At this time, I would like to welcome everyone to the Occidental Petroleum Second Quarter 2011 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 followed by 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.
Thank you, Christy. Good morning, everyone, and welcome to Occidental Petroleum's Second Quarter 2011 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer, Jim Lienert, Oxy's Chief Financial Officer, Dr. Ray Irani, Oxy's Executive Chairman, and Bill Albrecht, President of U.S. Oil and Gas Operations. In a moment, I will turn the call over to our CFO, Jim Lienert, who will review our financial and operating results for the second quarter and first six months of 2011. Steve Chazen will then follow with some guidance and an outlook for the second half of the year. Our second quarter earnings press release, related supplemental schedules, and the conference call presentation slides, which refer to Jim and Steve's remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Jim.
Jim, please go ahead.
Thank you, Chris. I'll discuss the second quarter results for the company, and Steve Chazen will follow with guidance for the second half of the year. Quarter income was $1.8 billion, or $2.23 per diluted share in the second quarter of this year, compared to $1.1 billion, or $1.32 per diluted share in the second quarter of last year. Net income was $1.8 billion, or $2.23 per diluted share in the second quarter of this year, compared to $1.1 billion, or $1.31 per diluted share in the second quarter of last year. Here's a segment breakdown for the second quarter. Oil and gas segment earnings for the second quarter of 2011 were $2.6 billion, compared with $1.9 billion in the same period of 2010. The improvement in 2011 was driven mainly by higher commodity prices.
The second quarter 2011 realized prices increased on a year-over-year basis by 39% for crude oil, 31% for NGLs, and 2% for domestic natural gas. Sales volume for the second quarters of 2011 and 2010 were flat at 705,000 BOE per day. Production volumes were 715,000 BOE per day in the second quarter of 2011, compared to 701,000 in the second quarter of 2010. The production guidance assumptions we gave you in last quarter's conference call were at a $95 WTI average price assumption. The actual average second quarter oil price of $102.56 reduced our production volumes by about 5,000 BOE per day. Domestic production volumes were 424,000 BOE per day, compared to our guidance of 425,000 BOE per day. The higher crude oil prices reduced Long Beach volumes by about 1,000 BOE per day. Latin America volumes were 33,000 BOE per day.
In the Middle East region, we recorded no production in Libya, consistent with our guidance. In Iraq, we produced 5,000 BOE per day. The decline from first quarter volume was due to the timing of development spending. Yemen daily production was 23,000 BOE, compared to 33,000 BOE in the first quarter. Civil unrest and operational issues reduced our daily production by 3,000 BOE, and higher prices and lower development spending rates reduced daily volumes by 7,000 BOE. The remainder of the Middle East had production of 230,000 BOE per day, compared with 235,000 BOE per day in the first quarter. Qatar's production was lower by 7,000 BOE per day, mainly due to planned maintenance and mechanical issues.
Our second quarter sales volume guidance, which assumed a $95 WTI oil price, was 725,000 BOE per day, which translates to about 720,000 BOE per day at the higher actual prices for the quarter. Our actual volumes were 705,000 BOE per day. The lower volumes resulted mainly from the lower production in Yemen and Qatar and the timing of liftings in Oman and Qatar. Second quarter 2011 realized prices improved for all our products over the first quarter of the year. Our worldwide crude oil price was $103.12 per barrel, an increase of 12%. Worldwide NGLs were $57.67 per barrel, an improvement of 10%, and domestic natural gas prices were $4.27 per MCF, an increase of 1%. The second quarter of 2011 realized oil price represents 101% of the average WTI price for the quarter.
Oil and gas production costs were $11.88 a barrel for the first six months of 2011, compared with last year's 12-month cost of $10.19 a barrel. The cost increase reflects more work over in maintenance activity and higher support costs. Taxes, other than on income, which are directly related to product prices, were $2.36 per barrel for the first half of 2011, compared to $1.83 per barrel for all of 2010. Total exploration expense was $62 million in the quarter. Chemical segment earnings for the second quarter of 2011 were $253 million, compared to $219 million in the first quarter of 2011. The second quarter results, one of the highest ever recorded for the chemical segment, reflected higher margins and volumes across most product lines.
Midstream segment earnings for the second quarter of 2011 were $187 million, compared to $114 million in the first quarter of 2011 and $13 million in the second quarter of 2010. The increase from first quarter earnings was mainly due to higher marketing income and improved margins in the gas processing business. The worldwide effective tax rate was 38% for the second quarter of 2011. Our higher proportionate domestic income draws closer to the U.S. statutory rates. Our second quarter U.S. and foreign tax rates are included in the investor relations supplemental schedule. Let me now turn to Occidental's performance during the first six months. Quarter income was $3.4 billion, or $4.19 per diluted share, compared with $2.2 billion, or $2.67 per diluted share in 2010.
Net income was $3.4 billion, or $4.13 per diluted share for the first six months of 2011, compared with $2.1 billion, or $2.61 per diluted share in 2010. Cash flow from operations for the first six months of 2011 was $5.6 billion. We used $3 billion of the company's total cash flow to fund capital expenditures and $1.2 billion on net acquisitions and divestitures. We used $685 million to pay dividends and $1 billion to retire debt. These and other net cash flows resulted in a $2 billion cash balance at June 30. Free cash flow from continuing operations after capital spending and dividends, but before acquisition and debt activity, was about $1.8 billion. Capital spending was $3 billion for the first six months, of which $1.6 billion was spent in the second quarter.
Year-to-date capital expenditures by segment were 85% in oil and gas, 13% in midstream, and the remainder in chemicals. Our net acquisition expenditures in the first six months were $1.2 billion, which are net of proceeds from the sale of our Argentina operations. The acquisitions included the South Texas purchase, a payment for the costs already incurred for the Shah Field development project, and properties in California and the Permian. The weighted average basic shares outstanding for the first six months of 2011 were $812.5 million, and the weighted average diluted shares outstanding were $813.3 million. Our debt-to-capitalization ratio declined to 11%, compared with 14% at the end of last year. Oxy's annualized return on equity for the first half of 2011 was 20%.
Copies of the press release announcing our second quarter earnings and the investor relations supplemental schedules are available on our website at www.oxy.com or through the SEC's Edgar system. I'll now turn the call over to Steve Chazen to discuss the guidance for the third quarter.
Thank you, Jim. As we look ahead to the back half of the year, at average oil prices about $95 WTI, we expect the back half of the year in oil and gas production to be as follows. Domestic volumes are expected to increase by 3,000- 4,000 BOE per day each month compared to the previous month. This should result in average third quarter production of about 430,000- 432,000 BOE a day. Latin America volumes should remain comparable to the second quarter. The Middle East region production is expected as follows. Consistent with the second quarter, we expect no production for Libya. In Iraq, we are still unable to reliably predict spending levels, which have a related impact in cost recovery barrels.
In Oman, production is expected to grow from our current gross production of 210,000 BOE a day to a year-end exit rate of 230,000 BOE a day, which should result in about a net of 2,000 BOE per day per quarter growth. In Qatar, we expect to gradually regain the production rate lost due to planned maintenance and mechanical issues, resulting in about 3,000 BOE per day growth rate each quarter in the second half of the year compared to the second quarter average. In Dhafn and Bahrain, production is expected to be similar to second quarter levels. In Yemen, forecasting production volumes remains difficult, although currently Oxy operated production has been partially restored. We expect the range to be between 23,000 and 27,000 BOE a day. We expect a lifting in Iraq in the third quarter of about 600,000 bbl of oil.
Including this lifting, we expect sales volume to be about 725,000 BOE a day at $95 West Texas Intermediate. A $5 increase in West Texas Intermediate would reduce our production sharing contract daily volumes by about 3,500 BOE a day. Our total year capital expenditures remain at $6.8 billion, same as the guidance we gave you last quarter. With regard to prices, at current market prices, a dollar per barrel change in oil prices impacts quarterly earnings before income taxes by about $37 million. The average second quarter WTI oil price is $102.56 per barrel. A dollar per barrel change in NGL prices impacts quarterly earnings before income taxes by $7 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 $4.40 per MCF.
Additionally, we expect exploration expense to be about $80 million for seismic and drilling for our exploration programs in the third quarter. The chemical segment earnings expect to moderate to about $225 million, mostly due to seasonal factors. The third quarter chemical segment earnings expect to reflect continued strong export demand and overall good supply and demand balances across most products, offset by some seasonal factors and turnarounds. Historically, the fourth quarter is typically the weakest quarter, and generally, earnings are about half of that in the third quarter. We expect our combined worldwide tax rate in the third quarter of 2011 to remain at about 38%. As far as our activity is concerned, in California, we expect our current drilling programs to result in more predictable production growth going forward. The status of permitting is generally unchanged from the prior quarter.
We've obtained enough permits to allow us to prosecute the program at the current pace until year-end. However, there remains some uncertainty around future permits, particularly related to injection wells. Our overall rig count in the United States has gone from 38 at the end of 2010 to our current rate of 59, as it is expected to grow to 74 at the end of the year. This represents a 25% growth in our total rig count from current levels. The growth will be in the Permian, the Williston Basin, and South Texas. This program leads to continued growth of production into next year. I think we'll allow you to take your questions now.
Thank you. At this time, if you would like to ask a question, press star and the number one on your telephone keypad. Your first question comes from David Heikkinen of Tudor, Pickering.
Thank you. Good morning, Steve. Just thinking about your production targets and the monthly sequential growth, can you give us where you were in June domestically, by region, just so we can kind of build from there?
You know, we don't report that way. What you have to do is use the average, because that's the way it'll be reported. If you take the average, which is the 424 number, and say, "Okay, that was the average," it'll be average to average when the numbers actually come out. If it'll be up 3,000, up 6,000, up 9,000 if it's 3, and then you average that out and you wind up with 6,000 of growth for the average for the quarter. If you start at the end of the quarter, you don't actually see the exit rate for the quarter.
As the regionalization of your domestic, kind of how you see that 3,000- 4,000 barrels a day of growth, how much of that's California, Permian, Williston, any idea of that would be helpful?
We risk these numbers. The number that we use might be a risk number as opposed to, you know, the maximum number that could come out or the worst number. It's probably misleading to say exactly where. Clear that there's going to be the bulk of it, the overwhelming majority will come out of California. There'll be some growth in the Williston, but the Williston's small anyway, and some in the Permian. I think if you look at the third quarter, you'll see the bulk of the growth out of California with smaller amounts out of the rest. If you go into the fourth quarter, because of the ramp-up in drilling in the Permian, you'll see a little more growth in the Permian, but continued pretty strong growth in California as the wells come on. That's sort of what it looks like.
To actually give you how we figured it out, I'd have to, you know, start with unrisked numbers, and you know, I don't want to give those kinds of numbers out.
Okay. On the California permitting side, you talked about injection wells being some uncertainty. Can you just walk us through any color around what that means? Is that just water disposal availability, and will you become limited as far as total oil volumes by that injection capacity?
At some point, we will. I don't think we're up against it now. Where it'll affect more than anything is actually Thums, more than at Elk Hills or the other places, because we probably have enough for a while. Thums, they got some, you know, that's really a water injection sort of process. I think you're going to, that's probably where you'll see it. The numbers are real small for this year, certainly within the noise of the rest of the numbers.
How do you think about opportunities for additional acreage acquisition and where things are currently in the market?
I don't know how much more there is in California. I probably don't want to buy the land underneath the building here to drill. I think California probably, probably not much. In the Permian, we continue to buy some small parcels of acreage for Wolfberry drilling primarily. In Williston, there's a lot of acreage for sale. If we were open seven days a week, there'd be seven guys here every day to sell us acreage. There's a lot in the Williston, and we're pretty picky about what we do. There may be a small amount of acreage acquisition there. I don't see a large deal flow in the back half of the year, although I think I said that last year at this time and was shown to be completely wrong.
Thanks, Steve.
Thank you.
Our next question comes from Paul Sankey of Deutsche Bank.
Hi, Steve. Hi. Can we just go back to the new disclosure on the rig count? What's the outlook beyond 2011 for those various counts, do you think?
The California one depends on the permitting. If we had better, you know, more visibility in the permitting, we'd lay more rigs on to the back half, the fourth quarter. Right now, this is the visibility we have, and that's why it's showing the way it is. Once we get more visibility, we'd probably raise the count.
That would be a raised count just for 2011, you mean? Exit rate?
Yeah. I mean, yeah, your exit rate, and it would, you got to get the rigs on before you get into 2012. We'd start contracting for the rigs, so you'd see a higher exit rate. Right now, this is all the visibility we really have. We're looking at the Permian, and we're trying to figure out what the right level is. More likely than not, it'll go up some more, and maybe even sizably more, depending on how we can figure it out. I think South Texas is about the same, and there'll be some growth in the Williston. I think, almost, a high probability of the Permian, and if we can get the permitting issues worked out in the next six months, you'll see significantly higher rig counts in California. Right now, I can't, I just don't have a basis to raise that rig count in California.
Fair enough.
What we're doing now will generate a fair amount of production growth. I'm not really concerned that this is going to be bad, but we could do some more. Right now, I just can't, I don't have enough confidence in the permitting process.
This level of rigs in California would generate growth through 2012?
Oh, yeah.
At the kind of pace that you're talking about?
Oh, yeah.
Which seems to be about 2,000 bbl per month?
Somewhere in that, you know, we give you the 3,000 bbl- 4,000 bbl. Yeah, you know, some of that will be California, maybe in some quarters, all of it. It's just hard to say exactly what it is. Again, I use risk numbers.
Understood. If we looked at the year-over-year, you're flat. Looking backwards, obviously, over 2010- 2011, Q2 to Q2. I know.
That's on sales, I think.
I understand. Yeah, it's on sales, and I understand, obviously, that net there's been a negative, basically, from Libya, but all the other movement. From here forward, are we looking again back to the 5%- 8%? If we ask you again in a year's time, are we going to be in that 5%- 8% volume growth range that you've talked about in the past?
At least that, because I think the domestic businesses, you know, it's been a surprise. I could be wrong. I think the $3,000- $4,000 a month for the domestic business is pretty solid for a while. Maybe we'll do a little better, but I think that's a good risk number for us.
Thanks, Steve. If I could ask you about Phibro, the midstream segment business, it was a good number, and we were expecting a headwind from Phibro.
There was a small headwind.
Okay. Phibro was a net negative. What I'm thinking about is whether the run rate of your midstream business is just structurally higher now as a function of Permian activity and piping, and whether we should think rolling forward of a higher through the cycle or even growing, I guess, midstream profitability.
You know, we break it out because it's the most volatile, and we have a hard time predicting it. I think the way to think about it is that volatility and price volatility, oil price volatility, and wide differentials between, say, the Cushing and the world prices generates generally higher numbers.
Yeah. Okay.
Now, it might generate lower numbers too, but you know, it reduces the predictability a lot. If I were to look at it and I'd say, "What's the average?" I'd average the first and second quarter to get sort of an average number.
Yeah. Just going back to Phibro, I think I seem to, forgive me if I've garbled this number, but I think you said that the range historically would be a - $0.08 to + $0.12. Was it a range of Phibro profitability or loss?
I can't remember anymore, but he was ahead for the year at mid-year. He had some, you know, I'm finding out how you view a modest loss in the second quarter. For the year, he's ahead, and he's well ahead now. I think I've told you this before, no sense in watching it. It's like an NBA game. You may as well tune in the last 30 seconds and forget the rest.
Fair enough. Forgive me if I missed this, this is the last one for me. I've kind of missed the Iraq guidance. I think you have 5,000 of production with no sales in Q2. Is that correct? Did you say 7,000 a day of production?
I don't think we said for production in Iraq. The field is doing fine. Did we say that? The field is doing fine. The gross is really doing fine. Our nets may be 6,000-ish, but it really depends on the investment, which has slowed up considerably. I don't really know. We do have a sale, we know, of 600,000 bbl this month. We'll have some actual sales this month.
I assume, given the spending slowing, that you will, the outlook for next year on Iraq volumes is difficult.
I don't know how to do it because it reacts so quickly to the spending. You know, if we spent more, production would go up immediately. I just don't know.
What is the spending constraint?
are a lot of issues, I think, with the operator and that sort of thing, getting permits approved, or not permits, but contracts approved.
Okay, I'll leave it there, Steve. Thank you very much.
Thanks.
Our next question comes from Ed Westlake of Credit Suisse.
Yeah, good morning, Steve.
Morning.
Just on California, you've spoken in the past about trying to get these larger areas permitted because then you can progress a little bit quicker once you actually get the permit through, and that means you get probably more effective capital. Could you talk to us in terms of, have you got one of these larger permit areas, two, three? When did you put those permits in? When, you know, given they might take 12- 18 months, you might get a larger area permitted? You know.
I don't really know. We could go into that. I don't know how helpful it is. We put a number of them in for large areas, a fair, a sizable number. We just don't know what the process is. It's not exactly transparent.
At this stage, you don't really have a feeling for how long it's going to take for one of those larger areas to actually get it?
I think it's a non-transparent process.
Right. Okay. Maybe then switch to the increase in rig count. Three to four monthly sequential increase over the second half of this year, but obviously, your rig count is increasing as you go through the second half. As you look into 2012, would it be fair to think that that would accelerate a little bit?
Yeah. Let's say we spot a well today. It doesn't make any difference where. Spot a well today, it will have a small effect on the production in the fourth quarter, because it takes, say, 90 days or so, you hook it up, and then you get a partial quarter. What you're seeing is a wedge of this stuff pushing into next year. Our exit rate going into next year ought to be fairly attractive with a pretty high backlog of production. It just takes a, you just lose sight of how long it takes from today, what you spend to drill today to when you actually get a meaningful measurement of production. I think we're on good track now, and I think we'll have an attractive exit rate in the United States as the year ends.
The final question is around realizations. Maybe any strategies to perhaps, or any changes we should be aware of to try and sort of get away from WTI inland pricing towards more international pricing across the portfolio?
We're not trying to solve the industry's problems in this. We're just trying to solve ours. I just assume not comment on our strategies, but to point out that, for example, California basically gets world prices.
I'm mainly thinking perhaps in the Permian.
In the Permian, some of that could fall into the midstream rather than into the oil and gas.
Right. Okay, thanks very much.
Our next question comes from Doug Leggate of Bank of America Merrill Lynch.
Oh, thanks. Good morning, Steve. Morning, Jeremy. Steve, at the beginning of the year, you suggested you make it 107 shale wells drilled this year. What's the latest estimate?
Sorry, I missed you.
At the start of the year, I believe you suggested that you would drill about 107 wells.
Shale wells.
What's the latest estimate?
Bill can answer that.
Yeah. Doug, good morning. I think right now we're looking at somewhere between 150 and 175 shale wells to be drilled in California for the year.
How many did you complete, Bill, in the second quarter? You gave us a first quarter number. I think it was 26. How many did you complete in the second?
Yeah, it was 55.
Completed?
Correct. It wasn't necessarily hooked up.
That's what I was going to say. They weren't, so your bite log is building, basically.
Yes, it is.
Steve, at dinner about, I guess six weeks ago, you suggested that your kind of first base target was to get to drill around 300 wells a year. To what extent, I mean, what is it going to take to get there, and how engaged are you with the state government in trying to achieve that objective?
Yeah, we're engaged with the state. I just do not go into our state relations. I think we're making some physical progress where we can. I think the state, eventually, I think the state will come around. It just takes longer.
I guess a couple of other quick ones, if I may. The production from the shale is obviously what we're all focused on in terms of how quickly that can ramp up. Are you prepared to give us what the current production is from that particular part of the portfolio and how you would expect, given your decline curves and the rate of drilling, how you would expect that to progress, let's say, over the next 18 months?
I don't think we're, I'm not going to give you a forecast because, again, the forecast that, you know, the overall forecast I'd give you is a risk number. The bottoms-up numbers are essentially, you know, sort of unrisked but I think Bill can give you some numbers on where we are.
Yeah, Doug, right now, in terms of current shale production in California, we're running about 45,000 barrels of oil equivalent per day.
Given the pace of the potential hiccups, Bill, where would you expect that to exit the year?
I think we're not into the forecasting of that. Again, because I think you'll be mixing risk and unrisked numbers on the totals.
Got it. All right. The final couple for me are again related to the same thing. Steve, the status of the gas plant, please. I believe after the maintenance in Q1, I guess we should have been expecting some recovery there. Finally, the Rosetta acquisition, how much of that was included in Q2? I guess.
Very little because it didn't, it closed in pieces during the quarter, so it was really a small number.
Okay, the plant status?
The plant is ready. April, is that the date?
Yeah, Doug, we're targeting April 2012, and actually, we're currently running a little bit ahead of schedule on that.
Sorry, Bill, I was talking about the existing plant.
The existing plant is an old plant that's not terribly reliable.
All right. I'll leave it at that, guys. Thanks a lot.
Thank you.
Our next question comes from Jason Gammel of Macquarie.
Thank you, guys. A few more on California, if I could. Of the 29 rigs that you have running in California, Steve, can you talk about how many of those are actually pursuing the unconventional objectives you have? Out of that number, how many are looking to de-risk further acreage versus drilling in the, I believe, 200,000 acres that you said you thought you had de-risked on the first quarter call?
Yeah, Bill can answer.
Jason, right now, of the 29 rigs we have running in California, fully 20 of those are drilling unconventional plays or horizons. Of that 20, roughly four to five are in the process of de-risking additional acreage. Is the 200,000 acres still a reasonable number for us to be thinking about in terms of de-risk?
I think that's plenty for now.
Agreed. One more, if I could, it's probably too early to talk about this, but I'm going to try it anyway. Anything on type curves, initial production rates, where you expect ultimate recoveries to be, etc.?
I think as we look at this, if we went back to what we said roughly a year ago or a little more than a year ago, I think we're a little more optimistic on the verticals and a little more pessimistic on the horizontals.
Steve, can you remind me what you were expecting on the verticals? Is that 300 bbl a day IP rate, 400?
Yeah, Jason, right now we're averaging about 370, and that's BOE, that's equivalent per day.
Of that 370 or just on an overall mix of production out of the unconventionals, how much would you expect to be gas versus black oil versus condensate?
Yeah, it's about 60/40, you know, 60% oil and about 40% gas.
Okay, thanks a lot, guys. I appreciate it.
Our next question comes from Faisel Khan of Citigroup.
Hi, good morning.
Morning.
On the 3,000- 4,000 barrels per month of domestic production growth through the end of the year, how much of that is gas and gas and oil?
Because of the way it was computed, there's no particular easy way to tell. I would guess the bulk of it, 75%, 80% would be oil.
Okay. Gotcha. In terms of your.
Oil meaning real oil. NGLs aren't oil, just so we're clear what we're talking about. NGLs are something between oil and gas.
Fair enough. If I'm looking at the overall domestic natural gas, dry gas production portfolio, is that production kind of expected to remain flat through the end of this year, or do you expect declines to take place?
No, I think it'll probably grow.
Okay. Okay. The last.
Sometimes, especially in California, you drill it, and sometimes it's a little misleading because if you drill a shale well, you might take it down to the deeper zone, slightly deeper zone. The slightly deeper zone tends to be gassy, and you may not have drilled a well for that purpose, but all of a sudden, you got some gas. Our ability to, as we take what was designed as a shale well down a little bit further, you can wind up with a gas zone. You get a little more volatility in the number, which is not a bad thing, by the way. Predicting this stuff, you might get lucky and find a big gas zone, and our gas might go up and sort of by serendipity.
Okay. Is that gas able to be produced into the market, or is there infrastructure required to?
Depends on where it is, but the answer is, you know, so far we've been able to manage it.
Okay. Fair enough. My last question is on the Permian Basin. In terms of your rig count going up in that basin, how much of that is split between the Delaware and the Midland Basin?
Bill
you know.
I would say, looking forward, Faisel, is that what you're asking?
Yes, sir.
Yeah, I'd say probably 70% or so is going to be devoted to that delta, that incremental rig count is going to be devoted to the Delaware Basin as opposed to the Midland Basin.
Of the delta from kind of where we are today versus what will be at the end of the year?
Right.
Okay. Great. Thanks, guys. I appreciate the time.
Sure.
Our next question comes from Sven Del Pozzo of IHS.
Good morning.
Morning.
With that new disclosure on the rigs, on the back page, is gross operated rigs, on a net basis, are the increases similar?
Yeah.
Okay.
There's a whole bunch of non-operated activity also, especially in the Permian, really. We don't have any way of sort of predicting that.
Okay. The overall increase in the rig count in the U.S. going from 38 to 59, does that, are those conventional drilling rigs, or are there workover rigs included?
No, that's just strictly drilling rigs.
We got.
A very large number of workover rigs. That would just obscure the numbers and include workover rigs.
Okay. The IP rate you mentioned, the 370 for the California shale well, is that a 24-hour rate?
It's actually longer than that. It's generally, you know, what a stabilized rate would be over, say, a week's time because, you know, these wells have to clean up before they stabilize. It's really over a week or even longer period of time.
Okay. How did your operations team deal with the flooding in North Dakota? I mean, you're farther away from the river, so I'd assume there was less flooding where you guys are, but I'm not sure.
It really didn't affect us at all, given where we operate.
Okay, I'm seeing an increase in NGL production from the U.S. in the second quarter over the first quarter. Is that correct? I mean, it's a substantial one.
NGL production?
Yeah, I might be wrong.
I didn't think it went too far to get off.
No, forget about that one.
Okay.
In the Permian, Apache was mentioning the application of modern drilling and completion techniques, horizontal application to their CO2 floods and also water floods. I'm assuming whether you guys see similar upside.
We don't have a basis to compare with what Apache's saying. I don't know what that's about.
Okay. All right. That'll do it. Thank you very much.
Thank you.
Our next question comes from Duane Grubert of Susquehanna Financial.
On the CO2 theme, we've had others in the sector see CO2 supply as a constraint. I think you guys have been pretty proactive in telling us why it's not a constraint. Can you talk to us about how you think of allocating capital in the Permian to non-CO2 versus CO2 projects, and if CO2 available is a factor in that allocation?
We supply about half of our own CO2, and we have ways to increase that. The fact that some smaller operator has a problem getting CO2 doesn't surprise us. The market's fairly snug. It's a very profitable business. We allocate it in sort of a, we have a five-year plan for putting CO2 in the ground, and we just go ahead and do it. It's a very profitable business because we've spent all the capital, really.
Jumping over to one of your recent acquisitions, the heavy oil stuff in California, do you have any early read on your enthusiasm for your heavy oil project?
It's a one-off thing. I don't think we're interested in more heavy oil. This was a pretty good opportunity. It was an undrilled field. You know, five years from now, it'll be pretty good, pretty good results for us.
Okay. You have been buying a lot of what appear to be one-off things that could have legs domestically. I'm sure people also pitch to you international assets. Do you have any appetite to be shopping internationally?
We always look for opportunities internationally, but in places we understand, of course. I think it'd be, I don't think we'll be drilling much in Antarctica or anything like that. We're looking for places we understand and where we can make substantial returns. You don't want to go to international just to produce empty barrels.
To follow on to an earlier comment you guys made on California, the unconventional wells, you got about 20 out of 29 rigs more or less developing and four or five de-risking. Can we really think of that whole program as being in a development stage now, or are there certain aspects of it, like infrastructure sizing or maybe where the footprint is, that you're still in less of a development stage and more of a figuring out what you want to do stage?
We're always figuring out what we want to do. I think we always are looking to expand it and figure out new opportunities. There are different plays that are around that we haven't talked about publicly. We're always looking for different things to do. We're trying to figure out where to build, you know, the next gas plant. There are a lot of things we do, and we're trying to figure out what the program will be over the next decade. That requires a certain amount of, you know, it's not high-risk exploration, but significant step-out activity just to figure out where we're going.
With the current sector environment, with the high oil prices and the ability to do a lot of work in domestic areas that didn't frankly exist 5 or 10 years ago, can you remind us of your philosophy of cash use and maybe how the current environment might be influencing or changing that, if at all?
Cash use has always been the same. I think I have the same slide for the last 15 years. Number one use is maintenance capital. The second use is dividends. The third use is growth capital. The fourth is acquisitions, and the share repurchases are last.
Very good. Thank you.
Thanks.
Our next question comes from John Herrlin of Société Générale.
Yeah. Hi, a bunch of quick ones for you, Steve.
Sure.
For your volume growth domestically in the second quarter, was the bulk of that South Texas?
I'll have to, maybe somebody will look at the numbers. I don't know whether it was the bulk of it or not.
Okay. Next one, California.
No, I don't think so.
Okay. With California, you said that the lion's share of the rigs currently running are unconventional. What would it have been a year ago, just to give some perspective?
It was more conventional. A year ago, we were probably even 50/50 on it, and we've shifted because we said we were going to do that.
Okay. Year-end, should we assume that there's no Yemeni volumes?
No. I think in the case of Yemen, we think that there's a reasonable chance that the government, first of all, half the production isn't really covered by that. It's other fields that have longer contracts. It looks to us that there's at least a reasonable chance that the government will allow us, allow Nexen to continue to operate the Masila field while it figures out what it's going to do. I think there's a reasonable chance that the stuff in Yemen will continue for a while at the full rate. No guarantees of that, obviously. You know, about half the production is unrelated to that and is pretty much unaffected by this.
Okay. For the properties that Nexen's operating, would you expect them to pay a sizable upfront bonus, some sort?
We don't know. I think right now there's really nobody to negotiate with. I assume that what will happen is that they'll just let it go for a while until there's clarity in the government there.
Okay. All right. That's fine. In terms of the property acquisition marketplace, you're full in California. You said there's a lot for sale in the Williston. There's always drips and drabs in the Permian. Are you considering any sort of new areas?
In the United States?
Yes. Correct.
No, not really. I mean, we tire kick a lot of stuff, so we understand what's going on. I don't see any, and certainly not this year.
Okay. You're accruing a lot of cash. Would it be reasonable to assume that you would focus on more dividend growth or potentially a share buyback, which I know you don't particularly like, but is that a consideration?
We like dividends better than share repurchases.
Okay. That's fine. Last one for me. We're seeing a lot of gratuitous divorces these days in the public marketplace, you know, disintegrations, whatever. Would the board ever consider maybe doing a split of Oxy between domestic and international?
You just have to come to the conclusion that that actually creates value rather than just some sort of something to entertain investment bankers. You never say never, but I think right now there's a lot of synergies between them. It is very difficult for the international business to have anything less than a single A credit rating to get new contracts, and it's just improbable that that would create new value to split them off that way.
Great. Thanks, Steve.
Thank you.
Our next question is from David Heikkinen of Tudor Pickering.
Bill, just had a follow-up question thinking about the vertical well split around talking about 60% oil, 40% gas. That's for all the wells drilled, including the Elk Hills primary wells, but your guidance is reflecting more oil growth. Can you talk us through kind of what are the kind of current well splits for the wells you're drilling on the vertical unconventional?
Most of them are vertical wells, you know, in terms of the unconventional wells. Nearly all are drilling vertical wells as opposed to horizontal, just speaking to the unconventional.
I'm trying to understand the 60% oil, 40% gas, and the average of all the wells drilled versus the guidance that most of the growth is oil.
What I was referring to, you know, was the 60/40 split was just solely on unconventional shale wells.
That's an average rather than the outcome. If they look at it, that's what they're doing because when you produce the oil, you get a fair amount of gas with it. The wells are oil wells. They just have associated gas. It's just hard to, most of the growth is out of oil, but I think you asked about a really, he answered a very narrow range of wells.
Out of your total, what's your conventional development program heading forward, and what do those wells look like?
Those wells are basically oil wells, and they're with less gas. Nothing wrong with the gas. I mean, you get $4 and they have high rates, so you get your money back pretty quick. We think most of the growth for this year will be oil because we're kind of biased it that way.
Just.
Although, occasionally, you have this issue with the, you drill a little bit deeper and you wind up in a gas zone.
For the properties required, it was kind of 30 million cu ft- 35 million cu ft equivalent a day, primarily.
I think it was less.
Okay.
I think it's less than that. We're the largest gas producer in the state. That's an old field, been around a long time. It's in a different part of the state. I think we probably market a little different than maybe the predecessor.
Okay, thanks, guys.
Thanks.
Our next question comes from Katherine Minyard of JPMorgan.
Hi. Good afternoon, or morning. Quick question on your comments on California and some of the permits. You talked about there being some uncertainty around future permits, particularly related to the injection wells. I was just curious as to whether there's something about the nature of the injection wells that's holding them up, or is it their location?
No, it's an industry issue, not necessarily related to us.
Okay. In light of that, how much of your growth forecast in California depends on successfully permitting the injection wells, and does that change over time?
It's a long-term problem for us rather than a short-term problem. The only place that would affect us, I mean, in sort of intermediate terms, a little bit under 1,000 bbl a day, it's thumbs. Other than the rest of it, ultimately, you need to dispose of the water. It's hard to produce oil without producing saltwater. We're going to have to ultimately have more injection wells. It's an issue, but it's more an issue for people in the steam flood business, which, you know, there's some large players in that here in California that have, I think, a much bigger issue than we do.
Okay. All right. Thanks. Can I just switch quickly to Latin America? It just looks like the production that's being reported from Colombia is kind of trending downward. I'm just curious as to whether that's a price-related impact or whether it's project delays.
It's basically, there's a kicker to the Colombian government on price.
Okay. All right. Thanks very much. I appreciate it.
Our next question comes from Evan Calio of Morgan Stanley.
Good afternoon, guys. Thanks for taking my call. If refining keeps on a roll here, it's going to cannibalize the front of your conference call, at least for some folks. I'll give you a break on the California questions, and let me know.
Oh, good. We thought we'd run out of counties.
I thought so. On the Permian, my question is, are wider differentials impacting the way you think about capital allocation and potentially away from the Permian, at least on operating level, at least until dips normalize and move into another part of your portfolio?
At $100 oil, which is the WTI price, you could drive a truck through the margins, you know, on a cash basis or reported basis or whatever. We historically viewed $100 as a pretty decent price. The fact that somebody says, "Maybe it should be on some basis $106," yeah, that's true, but this is still $100. Given a very oily portfolio in the Permian, I mean, this is enormously profitable. You say, "You should get some more." I don't know. We should get some more now, but I don't know about a year from now. I think we'll take the money and run.
I mean, that's, I guess, the second question. Clearly, you know, respect to that's very profitable. Do you think of changing any kind of hedge position into 2012 if you have?
We're not hedgers. We don't know. The FIBRA guys are bullish on oil forever. I guess we're not hedgers in that sense.
Okay. Nothing to protect any, you know, TILLS fixed book?
The reason we keep a sort of debt-free balance sheet is so we don't have to protect our downside. We don't have to buy basically insurance for downside. We're not good speculators on product prices.
Okay. That's fair. Maybe the last question on Iraq. I apologize if I missed it earlier. You mentioned in your last call, you begin liftings in the second half of.
If it's lifting, it'll be this month. The first lifting is this month.
Okay, perfect. Thank you, guys.
As a reminder, if you would like to ask a question, press star and the number one on your telephone keypad. Your next question comes from Doug Leggate of Bank of America Merrill Lynch.
Hey, Steve. Sorry for the follow-up. I just wanted to get clarification on a couple of things. You've said in the past that your shale wells were predominantly oil, meaning north of 90%. Has that changed?
No.
What's the 60/40 then? I'm confused.
The 60/40 is related to whether it's called an oil well or a gas well.
What is the majority of the wells you're drilling? Are they 60% oil or 90% oil? More.
Closer to 90%.
Okay. Thanks.
We may occasionally, you should understand that sometimes you drill a little deeper and you wind up with a pretty gassy well.
Sure. No, I understand that. Predominantly, if we're talking about completing 150- 175 wells this year, what proportion of those would you say were in the 90% range than in the other range? It makes a heck of a difference to the volume, obviously.
Probably not as much as you'd think, because the gas wells will have a lot of liquids with them.
Right. The IP rates, again, going back to Bill's comments, previously, you've said sort of 350, you know, was a good run rate as an IP rate, but you described that as longer than 30 days, which is a bit different from Bill saying seven days. Can we get some clarification on that also? Maybe just reiterate how you see the decline curve as we compare it to what you gave us a year ago.
Doug, just to clarify, when I was talking about seven days, I was talking about time for the wells to clean up. That 370 BOE a day number really is a 30-day stabilized IP number. That's an average.
How would I think about that in terms of, let's say, a month down the line? Three-day average, is that a good number, or?
That's a good number, Doug. Yes.
Okay.
I think what he was trying to say is, as opposed to just an IP rate like a Hainesville well, which is sort of one day or something.
Right.
What he's trying to say is it takes him a week or so to clean up the well. It stays at this 370 for a month or so, and then the decline would begin.
All right. Great. The final one is, previously, $3 million a well was kind of the number to drill, complete, and hook up, I guess, that you've given us. Can you just talk a little bit about what's happening to service costs in the state? Whether that is also still a good run rate that we should be thinking about in terms of CapEx, I'll leave it at that.
Yeah. Doug, I think $3.5 million- $4 million is really a good range. Drill, complete, and hook up to sales. We are seeing some inflation on pressure pumping, obviously, just as the whole industry is, but that's still a pretty good number, $3.5 million- $4 million.
You're not fracking these wells, Bill?
No, there's a few that we do fracture stimulate, but the majority are just acidized.
Okay. Great stuff. Thank you.
Your final question comes from Sven Del Pozzo of IHS.
Yeah. Sorry. Just returning to the NGL question from earlier. Yeah, it did go up. Just wondering, is that part of the South Texas acquisition? Is that rich gas? Is that why I'm looking at the domestic NGL production?
The additional NGLs from last year, from a year ago, come from South Texas and from the Permian.
Are we going to see in the future similar ramp-up in NGL production sequentially quarter-over-quarter?
No.
Okay, thank you.