norwegian North Sea that's called our Earb prospect. That's the only exploration well we're currently drilling. We do expect to get 1 to 2 wells drilled on our Polish acreage by the end of this year. Obviously, we're still engaged in some seismic activities, or will be engaged in some seismic activities, or will be engaged in some seismic activities by the end of the year in Kurdistan and I think our plans are, assuming our permits come forward from the United States government, that we'll be in a position in the fourth quarter to move back into the Gulf of Mexico on the Innsbruck-- on the Innsbruck prospect and we continue to test wells that have been drilled as discoveries in the Kurdish region of Iraq.

Thank you.

Paul Cheng from Barclays Capital. Please go ahead.

Good afternoon. Two questions, one is for Gary, the other one I think for Clarence. Gary, you indicate that you have increased the use of the WTI-linked crude, I think in the fourth quarter it's about 20%. Can you give us a rough idea as to how much is in the first quarter? And also that is there any additional step you can take to further increase it in the near term or that you really have to wait until the Detroit upgrading project is done for you to further increase the percentage there? That's the first one.

Okay, yes, in the fourth quarter, you're right, there was about 20% WTI benchmark and around -- overall, 25% between heavy and a couple of other crudes that I would say are linked more to the WTI price. In the first quarter, we were closer to 33% of what I call WTI-linked crudes, that would be WTI, WTS, as well as some of the Canadian heavy.

Okay. So I guess it's from 20% to 33%?

No, about 25% to 33%.

From 25% to 33%. And that 33%, is that including the heavy oil you run down at Garyville?

If it came from -- if it was Canadian-sourced, yes.

I see, okay, good, good. Thank you.

Yes. And then to your second point on are there other things that we can do? Yes. And we're in the process of some other optimization around some of our assets. Let me caution you, though, due to the very high water that we are experiencing in the Midwest on the Mississippi and Ohio River, there's been some slowdown, in fact, some docks have been -- and some locks have been shut down because of the high water. So we've had a week or so here of weather problems. But we expect to get back up and running next week. We do have some other things that we're working on, Paul, I won't get into the details, to help us further optimize our system.

Okay. The second question is then, Clarence, if I look at your cash, cash balance, that is a very strong position, wondering if you look at from the priority of use, how we view between acquisition and share buyback that -- how you determine which one that you want to go for yet?

Well, I think, Paul, go back to what we've said before, and in terms of cash priorities, our highest priority is to ensure that both Companies at separation are well capitalized so that's certainly going to be our highest priority through separation. Past that, I think as we've said all along, certainly funding profitable growth is a very high priority for us. As I indicated on one of the earlier responses, we are looking at increasing our activity levels in North America, in the liquids-rich plays, so certainly that's going to be a use of capital there.

We've said all along, dividend is very, very important to us, as a portion of total shareholder return. And again, share buybacks are something that we will certainly consider as we move forward. We recognize that certainly in the E&P space metrics on a per share basis make a great deal of sense. We recognize the value accretion from share buybacks and we will consider that certainly as a viable option for cash usage.

Thank you.

Blake Fernandez from Howard Weil. Please go ahead.

Good afternoon, guys. I wanted to confirm the Eagle Ford acreage that you added. I'm assuming that's different from the original Denali transaction and I was hoping you could maybe give some details on the location of that?

Yes, Blake. It is different from the Denali, so the 30,000 acres that we reference as being additional is in the form of a number of additional transactions, so the total number is certainly north of 115,000 acres now for Marathon, potentially. And what we would say is that it's representative of both the oil window and the condensate-rich gas window.

Okay, so no specifics on counties at this time on the new acreage; right?

No.

Okay. And then secondly, Clarence, you've recently divested a couple of the assets where you had 100% working interest, both Niobrara and Poland, are there any other assets that pop up on the radar screen as certain ones that you'd like to kind of derisk from a financial standpoint?

No, I think, Blake, those were 2 that we certainly saw as in the earlier stages of development where there was still a lot of unknowns, a lot of risks that -- and we had, as you've noted, a very high working interest. We simply felt it was prudent to share that risk. And I think when you look at the terms of those 2 agreements, we think they were excellent transactions and I think highlight the value of being early into a play, secure the acreage, hopefully at times before the competition sets in and then you're really in the driver's seat as to how you go about developing it. But at this stage, I think those were the 2 highest priorities on our list. I think we feel very comfortable about most of the other areas we're in.

Thanks a lot. Appreciate it.

Faisel Khan from Citigroup. Please go ahead.

Good afternoon.

Hello, Faisel.

On the In-situ Oil Sands leases, now that you've drilled these 94 test wells, what's the plan from here on out in terms of potential sanctioning and potential size of the project? And then a follow up on Downstream.

Yes, Faisel, this is Dave. As we know, we have between 1.5 billion and 2 billion barrels in place in the Birchwood asset, that's the one you're talking about. And again, that's an asset that we have 100% Marathon. We got 94 test wells drilled. We're doing the reservoir and core analysis as we speak. Our view is is that by the summertime, our expectations on what that project could be will be confirmed and we'll be moving towards taking a decision to potentially move into pre-FID with an idea of moving to an FID in sometime in 2012. The view would be that we would stage this project in to -- according to some of the permitting and you could potentially see a project on a scale of 10,000 to 20,000 barrels a day in our portfolio by 2016, that time frame.

Okay, got you. And then on the Downstream side, in terms of where we are with Detroit, if you could just give us an update on where we are with Detroit in the terms of construction completion, in terms of percentage completion, and in terms of any sort of delays that you've had for weather in the quarter or if things are on target and kind of expected to ramp up second half of next year?

Well, Faisel, in fact we're 55% complete. We're right on target. Even though the weather has hampered us, we've-- we're just a little bit ahead of schedule. So -- but of course, this is a very busy construction year for us, but everything is still on time, on budget.

Okay, great. Thanks, guys.

Joe Citarrella from Goldman Sachs. Please go ahead.

Thanks. My question's really just digging in a bit more on the portfolio management activities and spending in shale. You gave some color on the Niobrara and Poland sell down in the quarter and bought more acreage in the Eagle Ford, but moving across the unconventional portfolio, any other specific areas you're looking to either sell down or accumulate more aggressively? And do you expect any acreage acquisitions at this point to be primarily smaller bolt-on kind of deals or maybe something more meaningful than that?

Well, I think we're always looking for meaningful acquisitions, but I think it's also wrong to get caught up in the fact that you can't build portfolios by adding on to existing positions and I think what we've done already in the Eagle Ford is a great example of that. Because certainly we're looking for opportunities to add the 10,000 plus acre positions but we'll certainly add on 1,000 or 2,000 acres as we go forward.

The broader question, I think I'd start with the fact that we are oil focused, and so those assets that we're going to focus on are largely in liquids-rich plays as we've been pretty consistent on. I think you'll see us continue to move away from the Marcellus as an example, because while we think that's a great play and has great potential in terms of being a hydrocarbon resource base, it doesn't really fit our strategy. We would obviously like to increase our position in the Bakken, since it's a key play for Marathon and we continue to think we have a leading operating position there, but financially that doesn't make a lot of sense right now as it's a very overheated basin.

And so I think where you've seen us focus is the other 3 liquids-rich plays that we're focusing in on, the Anadarko-Woodford in Oklahoma, where we've now pushed our acreage position past 100,000 acres which is quite substantial in that play. The 200,000 gross acres that we subsequently farmed down in the Niobrara, we continue to look for opportunities there. And I think clearly the Eagle Ford is a play that we've got a significant focus on and we'll continue to have focus on as we still think there's opportunities out there. And I think that gives us the coverage that we need across a number of basins that give us exposure to liquids and an appropriate risk profile.

That's great and then as you're looking at the liquids-rich plays, any in particular centers having the greatest running room to increase spending of your existing liquids-rich acreage position?

Well I think what we've said, is in the Anadarko we're currently running 3 Marathon rigs. We're going to 8 by the end of the year. We see the potential to increase there. We're running 7 rigs in the Bakken, 6 drilling and 1 that's basically looking to refrac. There may be potential increase there. But the real key growth area for us in expansion is going to be the Eagle Ford. We've got 1 well down, fracked this week. That's a play that I think you could see us -- we've talked about going to 6 rigs in 2012. That's a play, given our recent success in adding acreage, you could see that number go to double digits pretty easily.

That's very helpful. Thank you.

Mark Gilman from The Benchmark Company. Please go ahead.

Folks, good afternoon. I had a couple things. Dave, I wonder if you could talk about what you saw in the Droshky sidetrack, what its implications are in terms of reserves in the profile going forward, and what if any changes there were in the DD&A rate on Droshky?

Okay, Mark, good to hear from you as always. I think we were able to do a successful intervention there with (inaudible) line and added that well to the production mix and I think what we would say is it's served to bolster our confidence in the guidance that we've given for the ability of that asset to produce between 15,000 and 17,000 barrels net for the year. Droshky's currently running at about 19,000 barrels a day, and so I feel pretty good about where we've got that particular asset. Wasn't an impact on the reserves, per se, and so what we would guide to DD&A is $80 a barrel for 2011.

Okay. Dave, my follow up relates to Kurdistan. What would you have to see in terms of assurances, guarantees or potentially regulation legislation in Iraq to actually move you to a production, a potential production status in Kurdistan?

Well, that's a great question. I think we're starting to see the beginnings of that, but the simple answer is we need to sign a hydrocarbon law, because the impacts of the hydrocarbon law are going to cover the cost recovery and the profitable splits that we're going to need to move forward. Now the rhetoric coming out of Baghdad today and over the last several weeks, that they seemed to reach an understanding on how cost oil and costs are going to be recovered is very important and that would certainly move us down the path of preparing for production capacity in the country. But I think until we get a hydrocarbon law that ratifies the PSEs that we signed with the Kurdish regional government, you will not see us go to a full production scenario there.

But you will continue to drill that from an evaluation standpoint?

Yes, I think our view is, and again as you'll recall, Clarence has characterized this, we believe that we have an appropriate amount of risk dollars given where the country is in terms of its overall security, and the continuing positive vibrations that we're getting in terms of how the laws are going to be settled. So we are going to engage in seismic activities on our block. If we can progress things quickly enough, we will move to drill if not late this year, then early next year, assuming that the signals and signs continue to move positively for us.

Okay, Dave, thank you.

Pavel Molchanov from Raymond James. Please go ahead.

Thanks very much. Just following up on Mark's question but with regard to Poland rather than Kurdistan, given that your ownership structure for the Polish acreage seems to have taken shape, what sort of regulatory framework do you need to see in Poland to ramp up drilling to kind of a faster run rate?

Yes, Pavel, I'm not sure that the government structure there is going to be the controlling factor. I mean, it always is, but again, we're getting very positive signals on how the government is going to help us frame the laws, such that we can move forward. The real issue that we're going to deal with there is getting equipment and infrastructure there to move that play along at a pace to where they can actually see that if the resources turn out to be there, that they're going to continue to have legislation and legal infrastructure that's going to support those activities. It's very early days.

There's been 5 to 7 wells drilled and the information is very spotty. We will obviously have a bite at the apple ourselves towards the latter part of the year. But again, the noise coming out of the government is very positive. Obviously they're interested in doing this. We've got a lot of work to do community relations wise to make sure that we continue to handle things in a way the community appreciates as we move that forward. But again, it's going to be more of an issue of getting iron on the ground to do the work in my view.

Okay, that's helpful. And then just a quick follow up, regarding Libya, do you have any sense of the physical state of the assets on the ground in terms of physical damage or is there just no visibility on that?

We have no visibility on that.

Okay. Understood. Thanks.

Mark Polak from Scotia Capital. Please go ahead.

Good afternoon, guys. Just wondered about a possible update on Ozona and where that project stands right now. I believe you guys may be looking for a different rig to go in and complete that, and curious if you could update us on timing?

Yes, the timing is consistent. We've consistently said mid to late Q3. We have a rig contracted, the Diamond Ocean Monarch, and the work that's being done on the host platform to-- it's the auger platform of Shell -- is progressing as expected and so we see no impediments to getting this done this summer.

That's great. Thank you.

Paul Cheng from Barclays Capital. Please go ahead.

Thank you. Dave, in Eagle Ford, the well that you've just fracked, you haven't complete yet, right? Or that you have some data there in terms of what's the production rate counts that you can share?

Paul, we literally pumped the frac the day before yesterday, and so we're basically -- the frac went well. The drilling met our expectations. The frac was pumped well and we're basically now moving to where we can flow the well back, so it's--

How many stage that you guys going to do on that?

I don't have that data, Paul. But we can follow up on that.

Okay. And can you tell us then what is your current production in Bakken and also that the well now you're drilling, how many frac stage that you are performing per well?

Yes, we're currently producing right at 14,000 net in the Bakken, and what I would put a caveat on that number as many of you if you follow the weather, you know that the weather in North Dakota has been very bad and so they literally had a blizzard this past weekend and so that our folks are able to still produce at those rates is a great testament to the folks at Marathon up there and the work that they're doing for us. So we're still on track to continue to drive our production towards our stated goals into the future.

Paul, the second part of your question is -- and I know there's been some reports out, Marathon pumps multi-stage fracs. I think there's this misperception out there that we somehow don't do what some of the operators are doing. But it's really dependent on what area you're in, and so when I think about the activities that we're engaged in in what we would call our Myrmidon area, which is an area that we think typically has a 500,000-barrel plus or minus recoverable per well, we are pumping 20 stage, 3 million-pound frac jobs on those wells. We typically pump smaller jobs in some of the areas that we think have less recoverable oil because obviously the key there is to try to make the completions as financially attractive as possible. So in our good wells, we're pumping up to 20, and 3 million pounds and as we see results that indicate that we should pump more, than we will certainly be open to that.

Very good. Thank you.

(Operator Instructions) Mark Gilman from The Benchmark Company. Please go ahead.

Dave, I've got a question about Kenai and what the implications will be of the shutdown which I believe has either occurred or is scheduled to occur very, very shortly? Was Kenai profitable to you in the first quarter and is that shutdown factored into your production outlook for the year?

Yes, it's 2 separate issues. Obviously, the LNG plant has been profitable for us for the entirety of its life and certainly some of the profitability and-- that we saw in the integrated gas segment can be attributed to LNG sales and to a very robust Asian market. We expect to deliver 2 to 3 more cargoes before the facility is actually shuttered in August, that's the time frame that we're looking at. For Marathon, because of the way that we're positioned and particularly because we have a proprietary storage and we also have firm contracts with a number of the utilities, we are not going to see any impacts relative to our productive capacity.

As you know, it's a seasonal market. And so right now, down a little bit from what we would normally see. But on a productive capacity basis, we're going to be in great shape and our contracts are fairly robust. They certainly don't represent what the Asian LNG markets do, but on the grand scheme of things, the percentage relative to LNG profitability is going to be de minimis for us.

Great, Dave. Had one for Gary, if I could, please. Gary, it seemed to me just in looking at the refined product yields in the quarter that the gasoline distillate yields were a little bit low and seemed to be, excuse me, offset a bit by feed stocks and specialty products. Can you comment on the validity of that observation and if so, what that change is all about?

Well, I'm going to have -- Gary will talk to you about some of the numbers. Let me state, though, Mark, generally as you start to switch over into the low vapor pressure season, February or so, you start max gasoline but the crack spreads have certainly forced everyone from an economic standpoint and because of the global demand for diesel, that we've run a lot more diesel all the way through the first quarter as compared to the normal history.

The second thing, when you look at the types of crude that we were running and moving a lot of the heavy Canadian into different positions, tend to lead you towards more diesel as well than gasoline. Now, I think some of the numbers, and Gary might be able to speak to this here, Peiffer, but some of the numbers in feedstocks, you probably need to add some of those feedstock numbers along with our finished product, and I'll let Gary comment on that.

Yes, Mark, I think you know -- I don't know which period you're comparing it to, but first quarter of 2010, we had the base Garyville plant was basically down for most of that -- or at least a good share of that first quarter, so I think some of the comparisons to the first quarter are a bit skewed. But at least for the first quarter of this year, as Gary was mentioning, we've been maximizing distillate as much as possible. So I'm not sure which quarter you're comparing to, but we were down a bit compared to the fourth quarter of 2010 but really it was more I think just the fact that we do have Garyville as Gary said a little bit of a minor turnaround. We take every first quarter of each year. So I think it was more just the effect that Garyville was down a little bit in the first quarter as well as then in the March of the first quarter, Canton was down. So I think it was more turnaround-related than really anything else.

And the other thing, Mark, if you're comparing to both the fourth quarter we've had 2 months and the first quarter of last year would have had St. Paul Park in both of those. So we will be down a little bit because of St. Paul Park not being in our numbers going forward.

Thanks, guys.

Thanks, Mark.

We have no further questions at this time.

John, we appreciate it. We appreciate everyone's interest in Marathon. We look forward to visiting you in the near future. Thank you.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.