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Marathon Oil (NYSE:MRO)

Q1 2012 Earnings Call

May 02, 2012 2:00 pm ET

Executives

Howard J. Thill - Vice President of Investor Relations & Public Affairs

David E. Roberts - Chief Operating officer and Executive Vice President

Clarence P. Cazalot - Chairman, Chief Executive officer, President and Member of Proxy Committee

Janet F. Clark - Chief Financial Officer, Executive Vice President and Member of Proxy Committee

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Paul Sankey - Deutsche Bank AG, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Rakesh Advani - Crédit Suisse AG, Research Division

Unknown Analyst

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Faisel Khan - Citigroup Inc, Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Howard J. Thill

Welcome to Marathon Oil Corporation's First Quarter 2012 Earnings Webcast and Teleconference. The synchronized slides that accompany this call can be found on our website, marathonoil.com. On the call today are Clarence Cazalot, Chairman President and CEO; Janet Clark, Executive Vice President and CFO; and Dave Roberts, Executive Vice President and COO.

Slide 2 contains the forward-looking statement and other information related to 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, 2011, and subsequent 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 for this presentation, there is a reconciliation of quarterly net income to adjusted net income for 2011 and 2012, balance sheet and cash flow information, second quarter and full year 2012 operating estimates and other data that you may find useful.

Moving to Slide 3, our first quarter 2012 adjusted net income of $478 million was a 13% decrease over the fourth quarter 2011, largely a result of higher income taxes, as I'll explain on the next slide.

As shown on Slide 4, earnings before tax for the international portion of our E&P segment increased $277 million, while the domestic portion of that segment decreased $30 million, with the Oil Sands Mining and Integrated Gas segments decreasing quarter-over-quarter as well, $26 million and $27 million, respectively.

To help explain the change in our tax position from the fourth quarter to the first quarter, and given our present inability to predict activity in Libya with confidence, we've broken the $281 million increase in our consolidated tax expense into 2 categories: one for those income taxes related to the first quarter resumption sales from Libya and one for all other changes in income taxes.

As we often point out, our revenue from Libya is taxed at 93.5%, which resulted in a first quarter tax charge of $203 million. The $78 million increase in income taxes not related to our Libya operations is made up of $125 million for the E&P segment, partially offset by reductions in other segments and a corporate tax benefit for unallocated items.

Approximately 40% of the $125 million increase in income taxes for the E&P segment was a result of a shift to an excess foreign tax credit position. As you may recall, we pointed out this change in the third quarter of last year, as we increased our international price and production forecast for future years. And we had this built into our previous income tax forecast for the full year 2012.

The other 60% of the change is largely a result of our revised expectation for an increase in our higher taxed international jurisdictions as a percentage of 2012 pretax earnings. With this revised expectation in sales mix, we are now projecting an overall effective income tax rate for the full year of 2012, excluding Libya, of between 60% and 65%. Remember, the actual effective income tax rate can vary quarter-to-quarter based on the expected annual level of sales by jurisdiction, as well as any discrete items.

On Slide 5, we've included a comparison of the total Upstream Q1 liquid hydrocarbon sales volumes, with the estimated liquid hydrocarbon sales volumes for Q2, as an aid in modeling the company's earnings with both periods excluding Libya. The timing of listings can vary based upon nominations yet to be finalized, which can affect the estimated sales volumes, as well as the percentage of contributions.

As shown on Slide 6, the first quarter was a good operating quarter for the E&P segment, with higher sales volumes and better prices compared to the fourth quarter. However, these increases were more than offset by higher segment income tax expense, as I just discussed, and higher DD&A and other expenses on an absolute basis because of increased activity. On a boe basis, E&P costs were essentially flat quarter-over-quarter.

Slide 7 shows that in the U.S., we increased sales volumes quarter-over-quarter reflecting our ongoing development programs, primarily in the Eagle Ford, Bakken and Woodford Shale plays. Our U.S. price realizations were negatively impacted by lower domestic natural gas prices and by dislocations in the crude markets, creating wider differentials and lower crude realizations in the Bakken and across the Rocky Mountain region.

After the late January and February widening in differentials, they have returned to more normal levels, narrowing substantially in March and April. On an absolute basis, DD&A and operating costs were higher in the U.S., reflecting our increased activity in the resource plays.

Slide 8 shows that on a boe basis, the U.S. E&P costs quarter-to-quarter were actually slightly lower, excluding the exploration expense, per boe costs were up $0.77, again, predominantly a reflection of increased activity in the Eagle Ford and the Bakken.

Slide 9 shows that our first quarter lower 48 onshore production was 12% higher than the fourth quarter. It also shows we continued to project this portion of our business will grow significantly, reaching between 120,000 and 130,000 boed in the fourth quarter 2012.

Slide 10 shows the positive pretax impact from higher volumes and higher price realizations, which combined, resulted in a 26% increase in international E&P pretax earnings quarter-over-quarter. These positive operating results were more than offset by the previously discussed increase in income taxes.

Slide 11 compares the international E&P cost structure by category over the past 5 quarters. Compared to the fourth quarter, field level controllable costs, DD&A and other costs fell in the first quarter, partially offset by an increase in exploration expense. Total international cost decreased $0.31 per barrel quarter-over-quarter.

As shown on Slide 12, our E&P segment production of available for sale increased 7% quarter-over-quarter, primarily a result of the increased production available for sale in Libya. Sales volumes in the first quarter increased approximately 4% from the fourth quarter. The higher production available for sale compared to actual sales is due to on under lift for the first quarter of 23,000 boed compared to a 10,000 boed under lift in the fourth quarter.

For the first quarter, Europe was under lifted approximately 500,000 boe and Libya was under lifted about 1.7 million boe. The cumulative under lift at the end of the first quarter was approximately 6 million boe: 2.9 million boe underlift in Libya, 2 million boe in Alaska Gas Storage and underlift positions of 750,000 boe in Europe and 400,000 boe in EG.

In April, we entered into agreements to sell all of our Alaska assets. Additionally, we continue to build on our core Eagle Ford holdings, adding 20,000 net acreage through recent and pending acquisitions with current net production of 7,000 boed, nearly all of which is operated. We expect these transactions to close in the second half of the year.

We now expect our capital investment and exploration expenditures budget, excluding acquisition cost, to move up about $200 million from $4.8 billion to $5 billion as a result of adding 2 rigs to our existing fleet of 18 in the Eagle Ford play and other adjustments.

Slide 13 shows the more than 17% growth in our E&P production available for sale since the beginning of 2010, excluding Libya. Increased volumes in the most recent 2 quarters were a result of improved reliability in our base business and new wells coming online in our growth assets, particularly in the Eagle Ford and Bakken.

Slide 14 shows our Oil Sands Mining segment decreased $22 million quarter-over-quarter. This was a result of lower price realizations and higher expenses due to unplanned maintenance, partially offset by changes in DD&A, taxes and other expenses. Net synthetic crude sales were flat quarter-to-quarter at 44,000 barrels per day.

To finish segment reporting, Slide 15 shows that the Integrated Gas segment income decreased $16 million quarter-over-quarter, with this decrease primarily a result of lower Henry Hub-based LNG sales prices and slightly lower LNG sales volumes due to the planned turnaround that began in late March.

Slide 16 provides an analysis of cash flows for the first quarter 2012. Operating cash flow, before changes in working capital, was $1 billion, while working capital changes from operations resulted in a $76 million use of cash.

Cash capital expenditures for the quarter were $1 billion, proceeds from dispositions totaled $208 million and dividends paid totaled $120 million.

During the first quarter of 2012, there was an approximate $150 million U.S. tax payment related to the inclusion of the Downstream business in our 2011 tax return. The quarter end cash balance was approximately $500 million.

As shown on Slide 17, at the end of the first quarter 2012, our cash adjusted debt-to-total-capital ratio remained at 20%.

We will now open the call up to questions. [Operator Instructions] Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Doug Leggate of Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of quick ones, hopefully. On the operational questions, I guess, if Dave's on the call, the Bakken and Eagle Ford well results, Dave, look a fair bit better than perhaps your underlying guidance had previously reflected. So I'm curious on whose areas. Are you now ready to basically change your type curve on, specifically on the Eagle Ford? 1,650 barrels per a day, I think, was the condensate window that you had originally targeted. Are those numbers still good? And how many -- if you could talk a little bit about how much activity you've actually had in the condensate window to write that out, that'd be great.

David E. Roberts

Okay. Sounds like several questions. I'll see if I can get to them all, Doug. First off all on the Bakken, we're going to stick with where we are. We're pretty much consistently on where we said we were going to be type curve-wise with the 30-stage fracs in the core area of the field. As we start getting results from the Diomedes area, which is the Western area of the field, which won't occur until later this month when we actually get some pump equipment out there, we'll take another look at those. Now with respect to Eagle Ford, a lot of chatter about -- from wells that we put out there and some of our partners had put out there. And what we can say is that the high GOR area is generally exceeding our type curve expectations. We have not yet shifted our curves up. We are seeing some variability across the play. There are some areas that are a little bit lower. In majority, the wells are behaving better. And these are in areas that, although we classify them as the high GOR areas, typically are falling at the low end of those GOR boundaries, 500 to 1,000. From an activity perspective, in the first quarter, we would have added approximately 20 to 25 wells, and all of them would have been in the high-GOR areas. So all of our activity was essentially in that area. And so what we've been able to do since then, in terms of our Q2 expectations is, again, we're largely still focused on the high-GOR area. But importantly, our cadence has improved markedly. I would expect that we would be able to double the number of wells that we are going to add to our portfolio in the second quarter. And of that number, 25% are going to be in the condensate area. We are currently running 6 rigs in the condensate area, so we should start seeing some results from that area very quickly. But based on the fact that the high-GOR wells are performing at or better than expectations, I have no reason to doubt that our type curves for the condensate wells are going to perform as well. And so we're looking forward to seeing those results sometime during this month.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

And my follow-up is just a little quick one, the guidance for this current year, is that still a good number? And if you could comment on the contribution from the acquisition and I'll leave it at that.

David E. Roberts

Yes. We're not moving off of our numbers in terms of what our guidance for the existing acreage that we have is. I think, critically, in the earnings release, we feel very good about what happened to us in April in terms of our ability to essentially add 1,200 barrels a day net on a weekly basis. And now that we're running 18 rigs across the portfolio with fully subscribed 4 frac crews, we believe that we're going to be able to add the 16 and 20 wells a month to the portfolio. So that guidance remains intact. We understand that we've got a lot of work to do there. With respect to Paloma, we've characterized that acreage position, we've characterized it as something that will pick up 7,000 barrels a day when it comes into our portfolio, hopefully in August. My view is that will be the number that we get. And you could look for that position to grow slightly over -- towards the end of the year to maybe 9,000 or 10,000 barrels a day. We'll see once we get a hold of it, we're going to be very careful with it. But on the annualized basis, I guess that puts us and being able to talk about our overall Eagle Ford of between 32-plus thousand barrels a day.

Operator

Our next question comes from Arjun Murti of Goldman Sachs.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

I apologize if you just said this, but the 767 is not in the updated budget number for this year, the acquisition.

Clarence P. Cazalot

That excludes -- correct, it excludes all acquisitions.

Janet F. Clark

And it does include some follow-on capital for that acquisition.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Got it, got it. I appreciate that. Can you comment at all on what you're seeing in terms of well costs in the Bakken and the Eagle Ford and then just any update on your Niobrara drilling?

David E. Roberts

Yes. Arjun, I think we're still pretty comfortable with this 8.5 range for our Bakken well. And that's what we had kind of anticipated once we've got to 30-stage fracs. Any increases that we're seeing there are really ones that we're driving in terms of maybe adding a little bit more fluid to the completions or whatnot. We're actually seeing some of the heat come off of the pressure pumping market across the U.S. And so that's going to help us hold our costs in as far as that goes. In the Eagle Ford, we're still very comfortable with this $8.5 million, again, well costs there. We have fixed contracts and so we're not seeing as much price relief potentially as we'd like in that part of the basin. But one of the things I would say is that we're seeing a lot of pressure on GOR pricing in South Texas because of the hot activity. And our commitments, I think, are going to allow us to remain outside of some of that inability to get products. So we still feel pretty good about what our pricing is in both of our key hot basins. We're running 2 rigs in the Niobrara. Where really in an important phase right now. We've got 7 wells that we're doing completions on. We've done most of these with cementless completions. It's a change from what we had done a little bit earlier. We brought one online this week. It's very early days. But it's flowing, it's a little bit less than 500 barrels a day. We're typically seeing 200 barrels a day out of these wells on pump, but we'll see if the cementless completion actually works for us. We'll know a little bit more towards the beginning part of June. But again, our big issue there is we still are concerned with the fact that these, in our view, are 250,000 to 300,000 EUR wells. We're still drilling these wells for a little bit north of $5 million. We've got to get that cost down to $4 million and get better completions. So as we've said consistently, this is an interesting exploration project, that's how I'd characterize it. But we'll get to some more interesting data in the next 30 to 60 days.

Operator

Our next question comes from Paul Sankey of Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

Just to -- I think you said this frankly, very clearly, but just to be triply sure, the guidance that you previously gave on the Eagle Ford for the end of the year is reiterated. And then any acquisitions -- the acquisitions that you just announced essentially are incremental to that guidance. I think I've said that right, if you could just confirm that. And then if you could talk about your outlook for acquisitions going forward in that region, that would be great.

Clarence P. Cazalot

Yes. I think, Paul, first of all, we do confirm our original guidance, and the acquisitions would be incremental. And I'd say we see additional small acquisitions. But for the most part, I think we've completed the bulk of our acquisition activity in the Eagle Ford.

Paul Sankey - Deutsche Bank AG, Research Division

Great. That's helpful. I just wanted to be triple sure. And then on the pricing down there, could you just talk about how that's going? It's obviously very noisy out there. And I just wondered if you could update us on how crude prices are moving. And perhaps what the outlook is there because it is so hard to kind of work out what's going on.

David E. Roberts

Yes. I think, Paul, we're pretty consistent that we've -- since we took this over and most of the assets that we acquired were on WTI contracts, we've been working very hard to move this to an LLS-based crude. We believe we've gotten there and we are pretty firm that it's LLS minus 6 and we think that's where the market is. There is, obviously, going to be some tightening over time. But right now, we think that's a good marker for you all to use. Yes, and I think to get to that point -- yesterday we actually started flowing some of our crude down pipelines, which essentially secures that pricing mechanism. And importantly, it's going to get substantial number of our trucks off the road, which we think is important for how we operate in South Texas as well.

Operator

Our next question comes from Paul Cheng of Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

Two questions. Dave, can you tell us that in Eagle Ford the date you picked to drill each well on average over the last, say, 3 months that what you've been able to do? And also the 30-day IP, as well as that you already give us the well cost, how about the cash operating cost that you're seeing on a per boe basis on the Eagle Ford and Bakken?

David E. Roberts

Okay. Yes. Paul, as I think we pointed out in the release, our spud-to-spud days in the Eagle Ford have fallen to 25 days over the last 3 or 4 months. Frankly, I expect us to be able to drive that even lower. And we are seeing some wells lower than that band. We think that, that's as good as there is in the basin. We're going to continue to test our limits to drive that forward on a go-forward basis. As I said a little bit earlier, consistent with the information that we put out at innumerable conferences, I'd still refer you to the charts that we have on our single well economics for the 30-day IPs, for the various fields that we've got out there, high GOR, 675 is the number we have out there. And you heard me mention to Doug a little bit earlier that we will see some of the condensate wells, and we're expecting those at 1,650 boes per day. Having said that, as I mentioned earlier, most of the wells that we're drilling out there in the high-GOR area are above those expectations, and so we may continue to improve those on a go-forward basis. We have had some cost pressure, both in the Bakken and the Eagle Ford, in terms of operating costs. Eagle Ford not unexpected. We stood up a huge business unit to prepare for what we expect is going to be 100,000 barrels a day business. And so we're seeing some pretty significant costs quarter-on-quarter there. And we've seen Bakken increases in the first quarter over last year as we moved into the Diomedes area, which is a higher water area in the Bakken. Generally, I would say that, while the basins fall within our guidance range of $8.50 to $9.50 per barrel per FLC with the Eagle Ford being toward the high end of that range and the Bakken towards the low end of it, but what I would say is that once we get the businesses underway, particularly in the Eagle Ford, my expectation is that next year, you're going to see those numbers fall back into the $7 to $8 range across our unconventional basins.

Paul Y. Cheng - Barclays Capital, Research Division

Nice. Final question. Dave, do you have the average for your Eagle Ford and Bakken production? And also do you have the breakdown, what you expect next year in Bakken and Eagle Ford, the percent of frac oil, condensate and NGLs from your output going to look like, based on the well that you're going to drill?

David E. Roberts

Yes. The Bakken is oil plays, 100%. And so we're producing, right now, as we've kind of indicated, 25,000, 26,000 barrels a day. And I think we've been pretty just positive on what we expect those rates to go forward and it's going to be 100% oil. On the Eagle Ford, the 20,000 barrels a day plus minus that we're producing, it's 80% condensate, 7% NGLs and the remainder is natural gas. And I would expect that those ratios are going to hang in line 85% liquids and the remainder natural gas as we continue to progress up the curve that we've also been very open about sharing into the future.

Paul Y. Cheng - Barclays Capital, Research Division

The 20,000 exit rate, do you have a number that you can share on the average for April?

Howard J. Thill

We haven't gone there yet, Paul. We have not given an average.

Operator

Our next question comes from Rakesh Advani of Credit Suisse.

Rakesh Advani - Crédit Suisse AG, Research Division

Just a question on the Eagle Ford. You've been pretty open how the lower GOR oil has been less economic. Would you guys consider JV-ing or selling that acreage?

David E. Roberts

No. Well, I mean -- okay, let me backtrack a little bit. In the low-GOR oil area that we classified, yes. We've said consistently we would be open to opportunities to allow somebody else to participate in those areas. In the lower end, high-GOR areas, if I can be that specific, no. We would not be interested in diluting our interest.

Rakesh Advani - Crédit Suisse AG, Research Division

Because you guys have flagged drilling costs in the Woodford were too high. Have you changed the approach to help bring these down?

David E. Roberts

Yes. We've been very quick to adapt to what other operators in the areas have done, both in specific areas. But also some of their specific techniques, and we've been able to dramatically drop our spud-to-spud times there from 7 plus days to 50 or less. So we've been very pleased with our team's performance in being able to execute in the Woodford and Oklahoma.

Operator

Our next question comes from Evan Calio of Morgan Stanley.

Unknown Analyst

It's actually Drew Banker [ph]. Just had 2 quick questions on the Eagle Ford. Are the results in Wilson and Gonzalez County in line with your expectations? And how do those compare with the results in your focus area in Karnes County?

David E. Roberts

Okay, Drew [ph]. I think what I would say is -- we consistently say that Wilson was below our expectations, and we are not conducting any activities by and large in those areas. Gonzalez is a little bit different. We've got rigs running across some of those areas. And to this point, we've been fairly pleased that those wells exhibit some very positive characteristics of the high-GOR oils that we've expected. So what we call our union area and certainly, a little bit south to that, in the DeWitt County area, we've been very pleased with. So far, so good there. But Wilson, we think is challenged with respect to the Eagle Ford.

Unknown Analyst

Okay. And where is the acreage that you picked up?

David E. Roberts

It's in the core area. So mostly in the Karnes area is what we would say.

Operator

[Operator Instructions] Our next question comes from Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Two quick ones. First on the Bakken, it looked like your U.S. crude price realizations were a little bit lower. Is there an effect from the depressed Bakken pricing we saw in the winter months?

David E. Roberts

Yes.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay. And what have the trends been recently?

David E. Roberts

Well, I mean, this morning, as I've been pretty consistently saying, we expect that the trends to close back. And this morning, the differential was $2. So we're back into this total range of both transportation from the well and differential to about a minus 7 to WTI. So the Bakken's recovered very nicely.

Clarence P. Cazalot

So has syn crude, Pavel, because as you know, the OSM earnings were affected by lower price realizations. And again, the same kind of dislocations we saw that affected the Bakken affected our syn crude realizations as well. So both have recovered very nicely. Those differentials have come in quite a bit. In fact, syn crude is actually a little bit of a premium this morning to WTI.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay. And then on Kurdistan, you mentioned there is a non-operated Sarsang well that's currently drilling. Any plans for 2012 to actually operate a well on either of your owned blocks?

David E. Roberts

Yes. We will be drilling at least one well on a Marathon-operated block in 2012, and may get the second one started. So we will actually be conducting operations this summer.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Okay. So spudding in Q3 or...

David E. Roberts

Sometime in the second half.

Operator

Our next question comes from Faisel Khan of Citigroup.

Faisel Khan - Citigroup Inc, Research Division

You guys have already a fairly large position in the Eagle Ford. So I was wondering if you could -- how would you characterize this transaction? Is it -- is this a transaction that you guys are doing -- or these series of transactions, does this help you kind of accelerate some of your drilling program? Or are these kind of -- is this an acreage position that's adjacent or right on top of your current acreage? I'm just trying to figure out the kind of the strategic rationale behind adding more to your position in the Eagle Ford.

Clarence P. Cazalot

Yes. I think, Faisal, what I'd say is these additional acquisitions are very complementary adjacent to what we already own. And so to a certain extent, as Dave said, we built a very substantial and we think a very capable operating presence. These assets will be able to develop and produce synergistically with the assets we already have, so they make a great deal of sense. And so we've been very clear upfront that to the extent we can acquire these kinds of bolt-on acquisitions, whether it's additional working interest in our existing acreage or additional acreage that we can develop, we believe at a competitive advantage, that's of interest to us. And certainly that's what we're doing with these acquisitions.

Faisel Khan - Citigroup Inc, Research Division

Okay. And then can you remind me how much are you guys spending on infrastructure in the Eagle Ford, gathering and processing and the sort of things that take your liquids to market?

David E. Roberts

I'd put that number close to $200 million this year.

Faisel Khan - Citigroup Inc, Research Division

Okay. Last question for me, the Ozona development, can you comment a little bit about what happened? What didn't work? Or what wasn't working versus your expectations of production?

David E. Roberts

Yes, I can. I think, again, we've run into a smallest-sized reservoir issue that has, what I would characterize as very channelized flow regime, and we've not seen the pressure support from any kind of meaningful drive mechanism. It's not the same problems. It's very similar to what we've seen in some of the other recent developments we've done. And it's, frankly, it's put us all chasing these smaller targets in the Gulf.

Operator

The next question comes from John Herrlin of Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Regarding the Bakken activity, could you further delineate how much of the contribution for volume adds you're getting is from the middle Bakken versus Three Forks?

David E. Roberts

Yes, John. It also gives me a chance to say that we actually do make about 5% of our volume from natural gas there. So much as I'd like to say it's 100% oil, I can't quite claim that. To this point, the vast majority of our activity is middle Bakken focused. We started feathering in summer activities in the Three Forks. And in fact, the biggest well Marathon has enjoyed to date, we saw last quarter there were 2,400 barrels a day from the Three Forks. And so we'll start to see more and more of that feature into, particularly, the third well, where we put most spacing units. But to this point, we're still a middle Bakken player and you'll see us increase our focus on the Three Forks on a go-forward basis, particularly in the core part of our acreage there.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Will you look at other formations like the Lodgepole or Nisku? Or is it something later on?

David E. Roberts

Well, as -- our practice across all of our big plays is to really try to stay focused on where we can create the most value. We're not going to leave anything behind. And we continue to look for that. We'll pay attention to what a lot of the other operators are doing out there. But our organization and people who follow this company should understand we focus on making sure we create the most value first and then chasing these other opportunities.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me is on Poland. Any news to speak of yet?

David E. Roberts

No, not really. We basically are pretty close to done with our third well. We had one disappointment with the second well in terms of the zone not really being present in terms of what we were looking for. So we've got some more drilling to do. We'll actually start doing some of our injectivity testing in the second half of the year. And from that, we'll determine if we actually frac any of this. So it's still early days, but at this point, I would say it's middle of the road.

Operator

And last question is a follow-up question from Rakesh Advani of Credit Suisse.

Rakesh Advani - Crédit Suisse AG, Research Division

Can you update us on the progression towards your asset sale targets?

Clarence P. Cazalot

Yes. We've talked about beyond the sales we've had over the last several years that we were targeting another $1.5 billion to $3 billion by the end of 2013. And thus far, this year, we've announced the sale of our Alaska assets. So that's the only update. We've not yet talked about the actual purchase price for those assets. We will at the appropriate time. But I would say that's the first this year. We had last year over $600 million of asset sales that would contribute towards that same target.

Rakesh Advani - Crédit Suisse AG, Research Division

And should we think about it as just being I guess more back-end weighted? Or kind of 50-50 over the next years? Or...

Clarence P. Cazalot

Yes. Again, we don't predict the schedule by which we'll have these sales. We certainly only do the sales if they make economic sense. But I wouldn't give you a projection of when to expect announcements around asset sales.

Rakesh Advani - Crédit Suisse AG, Research Division

And just the last one is are you guys doing any down spacing or water float tests in the Bakken that you can comment on?

David E. Roberts

Well, I think we've continued to chase what other people are doing in terms of -- we started this, obviously, on 12.80s, we're now moving very smartly to 3 wells on our drilling spacing unit, and we'll probably go beyond that. So in that vein, we are continuing to down space. We think it makes a lot of sense. We're studying enhanced recovery in the Bakken and the other unconventionals, but do not have any physical test plan or anything like a waterflood or any other type of enhanced recovery project at this point.

Operator

We have another follow-up question in queue from Paul Cheng's line of Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, do you have an exit rate you expect for Bakken and Eagle Ford for the end of this year?

David E. Roberts

Paul, we've not giving that information to this point. But April, as I've said, we're 20,000 plus in the Eagle Ford. But we're not talking about exit rates at this particular point.

Paul Y. Cheng - Barclays Capital, Research Division

I don't know what I did wrongly in the math. But if we're going to hit 30,000 barrel per day, that seems to suggest that the second half, you to be average more than 40,000. So it look like the fourth quarter, you need to be in excess of 50,000. Is that tie up expectation that we should have?

David E. Roberts

Well, Paul, I think what I said a little bit earlier is when we have that capability, which we do today, to add 16 to 20 wells per month for the remaining part of the year, and in April, we've been able to add over 1,000 barrels a day per week, I think what I would say to you is there's a number of ways you can get to that particular math. But we now have the capacity to get to the numbers similar to what you suggested to get to our average rates for the year.

Operator

We have no further questions in queue. I will now turn the call back over to Howard Thill for any closing remarks.

Howard J. Thill

Thank you very much. And before we close, I want to take just a moment to say goodbye to an important member of our team who is retiring at the end of this month, Bonnie Chisum, and who has been in our Investor Relations team for the last 10 years, and a 39-year employee for Marathon Oil Corporation, as I said is retiring at the end of this month. And we wish her well. We know many of you know her. And with that, we will end the call and wish everyone a good afternoon. Thank you.

Operator

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may all disconnect.

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