At this time, I would like to welcome everyone to the Occidental Petroleum 2011 First Quarter Earnings Release Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. 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.
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 pre-tax 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 pre-tax charges included $163 million related to the early redemption of $1.4 billion face value of debt, $35 million write-off of the entire accumulated cost of exploration properties in Libya, and non-recurring out-of-period charges for state and foreign taxes of $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 into two 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 South 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 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 a 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 for 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 for the 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 of 740,000 BOE - 750,000 BOE a day was at 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 were in the startup phases of operations. Climate 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 reconciliation schedules in the Investor Relations Supplemental Schedules.
First quarter production of 730,000 a day was higher than the fourth quarter of 2010 production of 714,000 a day. First quarter volumes compared to the prior fourth quarter included 25,000 bbl a day from the new domestic acquisitions in South Texas and North Dakota. Sales volume of 728,000 a day, which is higher than our initial guidance of 725,000 a day, differ from production volumes due to the timings of liftings, principally caused by Iraq, where liftings are expected in the later half of 2011. First quarter 2011 realized prices improved for all our products over the fourth quarter of 2010. Worldwide crude oil realized price was $92.14 a barrel, increase of 15%. Worldwide NGL for $52.64 a barrel, improvement of 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 costs of $10.19 a barrel. The increase reflects increased workovers and maintenance activity and higher costs for energy. Taxes other than on 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 expense was $84 million the quarter. This amount includes the Libya write-off of $35 million, which is included in non-core items discussed earlier. Chemical segment earnings for 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, resulting from the severe winter storms in the Northeast and Midwest sections of the United States. Midstream segment earnings for the 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 was mainly due to lower marketing and trading income. The worldwide effective tax rate on core income was 40% for 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 are 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 three 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 used $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 have 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 - $2.1 billion.
Free cash flow for 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 signing a Shah Field Development Project. This amount represents development costs incurred by the project prior to the effective date of our participation. Future development costs were reflected in capital expenditures. The weighted average basic shares outstanding for the first three months of 2011 were $812.6 million, and the weighted average diluted shares outstanding were $813.4 million. Our debt-to-capitalization 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 of 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 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 the second quarter production in the 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 production concessions are operated by others. In addition, the Masila Field contract, which produces net to us about 11,000 bbl of oil a day, is approaching expiration at the end of 2011, and capital spending is being phased down. These factors make forecasting the production volumes from this area to be very difficult. For the remainder of the Middle East, we expect production to be comparable to the 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 bbl a day. We are increasing our total capital spending program to $6.8 billion, with about $500 million of the increase related to the 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, a dollar 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. At a dollar per barrel change in WTI prices, it 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 MMBtu.
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 of the first quarter trends with sufficient gains from strong exports and seasonal demand improvement to offset the reduced contributions 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 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 expect 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 through the EDGAR system. We're now ready to take your questions.
Thank you. At this time, if you would like to ask a question, press star then the number one on your telephone keypad. Your first question comes from David Heikkinen of Tudor, Pickering, Holt.
Morning, Steve. First, I wanted 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 hear the question.
Is that better?
Not a lot better.
Okay, I'll speak really loud. Permian operations.
Loud and slow.
The CO2 flood assets and the conventional production, can you give us production amounts for each asset team?
Bill, I think, can rough it out. We're not going to report that separately because it's a little confusing, but you know we can give you an idea for it.
Yeah. David, it's about on the CO2 side, it's about 140,000 or so BOE per day. On the primary development side, it's around 60,000 to 65,000 a day.
Okay. On Shah Gas, the $500 million payment prior to participation, how was that communicated or was that expected? We didn't have that in our expectations.
The first $500 million was related to basically the historical costs because they've been working on it for three years. Sandy?
Yes, that was correct.
They've been working on it for three years. That's the historical cost. You know we treat it as effectively a bonus payment, but it's really related to the costs, 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.
Okay. 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. We're currently reviewing all the engineering procurement contracts with the Shah T eam, and $10 million or $10.2 million looks good to me right now.
We own 40% of that, just to remind you.
And.
Including the sunk.
Okay.
Because the sunk's in the $10.2 billion. We're talking about about a $4 billion net to us. Go forward, $500 million we've essentially already paid. We expect that $500 million will be either paid or accrued this year, another $500 million.
Okay, that was it.
Question comes from Paul Sankey of Deutsche Bank.
Steve, hi.
Hi.
Steve, can we just dig around in California a little bit more and try and work out really five or three 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? I noticed you've said that you've got 26 shale wells drilled and completed. Can you talk about the production from those? Thanks.
Yeah. 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. You know that's the pure exploration. I think we're doing very well on the shale exploration and development, and that's actually progressing well. The wells are, yeah, we basically have caught up to where we needed to be, and we're continuing to progress.
We're getting a little better results from the completions than we were historically because we've probably figured out how to do it better. The Kern County discovery, you know, basically, I don't think it'll change much until we move, until we start drilling more of the deeper wells, which won't happen until we get closer to having a new gas plant.
What's the latest on that?
Fundamentally, we're shifting to an oilier, more predictable outcome for this year.
Yeah. Just working backwards, the gas plant is back up from the turnaround, I guess, and we're then going to wait for you to develop a second one, which I guess is still in that timeframe.
It's back up, but you know it's not exactly, you know, brand new.
Right. The next one? Latest?
I think it's about in the first quarter of next year.
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. Having been burned on this in the last year, I just assume be cautious about it. I got some good results currently, but we'll see if they continue for the next few months. It's really picked up nicely, and I think our completion techniques have improved. I think we're doing better. I'd like to put off a more detailed discussion for another quarter if I could. There's nothing in here that's negative, anything. It's slightly positive.
Okay. Great. I'll take that. Thanks, Steve.
Thank you.
Our next question comes from John Herrlin of Société Générale.
Yeah. Hi. Some quick ones, Steve. With Yemen, would you opt to try to renew that PSC?
I'm sorry, you wanted to.
With Yemen, would you?
Oh, yeah. We'd like to, but you know it's hard to exactly find somebody to negotiate with right now.
True. True. That's fair. I was just curious whether you want to add there. That's all.
No, it's a very profitable small operation and really has created very little problems for us over the years. Right now, you need a government on the other side to be signing. 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 it materially already. You can see the rig count change from a year ago.
No, I meant beyond now, beyond what you've reported.
Yeah. No, I think we're continuing to accelerate it. I think that you'll see, certainly by the end of this year, by the end of the year, you'll see a much higher rig count in the Permian for us.
Okay. Great. You didn't mention anything about the Bakken. You bought yourself a little exposure there. Any news for you there?
We've just taken over. It's doing 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. Right now, it's doing what it's supposed to do. We really just took over.
Okay, that's fine.
There's nothing really here that's either surprising, good or bad.
Okay, that's fine. Last one from you.
We were surprised to find out it was cold there, I guess.
It's very cold there in the wintertime, yes.
Yeah, right here.
How about on the M&A front? Are you seeing ridiculous prices on packages, or are there big gaps now between buyers and sellers in terms of what you are seeing?
We 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 place. 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.
Great, thanks very much.
Thank you.
Our next question comes from Doug Leggate of Bank of America.
Thanks. Good morning, Steve. Good morning, everybody.
Morning.
We can 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? It seems to be a highly politicized situation over there right now. What was really behind my question is that when we look at the Department of Conservation data, Steve, it is looking like you got a load of permits issued in March, like on the order of more than 90. 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's focused on jobs in California. We've indicated that the job creation as the permits come, which is fairly obvious, is 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. We're encouraged. You know we really have a long way to go. We still have a nine-month backlog, roughly. The boost there, a lot of that was the normal development stuff within the field, which is not as contentious. 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 looked like, maybe 10 - 15 if we're lucky. You did say in the last call you had about 107 permits to drill in the shales this year. Can you just say, one, was that run rate about right? Is this step-up correct? Second, is the 107 still a good number, or is that moving higher?
It's likely to move higher as the back half of the year comes. We've indicated we're going to put more money in. I think we'll probably be higher at the back. I'm hoping it'll be higher at the back half of the year. There are some other issues floating around here that are sort of technical issues. I think the big jump-up in the early part of the year was drilling within fields. There is some in this extension, which was very positive because we focused with the Governor and others on this extension, this field extension, which is very important to us.
Great. My only follow-up, Steve, is can you talk a little bit about the Lost Hills acquisition? It looks like a steam flood, but my understanding is there's also historical well data that suggests there's some deep similarities to the discovery you had in Southern Kern County. If you could elaborate on that, and I'll leave it there. Thank you.
Yeah, it's a very small amount, relatively small amount of production. It was 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. There are obviously some other opportunities there. Right now, I don't think it'll add a lot for several years. It'll be a slow build-up, and I think it'll do fine. Obviously, we got a lot of, we're by far the largest gas producer in the state, and some cheap gas to turn it into oil strikes me as an okay trade right now, although we're not bearish on gas over a multi-year period.
Nations Petroleum, we're talking $35,000 a day within four or five years. Is that about the right number?
I think what you picked up was the, I don't know what they call it, the advertising numbers rather than, I think that was the bait sort of numbers.
All right, I'll leave it at that.
I think the real numbers are more modest than that.
Got it. Thanks a lot.
Thanks.
As a reminder, if you would like to ask a question, press star then the number one on your telephone keypad. Your next question comes from Faiz Ahmed Khan of Citi.
Thank you. Good morning.
Good morning.
It looks like you guys reported a full quarter of production in Libya. 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 how.
Almost nothing. You know, it has a very small contribution. I don't have the number in front of me, but in the sales number, not, you know, we actually reported what we actually lifted. We didn't report any. In the queue, I think we'll report the earnings rate of Libya, but you know, it might be a penny in the earnings.
Okay. Understood. If I'm looking at the Permian Basin view, 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? Are you seeing any sort of significant discounts to that crude? 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. 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 your domestic oil price realizations from owning those 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. Pretty hard to come up with a number. Generally speaking, our basic marketing business does about $1.50 a barrel better than a small producer would. It's clearly a lot wider than that now.
Okay. Great. Thank you for your time.
Our next question comes from Joseph Stewart of KeyBanc Capital Markets.
Good morning, and thank you for taking my questions. First, Steve, 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 fracks?
Why don't you have Bill answer that?
Yeah, Joe. It's mainly acid jobs driven. We're just simply treating these wells in larger intervals with more acid.
What are the average lateral lengths running on your horizontal wells?
California has hardly any horizontal wells.
Yeah, there's very few in the shales, if that's what you're referring to, Joe.
Yes, in the shales.
Yeah, I mean, we basically drill vertical wells.
Okay. Got it. A 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 oversupply of, you know, the future oversupply NGLs. We're trying to figure out how our chemical business can reap some of the benefits from that. We'll probably have some kind of announcement here in the next quarter about how we're going to deal with it.
Okay. Great. Thank you, gentlemen.
Our next question comes from Paul Sankey of Deutsche Bank.
Hi, Steve. It's me again. Just going back to the, I guess, the two 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've said that California will be bigger than the Permian for the full year of 2012. I think in the past, I haven't seen it recently in a presentation, you've talked about the.
12, 13, I think, is probably what was a better, you know, I think I said the next couple of years. I think that'd take me to 12, 13 area.
That would, I guess, mean 200,000 a day barrels of oil equivalent plus.
That's right.
In the past, you had in your presentation what the effect of unconventional oil in California would achieve at a similar level, i.e., I think it would be the biggest business unit within, I think it was 10 years.
That's right.
That would mean unconventional oil in California alone would be more than 200.
Yes. Our biggest business unit is the Permian, combined Permian. I didn't split it in two so I could make it easier now.
Is there any other, are there any other long-term statements of that kind that you can help us with, again, just from a top-down point of view for getting our arms around this?
Yeah. I think those are pretty, you know, conservative statements. I think they're pretty easy for us to see how we can achieve that if there were little bumps in the road, as you're aware. I think once we get by the, you know, whatever you want to call it, the issues here in California, I think you'll see pretty good growth in the, certainly in the shale production for sure. I think that because we're focusing on that now because it's fairly predictable. We may not know what two wells will do, but we certainly know what 100 will do. I think we got a pretty predictable program for the next year or so that allows us to build a base, and then we can do some more exotic things, if you will.
Can we back in reasonably to an activity level from your higher CapEx? I mean, an increase? How would I do that?
You could figure some amount per well.
What would you figure that to be?
About three.
Okay. Just.
I mean, there might be some that are less, sometimes more, but you know if you just look at an average around $3 million.
Okay. And.
That drill, complete, and hook up, not just, you know, drill.
Okay. We can move forward on the CapEx number that you've given us for California as the way of going forward on that.
I'd like to spend more to understand. This isn't, you know, we're not limiting them. This is just an estimate for you so you can see what we think. This is sort of what we think we can do, but we would like to spend more if this moves along faster.
How much would each well produce, Steve, approximately?
Yeah, you know, a reasonable guess, and I thought there's some variance around it, but on average, you know, around 400, mostly oil.
Sorry. Yeah, 400 bbl a day, right?
About four.
Yeah, it's about 400 equivalent, Paul.
Yeah, it's heavily skewed to the oil side.
I understand this. Yeah, I guess the obvious question to follow that up is what kind of declines would it then show?
Yeah, I think if 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 of Bank of America.
Let me see. I figured if everybody's doing follow-ups on that, we'll jump in as well.
You're breaking up.
Did he answer? You say you answered the questions, and we said.
Doug, could you please repeat your question?
I think you're having some trouble hearing me, Steve. Can you hear me now?
Yeah, I can hear you now better. It's not perfect.
Sorry, I had a problem with the phone. I said.
I don't think it's your problem.
Oh, if everyone else is doing a follow-up, I figured I would as well. I think what we're really all trying to get to, Steve, is real simple. Let me just try a couple here and see if we can frame it. Are you still comfortable with your 10-acre spacing? 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? 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 bbl a day of unconventional production, or as it being a conservative statement, what resource are we talking about in the context of supporting that? If you could just, you know, try and help us a little bit with ultimately what you see as.
No, 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. You know, we're pretty comfortable that we got more than 200,000 acres. That's fairly safe.
We're talking about 20,000 locations?
Yeah.
With a half a million barrels per location? Sorry, a half a million barrels per location.
Yeah, $400 - $500, whatever you want to use then.
Is it only the permits then that's stopping you putting more money to work?
Permitting and people, you know, you got to get the rigs and you don't want to destroy everything. It's a combination of all those things. That's sort of where we're headed over the next few years.
Great. One final follow-up, if I may, completely unrelated. Will's camp activity, could you maybe just give us a little bit of color as to what you're doing there in the context of your overall Permian business? I will leave it there. Thank you.
We're talking about the Berry stuff?
Yeah.
It's a different berry everywhere, so Bill will answer that.
Doug, just to give you a flavor, of the 16 rigs that we have currently running in the Permian right now, six of those are drilling Wolfberry wells, which, as you know, is that interval between the Spraberry and the Wolfc amp. We've got nearly 50% of our Permian development program designated to drill Wolfberry wells.
Can you give any kind of characteristics around the wells, Bill?
Yeah. I mean, they make good returns. General IPs are somewhere around 150 bbl of oil equivalent per day, you know, with ultimate recoveries of 200 or so thousand BOE per well.
Is there multiple horizons that you're targeting in terms of, you know, I hear talk of like seven different re-completions in some of these wells? Is that something you're seeing? If you could just elaborate on how you see the potential here, that'd be great.
Yeah, Doug. I mean, it's a thick interval, as you know. We're doing multi-stage fracks on these intervals. Frankly, we're not leaving a whole lot behind in terms of re-completion potential. We like to open the whole thing up.
Got it. Okay. Terrific. Thank you.
Our next question comes from David Heikkinen of Tudor Pickering Holt.
I think Douglas George Blyth Leggate covered me. Thanks.
Good. Thank you.
At this time, there are no further questions. I'll turn the call back over for closing remarks.
Thank you very much for participating in today's call. If you have any other questions, feel free to call us here in New York. Thanks very much.
Thank you. This is the end of today's call.