Occidental Petroleum Corporation (OXY) Q1 2011 Earnings Report, Transcript and Summary

Good morning. My name is Christy, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum 2011 First Quarter Earnings Release Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thanks, Christy. Good morning, everyone, and welcome to Occidental Petroleum's First Quarter 2011 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Dr. Ray Irani, Oxy's Chairman and Chief Executive Officer; Steve Chazen, our President and Chief Operating Officer; Bill Albrecht, President of Oxy's U.S. Oil and Gas operations; and Sandy Lowe, President of our International Oil and Gas business. Our first quarter earnings press release, Investor Relations supplemental schedules and conference call presentation slides can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Steve Chazen, who will review the first quarter financial and operating results. Steve, Please go ahead.

Well, thank, you, Chris. I hope you can hear me better than I can hear you. Thank you, Chris. Core income was $1.6 billion or $1.96 per diluted share in the first quarter of this year compared to $1.1 billion or $1.35 per diluted share in the first quarter of last year. Non-core items amounted to a net after-tax charge of $44 million. Non-core items included pretax gains of $225 million from the sale of the Argentina operations and a $22 million gain from the sale of our interest in the Columbia pipeline. Non-core pretax charges included $163 million related to the early redemption of $1.4 billion face value of debt, $35 million write-off, the entire accumulated estimated cost of exploration properties in Libya and nonrecurring out-of-period charges for state and foreign taxes, $62 million. This resulted in net income of $1.5 billion or $1.90 per diluted share in the first quarter of 2011 compared to $1.1 billion or $1.31 per diluted share in the first quarter of last year. We reorganized our Permian operation to 2 business units this quarter. One unit will hold the CO2 flood assets and the other will operate the conventional production. In connection with these, we've moved the production from Southwest Texas, which was previously part of the Midcontinent and other, into the Permian. The Midcontinent and other includes production from the recently acquired South Texas and North Dakota properties. Natural gas liquids account for about 10% of our Oil and Gas volumes and sell at a discount to crude oil. Starting this quarter, reporting NGL and crude oil production and sales volume separately as opposed to the previously disclosed combined liquids volumes. Please see the Investor Relations supplemental schedules for the 2010 quarterly realized prices and production and sales volumes reflecting these changes. Here's the segment breakdown for the first quarter. Oil and Gas segment and core earnings for the first quarter of 2011 were $2.5 billion compared to $1.9 billion from the first quarter of 2010. Realized prices increased 24% for crude oil in 2011 and 11% for NGL prices on a year-over-year basis, but domestic natural gas prices declined 25% from the first quarter of last year. Sales volumes to first quarter of 2011 were 728,000 BOE a day, a 6% increase compared to 685,000 BOE a day for the first quarter of 2010. The production guidance we gave you in last quarter's conference call was 740,000 to 750,000 BOE a day, was an $85 average price assumption. The actual first quarter oil price reduced our production volumes by about 10,000 BOE per day, including 1,000 BOE a day at THUMS in Long Beach in California. As we previously disclosed, our Iraq production was lower by about 9,000 BOE a day due to less than planned spending levels as we are in the startup phases of operations. Inclement weather, mainly in Texas, caused an additional reduction of about 7,000 BOE a day. These reductions were offset by less-than-expected production loss from the Elk Hills maintenance shutdown and operational enhancements, providing higher-than-expected production in Colombia, Yemen and Qatar as well as the new assets resulting in production of 730,000 a day. Please see the production and sales volume reconciliations schedules in the Investor Relations supplemental schedules. First quarter production of 730,000 a day was higher than the fourth quarter 2010 production of 714,000 a day. First quarter volumes compared to the prior fourth quarter included 25,000 barrels a day from the new domestic acquisitions in South Texas and North Dakota. Sales of 728,000 a day, which is higher than our initial guidance of 725,000 a day, differ from production volume to the timings of liftings principally caused by Iraq, where liftings are expected in later half of 2011. First quarter 2011 realized prices improved for all our products over the fourth quarter of 2010. Worldwide crude oil realized prices $92.14 a barrel, increase of 15%. Worldwide NGLs were $52.64 a barrel, improvement 7%; and domestic natural gas prices were $4.21 per MCF, increase of 2%. Oil and Gas production costs were $11.30 a barrel for the first quarter of 2011 compared to last year's 12-month cost of $10.19 a barrel. The increase reflects increased workovers and maintenance activity and higher cost for energy. Taxes, other than non-income, which are directly related to product prices, were $2.25 a barrel for the first quarter of 2011 compared to $1.83 for all of last year. Total exploration expenses are $84 million in the quarter. This amount include the Libyan write-off of $35 million, which is included in non-core items discussed earlier. Chemical segment earnings in the first quarter of 2011 were $219 million, which were greater than our earlier guidance. These results are among the best ever reported for the Chemical segment's first quarter of operations which is historically a weak quarter due to seasonal factors. First quarter operations were positively affected by strong export demand and improved supply-demand balances across most products, resulting in higher margins including higher demand for calcium chloride resulted in severe winter storms in the Northeast and Midwest sections of the United States. Midstream segment earnings for first quarter of 2010 were $114 million compared with $202 million for the fourth quarter of 2010 and $94 million in the first quarter of 2010. The decrease from the fourth quarter earnings were mainly due to lower marketing and trading income. The worldwide effective tax rate on core income was 40% in the first quarter of 2011, which was in line with our guidance. Capital spending for the first quarter of this year was $1.3 billion, about 88% was in Oil and Gas, 10% in Midstream and the remainder in Chemicals. We're currently operating 16 rigs in the Permian and 24 rigs in California compared to 5 and 11 rigs, respectively, in the first quarter of last year. Cash flow from operations the first 3 months of 2011 was $2.2 billion, which includes a build in our accounts receivable of about $1 billion from the fourth quarter. In addition, we received $2.7 billion in proceeds from the sale of assets and use $1.3 billion from the company's cash flow to fund capital expenditures and $3 billion on acquisitions. We used $310 million to pay dividends and $1.5 billion to retire debt. We borrowed $1 billion at the end of the quarter for short-term needs, which has now been repaid. These and other net cash flows reduced our $2.6 billion cash balance at the end of last year by $500 million to $2.1 billion. Free cash flow from continuing operations after capital spending and dividends, but before acquisition and debt activities, was about $500 million. Acquisition expenditure in the first quarter was $3 billion. These acquisitions included the previously announced South Texas purchase and properties in California and the Permian. Excluding the South Texas purchase, these properties did not materially impact the first quarter volumes. During the second quarter, we will make a payment of about $500 million in connection with the signing of the Shah Field Development Project. This amount represents development costs incurred by the project prior to the effective date for our participation. Future development costs reflected in capital expenditures. The weighted average basic shares outstanding for the first 3 months of 2011 were $812.6 million and the weighted average diluted shares outstanding were $813.4 million. Our debt-to-cap ratio declined to 12% compared to 14% at the end of last year. Our remaining outstanding debt has an average interest rate of 3.7%. As we look forward to the current quarter, first quarter average oil prices are about $95. Expect the second quarter Oil and Gas production volumes to be as follows. Domestic volumes are expected to increase to at least 425,000 BOE a day compared with the first quarter daily production of 404,000 BOE a day. Latin America is expected to be comparable to quarter one volumes. In the Middle East region, where an overwhelming majority of the value using either the SEC standardized measure or income, comes from Qatar, including Dolphin and Oman, where the operations are running smoothly. With regard to second quarter production in Middle East region, we expect no production for Libya. Production levels in Iraq are not easily predictable due to volatile spending levels at this early stage of that project. This is caused by the nature of the contract, which allows at anywhere near current oil prices immediate recovery of expenditures through cost recovery barrels. As a result, the level of development spending in any given period has an immediate impact on volumes for that period. In Yemen, almost all of our reduction comes from concessions operated by others. In addition, the Masila Field contract, which produces net to us about 11,000 barrels of oil a day is approaching expiration at the end of 2011 and capital spending is being phased down. These factors make a forecast in the production volumes from this area to be very difficult. For the remainder of the Middle East, we expect production to be comparable to first quarter volumes. Total sales volumes are expected to be 725,000 BOE a day, which should not include any volumes from Iraq or Libya. A $5 increase in WTI would reduce our production sharing contract daily volumes by about 3,500 barrels a day. We are increasing our total capital spending program to $6.8 billion, with about $500 million of the increase related to Shah Field development program, subsequent to the effective date of our participation, and the remainder principally in California spending attributable to additional permits being obtained. At current market prices, $1 per barrel change in oil prices impacts quarterly earnings before income taxes by about $34 million. First quarter WTI oil price was $94.10 per barrel. $1 per barrel change in WTI prices affects NGL quarterly earnings before income taxes by about $4 million. A swing of $0.50 per million BTUs in domestic gas prices has a $34 million impact on quarterly earnings before income taxes. The current NYMEX gas price is around $4.25 an M. Additionally, we expect exploration expense to be about $85 million for seismic and drilling for our exploration program. The Chemical segment earnings are expected to be comparable to the first quarter. We expect continuation in the first quarter trends with sufficient gains from strong exports and seasonal demand improvement to offset the reduced contribution from the calcium chloride business. We expect our worldwide tax rate in the second quarter to be about 39%. In California, we are continuing the program I discussed in the last quarter's conference call, which is progressing with satisfactory results. Permitting, especially exploration permits, are still an issue but we recently obtained some permits that make us optimistic about increasing our second half capital spending plan. Governor Brown has been working to speed up the permitting process. We expected that his effort will be successful, which should enable us to increase our activity and add more jobs to the state. In the first quarter, we drilled and completed 26 shale wells outside of the Elk Hills Field. Copies of the press release and the Investor Relations supplement are available on our website or to the EDGAR system. We're now ready to take your questions.

[Operator Instructions] And your first question comes from David Heikkinen of Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: First, want to talk about your Permian operations, with the division of CO2 flood assets and conventional production, can you give us what the current production is for each of those assets?

You're actually breaking up, so we couldn't actually hear the question. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So Permian operations, the CO2 flood assets and the conventional production, can you give us production amounts per each asset gain?

Bill, I think, can rough it out. We're not going to report that separately because it's a little confusing. But we can give you an idea for it.

Yes, David, on the CO2 side, it's about 140,000 or so BOE per day and on the primary development side it's around 60,000 to 65,000 a day. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And then on Shah gas, the $500 million payment prior to participation, how is that communicated or was that expected because we didn't have that in our expectations?

The first $500 million is related to basically historical costs because I think they've been working on it for 3 years. They're working on it for 3 years. That's the historical cost. We treated it as effectively a bonus payment but it's really related to the cost and some of it is actually accrued. The remaining $500 million is our estimate of what the capital will be for the remainder of the year. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And as you think about the total cost of the project now, do you have any update as far as what that will be?

Sandy?

$10 million is still a good number. And we're currently reviewing all the engineering procurement contracts with the Shah team and $10 million or $10.2 million looks good to me right now.

And we own 40% of that, just to remind you. So including the sunk, because the sunk's in the $10.2 million, so we're talking about a $4 billion net to us, $500 million we've essentially already paid. We expect that $500 million will be either paid or accrued this year, another $500 million.

The next question comes from Paul Sankey of Deutsche Bank.

Steve, can we just stick around in California a little bit more and try and work out really by the 3 elements that you've got going on there, how the satisfactory progress is going and where we'll go from here. Can you talk more about Kern County going forward, about other California, if you like? And then I noticed you said that you've got 26 shale wells drilled and completed, can you talk about the production from those?

Yes. Thank you. The exploration program is slightly stalled from the permitting process. We hope at the back half of the year, we can catch up. That's the pure exploration. I think we're doing very well on the shale exploration development and that's actually progressing well and the wells are -- we basically have caught up to where we needed -- where we thought we'd be and we're continuing to progress. We're getting a little better results from the completions than we were historically because we probably figured out how to do it better. The Kern County discovery basically, I don't think it will change much until we move -- until we start drilling more of the deeper wells, which won't happen until we get closer to have the new gas plant.

And what's the latest on that?

So fundamentally, we're shifting to an oilier, more predictable outcome for this year.

I guess just looking backwards, the gas plant is back up from the turnaround of gas and we then get to wait and see to develop the second one, which I guess is still...

That's right. It's back up but, no, it's not exactly brand new.

Right. And the next one? Latest...

Next one I think is about in the first quarter of next year.

And can you put some volumes around the shale, exploration and development in terms of any sort of additional data you can give us on what you're finding?

I'd really like to wait another quarter if I could because I got some preliminary results now but having been burned on this in the last year I just assumed we'd be cautious about. I got some good results currently but we'll see if they continue for the next few months. But it's been -- it's really picked up nicely and I think our completion techniques have improved, so I think we're doing better. But I'd like to put off a more detailed discussion for another quarter if I could. But there's nothing in here that's negative. If anything, it's slightly positive.

The next question comes from John Herrlin of Societe Generale.

Some quick ones, Steve. With Yemen, would you opt to try to renew that PSC?

I'm sorry I -- you wanted to...

With Yemen, would you...

We'd like to but it's hard to exactly find somebody to negotiate with right now.

True. That's fair. I was just curious whether you want to stay there. That's all.

No, it's a very profitable small operation and really has created very little problems for us over the years. But right now, you actually need a government on the other side to be signing. So I think once the thing stabilizes, we'll be trying to do that.

Okay, that's fine. With the Permian, there's been a big ramp up in activity. Given the price realizations, would you try to accelerate there at all or you just keep to your normal program?

No, I think we've accelerated materially already. You can see the rig count change from a year ago.

No, I meant beyond now. Beyond what was reported.

I think we'll continue to accelerate it. I think that you'll see it certainly by the end of this year. Another by the end of the year, see a much higher rig count in the Permian for us.

Okay, great. And you didn't mention anything about the Bakken, you bought yourself a little exposure there, any news for you there?

We've sort of just taken over. It's still what it was supposed to do but it's still pretty small at this point. Once it becomes more sizable, we'll talk more about it. But right -- it's doing what it's supposed to do. We really just took over. There's nothing really here that's either surprising, good or bad.

Okay. Last one for me...

We were surprised to find out it was cold there.

It's very cold there in the winter time, yes. How about on the M&A front, are you seeing ridiculous prices on packages or are the big gaps now between buyers and sellers in terms of what you are seeing?

Yes, we've had obviously a big first quarter in M&A, which you can see in the numbers. The pipeline now is pretty thin and there's a lot of expensive-looking stuff floating around, especially in the shale plays. So I'm guessing right now that the rest of the year will be pretty -- or the next couple of quarters for sure -- will be pretty inactive for us, except for some small deals maybe.

Your next question comes from Doug Leggate from Bank of America.

Let me do and try a couple please, if I may. Obviously, the discussions you appear to have had with the Governor in California. Can you give some indication as to what commitments you may have given in terms of your activity levels? Obviously it seems to be a highly politicized situation over there right now? And what was really behind my question, is that when we look at the Permian [ph] conservation data, Steve, it's looking like you got a lot of permits issued in March, like of the order of more than 90. And I just want to get a feel as to are we really starting to see a ramp up there? And what commitment have you made to basically raise your own activity levels obviously in the unconventional?

The governor is focused on jobs in California and so we've indicated that job creation as the permits come, which is fairly obvious. Not something that's hard to figure. The permits that you're looking at there, a lot of those are development permits, which are sort of normal course of business things which we counted on. We did get some for an extension, not an exploration, but extension of a discovery and some permits to drill there, which I think will be good. So we're encouraged but we really have a long way to go. We still have a nine-month backlog, roughly. So the boost there, a lot of that was the normal development stuff within the field, which is not as contentious. And so I'd like to wait another quarter before we say that the tide has really turned.

Just a quick follow-up on that. The run rate up until March was about 10 or 12. It looks like maybe 10 to 15 if we're lucky. And you did say in the last call, you had about 107 permits to drill on the shales this year, can you say, 1, was that run rate was about right? So is that step-up correct? And second, is the 107 still a good number or is that moving higher?

I think it's likely to move higher as the back half of the year comes. I mean, we've indicated we're going to put more money in so I think we'll probably be higher at the back. I'm hoping it'll be higher at the back -- I'm hoping it'll be higher at the back half of the year. There are some issues floating around here that are sort of technical issues, but I think that big jump up in the early part of the year was drilling within fields and then there's some on this extension, which were look very positive because we focused with the Governor, others on this field extension which is very important to us.

My only follow-up, Steve, is can you talk a little bit about the Lost Hills acquisition. Looks like a steam flood but my understanding this was also historical well data to suggest there is some deep similarities with discovery you had in southern Kern County. So a little bit, if you could elaborate on that and I'll leave it there.

It's a relatively small amount of production. We have -- sort of a special situation, we own the minerals under a slug of it. So we could get significantly better economics at almost any price level than somebody else might. So, and there's obviously some other opportunities there. But right now, I don't think it'll add a lot until for several years. So it'll be a slow buildup and then I think it'll do fine. Obviously, we got a lot. We're, by far, the largest gas producer in the state and some cheap gas, to turn it into oil, strikes me as okay trade right now, although we're not bearish on gas over a multi-year period.

But nation's petroleum, we're talking 35,000 barrels a day within 4 to 5 years, is that about the right number?

I think what you picked up was -- I don't know what they call it, the advertising numbers rather -- I think that was the baked sort of numbers. I think the real numbers are more modest than that.

[Operator Instructions] And your next question comes from Faisel Khan of Citi.

Just you guys reported a full quarter of production in Libya and I guess what I'm trying to understand is what was the contribution to segment earnings from Libya in the quarter? Just so I can understand...

Almost nothing. It has a very small contribution and I don't have the number in front of me. But sales number -- so we actually reported what we actually listed. We didn't report any -- so in the Q, I think we'll report the earnings rate of Libya, but it might be $0.01 in the earnings.

Okay, understood. And then if I'm looking at the Permian Basin view, and of course you guys control a lot of the pipeline systems in and around that area, how are you using your logistics assets to move some of that crude to market? And are you seeing any sort of significant discounts to that crude? Or are you able to get higher realizations because of the assets you own?

I think the answer is, yes, we're doing, I think, better than the average there. We're not interested in solving the whole industry's problem with pushing. We're just interested in solving ours. So I think we're doing better. Our realizations, company-wide, are very good and likely to improve into the second quarter.

Is there a way to quantify the kind of uplift that you guys got in the quarter from the domestic oil price realizations from point of assets?

Not really because they pass it back to the -- they don't keep it in the Midstream. They pass it back to the oil companies so we can pay royalties on it. So pretty hard to come up with a number. Generally speaking, our basic marketing business does about, putting aside the current situation, does about $1.50 a barrel better than a small producer would. It's clearly a lot wider than that now.

Your next question comes from Joe Stewart from KeyBanc Capital Markets.

First, Stephen, in response to an earlier question, you said that you guys are just kind of climbing up the learning curve on the completions in the California shale wells, could you please comment, are you using more acid jobs now or are you moving towards hydraulic fracs?

Why don't you let Bill answer that?

Yes, Joe, it's mainly acid-jobs driven and we're just simply treating these wells in larger intervals with more acid.

Okay. And what are the average lateral links running on your horizontal wells?

California has hardly any horizontal wells.

Very few in the shales, if that's what you're referring to, Joe?

Yes. Yes, in the shales.

Well, actually, we drilled vertical wells.

Okay, got it. And then second question for you, Steve, thinking about NGLs, last week Dow announced that long-term contract for ethane supply, what do you think the potential is there globally for similar contracts for you guys?

We're looking at the future oversupply NGLs. We're trying to figure out how our Chemical business can reap some of the benefits from that. So we'll probably have some kind of announcement here in the next quarter about how we're going to deal with it.

The next question comes from Paul Sankey of Deutsche Bank.

Just getting back to the, I guess, the 2 approaches here on California, bottom up or top down. I think on the top-down basis, you've made a couple of statements about where volumes are expected to go. Firstly, I believe you said that California will be bigger than the Permian for the full year 2012 and I think in the past, I haven't seen recently the improvisation [ph] you've talked the...

'12, '13, I think, was probably a better -- I think I said in the next couple of years. So I think made a '12, '13 area.

And that would, I guess, mean 200,000 a day barrels of oil equivalent plus?

That's right.

And then in the past you had in your presentation words to the effect of unconventional oil in California would achieve a similar level. I think it was to be the biggest business unit within, I think, it was 10 years?

Yes, that's right.

So that would mean unconventional oil in California you're allowing would be more than 200?

That's -- yes. Our biggest business unit's the Permian, combined Permian. I didn't split it in 2 so could I make it easier now.

Is there any other long-term statement to that kind that you can help us with again just from a top-down point of view for getting our arms around it?

I think those are pretty conservative statements. I think pretty easy for us to see how we could achieve that if -- we had a little bumps in the road, as you're aware. But I think once we get by, whatever you want to call it, the issues here in California, I think you'll see a pretty good growth certainly in the shale production for sure. So I think that because we were focusing on that now because it's fairly predictable. We may not know what 2 wells will do, but we certainly know what 100 will do. So I think we've got a pretty predictable program for the year or so. It'll allow us to build a base and then we can do some more exotic things, if you will.

Can we back in recently to an activity level from your higher CapEx? I mean an increase, how would I do that?

Yes, you could figure some amount per well.

What would you figure that to be?

About 3.

Yes, okay. And then just...

I mean it might be some that are less, sometimes more. But if you just stick to an average, around $3 million. That's real complete and hook-up, not just drilled.

Okay, and then we can move forward on the CapEx number that you've given us for California. What's the kind of word going forward on that?

I'd like to spend more. Just so you understand. This isn't -- we're not limiting them. This is just an estimate for you so you can see what we think sort of what we think we can do. But we would like to spend more if this moves along faster.

And how much would each well produce, Steve, approx?

A reasonable guess, and there's some variance around it, but on the average, around 400, mostly oil.

400 barrels a day, right?

No. It's about 400 equivalent, Paul, but heavily skewed to the oil side.

And then I guess the obvious question to follow that up is, what kind of declines would it then show?

I think we're trying to get to the ultimate recovery, I think we're somewhere between 400,000 and 500,000.

Your next question comes from Doug Leggate from Bank of America.

If anyone else is doing a follow-up, I figured I would as well. I think what we're really all trying to get, Steve, is real simple. Let me try a couple here and see if you can frame it. Are you still comfortable with your 10-acre spacing? And if so, how much of the acreage on your current 12-rig drilling program do you believe that you've de-risked out of the 1.6 million acres? And if you could just do the math for us and help us hold our hand a little bit on it, ultimately, when you talk about 200,000 barrels a day of unconventional production, in a conservative statement, what resource are we talking about in the context of supporting that? If you could just try and help us a little bit what ultimately what you see...

I'll try to do it without going nuts. The 10-acre spacing, I think, is fine. It's possible, it could be less but we'll say it's 10. Less meaning a number below 10. We're pretty comfortable that we got more than 200,000 acres, that's fairly safe.

So we're talking about 20,000 more locations.

Yes.

With 500,000 barrels per location. I'm sorry...

Yes. 400,000 to 500,000, whatever you want to use then, yes.

So what was -- is it only the permits then is stopping you putting more money to work?

Permitting and people. You got to get the rigs and you don't want to destroy everything. But it's a combination of all those things. But that's sort of where we're headed over the next few years.

Great. One final follow-up if I may, completely unrelated. Wolfcamp activity, could you maybe just give us a little bit color as to what you're doing there in the context of your overall Permian business? And I'll leave it there.

You're talking about the berry stuff?

Yes.

It's a different berry everywhere, so Bill will answer that.

Yes, Doug, just to give you a flavor. Of the 16 rigs that we have currently running in the Permian, right now 6 of those are drilling Wolfberry wells, which as you know is that interval between the Spraberry and the Wolfcamp. So we've got nearly 50% of our Permian development program designated to drill Wolfberry wells.

And can you give kind of any characteristics around the wells, Bill?

Yes, I mean they make good returns. General IPs are somewhere around 150 barrels of oil equivalent per day. Its ultimate recoveries of 200,000 or so BOE per well.

Is there multiple horizons that you're targeting in terms of -- I hear talk of like 7 different recompletions in some of these wells. Is that something you are seeing or, again, if you could just elaborate on how you see the potential, that would be great.

Yes, Doug, I mean it's a thick interval, as you know, and so we're doing multistage fracs on these intervals. So frankly, we're not leaving a whole lot behind in terms of recompletion potential. We like to open the whole thing up.

Your next question comes from David Heikkinen of Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: I think Doug Leggate covered me.

Good. Thank you.

And at this time, there are no further questions. I'll turn the call back over for closing remarks.

Well, thank you very much for participating in today's call and if you have any other questions, feel free to call us here in New York. Thanks very much.

Thank you. This does conclude today's conference call. You may now disconnect.