馬拉松石油 (MRO) 2012 Q1 法說會逐字稿

Welcome to Marathon Oil Corporations first-quarter 2012 earnings webcast and teleconference. The synchronized slides that accompany this call can be found on our website www.Marathonoil.com. On the call today are Clarence Cazalot, Chairman, President, and CEO; Janet Clark, Executive Vice President and CFO; and David 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 to 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 two categories. One for those income taxes related to the first-quarter resumption of 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 and 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 pre-tax earnings. With this revised expectation in sales mix, we are now projecting an overall effective income tax rate for the full year 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 liftings can vary based upon nominations yet to be finalized, which can affect the estimated sales volumes as well as the percentage 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 US, we increased sales volumes quarter-over-quarter, reflecting our ongoing development programs, primarily in the Eagle Ford, Bakken, and Woodford shale plays. Our US 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 US, reflecting our increased activity in the resource plays. Slide 8 shows that on a BOE basis the US E&P costs quarter to quarter were actually slightly lower. Excluding 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 continue 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 pre-tax impact from higher volumes and higher price realizations which combine resulted in a 26% increase in international E&P pre-tax 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 five 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 costs decreased $0.31 per barrel quarter-over-quarter. As shown on slide 12, our E&P segment production 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 of available for sale compared to actual sales is due to an underlift for the first quarter of 23,000 BOED compared to a 10,000 BOED underlift in the fourth quarter. For the first quarter Europe was underlifted approximately 500,000 BOE and Libya was underlifted about 1.7 million BOE. The cumulative underlift 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 acres 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 two 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 two 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 US 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 to questions. To accommodate all who want to ask questions we ask that you limit yourself to two questions. You may reprompt for additional questions as time permits. For the benefit of all listeners we ask that you identify yourself and your affiliation. Thank you.

(Operator Instructions)

Doug Leggate, Bank of America.

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

Okay, sounds like several questions. I'll see if I can get to them all, Doug. First of all in the Bakken, we are going to stick with where we are. We are pretty much consistently on where we said we're 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 the Eagle Ford, a lot of chatter both 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 area, 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're 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 six 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 some time during this month.

Dave, my follow-up is a real 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 then I'll leave it at that, thank you.

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 four frac crews weak, we believe that we're going to be able to add this 16 to 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 characterized it as something that we'll 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 an annualized basis I guess that puts us being able to talk about our overall Eagle Ford between 32,000 plus barrels a day.

Perfect, thanks Dave, I appreciate it.

Arjun Murti, Goldman Sachs.

Apologize if you just said this, but the $767 million is not in the updated budget number for this year, the acquisition?

That excludes that, correct. It excludes all acquisitions.

Got it.

It does include the follow-on capital for that acquisition.

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 any update on your Niobrara drilling, thank you.

Yes, Arjun, 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 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 what not. We're actually seeing some of the heat come off of the pressure pumping market across the US, 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 again well costs there.

We have fixed contracts and so we're not seeing as much price relief potentially as we would 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 still feel pretty good about what our pricing is in both of our key hot Basins. We are running two rigs in the Niobrara, we're really in an important phase right now. We've got seven wells that we're doing completions on. We've done most of these with cementless completions, that's a change from what we've done a little bit earlier. We brought one online this week. It's very early days but it's flowing 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, our 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 some more interesting data in the next 30 to 60 days.

Thank you.

Paul Sankey, Deutsche Bank.

Just two. I think you said this frankly very clearly but just to be sure, the guidance that you previously gave on the Eagle Ford for the end of the year is reiterated and then any 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, thanks.

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.

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 work out what's going on, thanks.

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 LOS faced crude. We believe we've gotten there and we are pretty firm that it's LOS minus 6 and we think that that's where the market is. There's obviously going to be some tightening over time but right now we think that's a good marker for you all to use. 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 is going to get a substantial number of our trucks off the road which we think is important for how we operate in South Texas as well.

Great, thank you very much.

Paul Cheng, Barclays Capital.

Two questions. Dave, can you tell us in the Eagle Ford that the, Dave, you picked the (inaudible) of each wells on average over the last say three months that what you've been able to do and also the 30 day IP as well as that you already gave us the well costs, how about the cash operating costs that you are seeing on the per BOE basis in your Eagle Ford and Bakken. Thank you.

Okay. Yes, Paul. As I think we pointed out in the release, there are spud to spud days in the Eagle Ford have fallen to 25 days over the last three or four 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 numerable 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 in the Eagle Ford in terms of operating costs. Eagle Ford is 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 and the Bakken.

Generally, I would say that while the Basins fall within our guidance range of $8.5 to $9.5 per barrel for FLC with the Eagle Ford being towards 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 under way, 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 bases.

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

Yes, well the Bakken is oil-based 100% so we're producing right now as we indicated 25,000 to 26,000 barrels a day and I think we've been pretty dispositive 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 or 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 curves that we've also been very open about sharing into the future.

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

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

Okay, thank you.

Rakesh Advani, Credit Suisse.

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

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

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

Yes. We've been very quick to adapt to 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 teams performance in being able to execute in the Woodford and Oklahoma.

Okay, thank you.

Evan Calio, Morgan Stanley.

It's actually Drew Bankor. Just two quick questions on the Eagle Ford. Are the results in Wilson and Gonzales County in line with your expectations? And how do those compare with results in your focus area in Karnes County?

Okay, Drew. 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. Gonzales 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 oil that we've expected. So what we call our union area and certainly a little bit south to that in De Witt County area we've been very pleased with. So, so far so good there but Wilson we think is challenged with respect to the Eagle Ford.

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

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

Okay, thanks.

(Operator Instructions)

Pavel Molchanov, Raymond James.

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

Yes.

Okay, and what have the trends been recently?

Well, this morning, as I've been pretty consistently saying, we expect the trends to close back and this morning's differential is $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.

So has syn crude Pavel, because as you know the OSM earnings were affected by lower price realizations, and again, the same dislocations we saw that affected the Bakken affected our syn crude realizations as well and 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.

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

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.

Okay, so spudding in Q3?

Some time in the second half.

In the second half. All right, thanks very much.

Faisel Khan, Citigroup.

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

Yes, I think Faisel, what I'd say is these additional acquisitions are very complimentary adjacent to what we already own and so to a certain extent as Dave says we built a very substantial and we think 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 up front 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.

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?

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

Okay, and then 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?

Yes, I can. I think again we've run into a smaller size reservoir issue that has what I'd 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 problem, it's very similar to what we've seen in some of the other recent developments we've done and it's frankly put us off chasing these smaller targets in the Gulf.

Okay, understood, thank you.

John Herrlin, Societe Generale.

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

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 some of our activities in the Three Forks and in fact the biggest well Marathon has enjoyed to date we saw last quarter at over 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've put in 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.

Okay, will you look at other formations like the Lodgepole or Nisku or is it something later on?

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.

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

No, not really. We basically are pretty close to done with our third well. Had one disappointment with the second well in terms of the zone not really being present in terms of what we were looking for, still 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.

Thank you very much.

Rakesh Advani, Credit Suisse.

Just wondering, can you update us on the progression towards your asset sales targets?

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 of 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.

And should we think about it as being I guess more back-end weighted or 50/50 over the next two years?

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.

Thanks, and just last one is are you guys doing any down spacing of water flood testing in the Bakken that you can comment on?

Well, I think we've continued to chase what other people are doing in terms of we started this obviously on 1,280s and we're now moving very smartly to three wells on a 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 tests planned for anything like water flood or any other type of enhanced recovery projects at this point.

Thank you.

Paul Cheng, Barclays Capital.

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

Paul, we've not given 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.

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

Well, Paul, I think what I said a little bit earlier is when we have the 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 a 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've suggested to get to our average rates for the year.

All right. Okay, thank you.

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

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 Chisholm 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.

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