Patrick Cassidy - Director of Investor Relations G. Steven Farris - Chairman, Chief Executive Officer and Member of Executive Committee Rodney J. Eichler - President and Chief Operating Officer Thomas P. Chambers - Chief Financial Officer and Executive Vice President Janine J. McArdle - Senior Vice President of Gas Monetization

Arun Jayaram - Crédit Suisse AG, Research Division John Freeman - Raymond James & Associates, Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Pearce W. Hammond - Simmons & Company International, Research Division John Malone - Global Hunter Securities, LLC, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Good afternoon. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation Second Quarter 2012 Earnings Release Conference Call. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Mr. Patrick Cassidy, Director of Investor Relations. Sir, you may begin.

Thank you, Regina. Good afternoon, everyone, and thank you for joining us for Apache Corporation's Second Quarter 2012 Earnings Conference Call. This morning, we reported earnings of $337 million or $0.86 per diluted share. Adjusted earnings, which excludes certain items that impact the comparability of results, totaled $821 million or $2.07 per diluted share. Cash flow from operations totaled $2.4 billion for the quarter. On today's call, we will have 3 speakers making prepared remarks prior to taking questions. First, we will hear from Steve Farris, our Chairman and Chief Executive Officer; followed by Rod Eichler, President and Chief Operating Officer; and finally, Tom Chambers, Executive Vice President and Chief Financial Officer. We prepared our quarterly supplemental data package for your use, which also includes a reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or pretax margins. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussions may contain forward-looking estimates and assumptions, and no assurances can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thank you, Patrick, and good afternoon, everyone, and thank you for joining us today. I'm sure all of you have seen that in our recent Investor Day, we outlined our extensive oil and liquids drilling inventory in the onshore U.S. We have over 67,000 future drilling locations that have been technically assessed, and we also have 9 billion barrels of oil equivalent net unbooked inventory that is available to drive our growth in the years to come. And this inventory is already beginning to deliver meaningful results in our onshore. During the second quarter, our Permian and Central regions grew net production at annualized base of 23% and 18%, respectively, and this was before the contribution of Cordillera assets that we acquired at the end of April. Obviously, not every quarter's going to be as good, but we're firmly on track to deliver the double-digit growth in these regions for the years to come, as we outlined in our Investor Day. Moreover, if you count the land drilling rigs operating in the United States from the Rockies to East Coast, Apache has 62 rigs running, which is the second most active operator out of all the independents and majors, and that's only behind Chesapeake, which really has a different focus and business model. I might point out that not a single 1 of the 62 rigs is drilling a gas target. We said we were going to step up our U.S. drilling activity to exploit our enlarged portfolio, and we're doing just that. Our total reported production in the second quarter was reduced by a 16 -- which is the difference between a hit and a miss on our production growth. We had offline about 16,000 barrels of oil equivalent a day. This includes 4,800 barrels a day due to…

Thank you, Steve. I'll begin with onshore North America as it was the focus of our recent Investor Day conference and is the area where we are currently most active. In the Permian, we reached a company milestone in the second quarter with production surpassing 100,000 barrels of oil equivalent per day marker for the full 3-month period. During the second quarter of 2012, net production was up 5.3% over the previous quarter at 104,500 barrels of oil equivalent per day, of which 72% was liquid and more than 3/4 of that was crude oil. Also included in total volumes are nearly 2,000 barrels of oil equivalent per day, of positive prior period adjustments, the majority of which are attributed to non-operated fields. Drilling at Deadwood in the Midland Basin and the Glasscock County continues to be a large contributor to growth, with horizontal drilling in the Wolfcamp emerging as a new development area. For the quarter, Permian averaged 32 drilling rigs, up 4 from the previous quarter, on the base properties, adding 187 wells, of which 167 were vertical and 20 were horizontal. We are currently running 36 rigs. Other than 2 weeks of working inventory, we have almost no backlog of stimulation jobs. In the Deadwood vertical play, we are targeting Wolfwood, that is the Wolfwood through the Wolfcamp reservoirs, and Fusselman vertical wells. We've had several notable test results with wells flowing in excess of 300 to 400 barrels of oil per day for intervals covering the Wolfwood reservoirs. We also have a number of locations where we'll initially complete only the deeper Fusselman formation and recompleted later at Wolfwood formations at hole [ph]. Our Amberjack well is a Fusselman-only completion and tested at a rate of 285 barrels of oil per day plus 180 Mcf per…

Thanks, Rod, and good afternoon, everyone. As you've read previously in our press release and heard earlier on the call, we are rapidly building a significant inventory of drilling opportunities and have established a robust platform for long-term growth across all of our regions. We achieved solid production level this quarter averaging 774,000 barrels of oil equivalent a day despite some significant third-party challenges. This is the ninth consecutive quarter of production growth, and we exit the quarter with continued upward momentum. For the second quarter, we reported earnings of $337 million or $0.86 per diluted share and adjusted earnings of $821 million or $2.07 per share, and we adjust for certain items that affect the comparability of results such as the noncash property write-down in Canada and foreign currency fluctuations. Our bottom line results were impacted by lower commodity prices, yet we were still able to generate revenues of almost $4 billion. This translates directly into significant cash flow from operations, $2.4 billion this quarter. Year-to-date, our cash flow from operating activities before changes in working capital was 3% higher than the prior year-to-date period. On the quarter, our cash flow from operations was down 10% over the previous quarter, primarily driven by lower oil and gas price realizations, which were down 12% and 8%, respectively. International gas prices helped mitigate the decline in earnings and cash flow, with realizations up slightly from the previous quarter and 29% higher than North American average realizations. For the past 2 quarters, we have realized over $4 per Mcf on our international production, a sharp contrast to the North American prices, which averaged well below $3 per Mcf over the same timeframe without the benefit of hedges. Year-over-year, we produced 100 million cubic feet a day of additional international gas. And in…

Thank you, Tom. We will now open the call to questions.

[Operator Instructions] Your first question will come from the line of Arun Jayaram with Crédit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: I'm wondering, Steve or Rod, if you could give us a little bit of a road map relative to the near-term production picture. The guidance is 6% to 9%. I know that's adjusted for asset sales, but the way I'm thinking about it is you produced about 748,000 barrels last year. If you back out 11,000 from asset sales and then you apply the 6% to 9% range, so that would put you in the 781,000 to 803,000 [ph] kind of range in terms of thousand barrels a day, is that how you're thinking about 2012?

We'd better hit that. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. Okay. And obviously, Steve, you highlighted you had quite a bit of production, 16,000 barrels come online, and you said most of that's come back. I don't know if you could give us a little bit of specificity around when that came back and just so we can kind of fine-tune our third quarter and Q4 numbers.

Yes, Rod -- I'll mention a couple of them, and then Rod will obviously give some more detail. But SemCAMS plant in Calgary went on, in Canada, went on, on July 6. So we should get all of that back. Now that's -- you've got all kinds of things going on in terms of it, but we -- that plant is back on. That was about 70 million a day. It was a big hit. We should have Lake Paige on about the middle of August. Grand Isle -- I mean, West Camp 43 is ramping back up. In fact, it should be back up right as we speak. It started ramping up about the fourth of July, and that was very unexpected downtime. Lake Paige was totally unexpected. We had a confluence of things that hit us all in one quarter, which you usually get over the whole year. In terms of the North Sea, we're doing 2 things. One is we're going in and replacing ESPs or pulling ESPs on the Forties. But we also got, as Rod pointed out, we just had the Bacchus well come on. And also our Beryl well hopefully will come on, Rod, in the middle of this month?

Yes, yes.

And we're expecting great things out of it. So. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. It sounds like you got a lot -- most of that coming back on track this quarter. My follow-up is, obviously you talked quite a bit at the Analyst Meeting about the Permian and the Cline Shale, and the horizontal Wolfcamp, that results looked pretty positive. As you think about next year, I know it's early but I was just wondering how you're thinking about activity in each of those plays and broadly into the Permian into 2013?

Well, we're running 36 rigs in the Permian Basin right now, and honestly, you're going to see -- I mean, it's not a lack of inventory. So you're going to see that ramp up, and I think right now, I think Alfonso's plan had it at 40 rigs next year. That's probably conservative. In terms of the Anadarko Basin, we're running 26 rigs right now. And frankly, that's higher than we had in our outlook for the Investor Day. So we're -- I think in the Investor Day, we showed that the Permian would grow on an annualized rate over a 5-year period of about 13% and the Central region, if you don't include the Cordillera, our 5-year growth would be about 23%. And we're very comfortable with those 2 numbers.

Your next question will come from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: Just a follow-up on the last question again on the downtime. I didn't quite hear the 6,000 that's offline on the Forties. Just a ballpark idea of when that returns.

That Forties production is we have 9 ESPs that are principally off the Beryl -- I'm sorry, off the Forties Bravo platform. Those are being restored in sequence that we've fired up the platform drilling rig here on the late part of the second quarter. So we're swapping in the ESP replacements with new well -- new drilled wells. Whichever has the highest rate of return to us gets the favored treatment. So we're probably seeing those ESPs return in production through the rest of this year and perhaps even in the first quarter, intermixed with normal drilling activity on the same platform. I should note that the ESP run life out there is typically about 680 days, and that gives you an idea that about 2 years ago, most of those ESPs replaced in the last cycle, and so they all start falling about the same time. John Freeman - Raymond James & Associates, Inc., Research Division: That helps. Of the incremental rigs that you added in the Permian going from 31 to 36, the 5 that were added, are they being focused mainly horizontal or can you give me maybe the current mix?

One of them is in Wolfcamp, and then 2 of them are in Deadwood, and I don't know where the other 2 are off the top of my head.

Just a second. I'll look it up for you. John Freeman - Raymond James & Associates, Inc., Research Division: And while you're all looking for that, just the last question I had while you're looking at that. The well in Kenya that I believe was supposed to be spudded at the end of July, has that well been spud?

No. In fact, I think it's going to be spud on August 15.

Your next question will come from...

We currently have 6 horizontal wells operating in the Permian, they're scattered at the moment among the leased properties. So we have 2 rigs operating in the Wolfcamp Shale, which is a new area of expansion for us south of Deadwood, and we see that to be a continuing area of increasing drilling focus in the coming year.

Your next question will come from the line of Doug Leggate with Bank of America.

I'm going to try a couple as well, if I may. I guess on the first question that was asked about production. I wonder if I can just push you a little bit on that because clearly if you get the target, to stay within target this year, it looks at least on our numbers that you'd get on to a fairly big step-up in the second half. Can you give us an idea of what the portfolio is doing currently? And would you be prepared to give us a trajectory through the back end of this year because obviously, we're -- I guess marking this issue [ph] with a bit of line of sight here.

Yes, with respect to direction, we've got half a year and you've got 2 quarters of production. I think it's pretty easy to calculate what it's going to take to get to 6% to 9%. In terms of -- I'm sorry, I didn't catch your other question.

I'm just trying -- where is the portfolio right now, Steve?

Well, we don't -- I've got to tell you it's higher. I will tell you, we don't give month-to-month production. I will tell you it is higher than what our average was, and we went -- each month went up. So July is higher than our average for the first -- the 3 months of the second quarter.

All right. I won't push that one too much. So just one other one from me then. Egypt, it was -- production obviously was kind of flattish despite the decline in the oil price while realizations were -- seemed to have dropped off relative to your kind of historical capture, relative to Brent. Anything unusual going on there, and what should we expect going forward? I'll leave it at that.

Douglas, that price -- adjustment of the price that you see in Egypt, which is lower than what you typically release -- the timings of the liftings, and it's more pronounced this quarter because of the volatility in the prices. We had a bigger drop in prices this quarter. But the key thing to note is there is no change in the underlying pricing of our oil in Egypt.

And the volumes, Tom?

The volumes...

We're -- on a gross basis, we had 13 days of production downtime at the Salam gas plant. That's 200 million a day downtime for 13 days, and the associated condensate production without that gas. That was probably the biggest impact for our overall volumes in the quarter.

Okay, and I guess generally operationally, you're still pretty happy with how things are progressing there?

No different. Everything is proceeding per normal operational program.

Your next question will come from the line of Michael Hall with Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I guess first on my end, just curious if you might elaborate a little bit on the comment you made regarding the potential interest in accelerating given the improving cost environment. Are there any particular areas that are more compelling? Just looking for maybe a little additional color there.

Well, I'd say, obviously, and I don't think we're the only company in the industry that is experiencing it. We're seeing some significant reductions in frac cost, and we're also starting to see some softening in rig costs. Year-over-year, frac costs are down 25%. So we're beginning to see some impact of rigs coming out of other -- especially the gas areas and going to the more oily areas. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, appreciate that. And then I guess, as a follow-up on the downtime expected in Australia, can you quantify how long that's expected to be down?

That will be at the end of September, but that's the ammonia plant going down or the fertilizer plant going down.

It's about 3 weeks.

3 weeks.

Your next question will come from the line of Bob Brackett with Sanford Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I had a question that follows on your pretty active lease round in the deepwater Gulf of Mexico. What's your overall exploration strategy there, given you've such a deep inventory are you going to swing for the fence a little on the deepwater?

Well, certainly, all of those blocks are exploration plays, and the good thing about the deepwater is you get the blocks for 10 years. So we're going to -- we're going to -- we plan on drilling 4 to 5 wells a year, and obviously, they're going to be the best projects that we can find. We do have a backlog of prospects, and we're -- the ones that are the best will come to that. But they're not small. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: But when you say best, is it -- are you going to keep high working interest? Are you going to go for highest risk volumes? Or are you going for things that are more likely to work?

Well, honestly, it's going to be -- we're not going to have 100% of any well we drill in the Gulf of Mexico deepwater. That's a number one premise. Number two, we're going to balance the risk against the size. So some of them will be lower risk, but they're also going to be lower-sized. But in terms of -- we're going to run that program like we do the rest of the company, and that's going to be on a portfolio basis.

Your next question will come from the line of Pearce Hammond with Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: The FPSO, the Ningaloo Vision, seems like operations are running very smoothly. Is that vessel still supposed to have shipyard time next year, or is that maybe delayed?

No, that's correct. It's still on schedule for shipyard time to do some modifications, and you're correct in your assessment about the uptime. In the transition period, we began actually operating the vessel with the contractors' ownership back in February, and subsequent to our involvement with the day-to-day operation, we experienced 95% uptime for the last 6 months. We're very pleased with the vessel's performance. Yet we still have to do the same kind of modifications that we intended to bring the Coniston and Van Gogh projects together in 2013. Pearce W. Hammond - Simmons & Company International, Research Division: And then if you could compare your rates of return on the Gulf of Mexico shelf versus the Central region, it would seem like in the current NGL price environment and gas price environment that the shelf should be a better competitor for activity and for capital than it actually is.

Well, it really has to do with balanced portfolio and risk and reward. Certainly, anything that has liquids with it in the Gulf of Mexico given the rate has a leg up on anything that you drill horizontal, frankly, just because of the profile. But in terms of risk versus reward, the predictability in shales is probably 99.9%. The question is what's the rate? So we try to balance both of those. And if you look at both of those programs, honestly, the Gulf of Mexico was always the highest rate of return projects we can do. I mean, we just got to find good ones to do.

Your next question will come from the line of John Malone with Global Hunter Securities.

Just a question on the Mississippian Lime, can you just give us some sense of how things are progressing there and what are the near-term steps?

Well, we're going to drag in -- a rig in there, here next week, and we're going to drill our first Mississippian Lime horizontal well. And we've honestly -- if you're watching that play, there are some people that have had very good success up there, and we -- honestly I don't expect anything different than that. We have a good position, and it's a question of how long it will it take us to ramp it up.

So no notion on how many you'll drill this year?

We're going to -- I'm sorry. We're going to drill 4 to 6 wells this year. Both there and also in the Bakken.

Okay. And then second question in Argentina. Any comments you can make on this new legislation they're talking about, the submitting of budgets to the government for approval?

We haven't -- other than what we've read in the press, we've interpret the preliminary decree information. We've not had meetings with the government yet. We're currently scheduled to have our first round of meetings with the government per that new decree by the end of September in which case we'll introduce our financial and investment plans for 2013. Now we've, in the past, we have annually produced an investment plan of similar format to the provincial governments. That's been standard procedure. This will be the first time having to do that as a requirement of the federal government. So yes, we don't know exactly what form it's going to take. We don't have the details from them yet on specifically what they want to have us prepare or disclose at the meeting. But that's coming up end of September, and they will have an answer for us within 60 days with regard to the nature of our investment plan and any comments they might have. That's our understanding of where it stands presently.

Historically, we have -- and one of our philosophies down there is to spend our cash flow, and I think in terms of Argentina, that is what they're looking for because they have a number of companies down there, one of which has been in the news forever, and that is they didn't spend anywhere near their cash flow. And I think honestly that's what they're looking for -- who's not spending their Argentine cash flow in Argentina.

Okay. Just one quick follow-up on -- just on Egypt on the realizations asked previously. So can we see that those realizations climb back towards parity with Brent, just subject to liftings times?

Yes.

Yes.

Your next question will come from the line of Leo Mariani with RBC.

Looking for an update on the Kitimat LNG process.

Yes, Janine's here, Janine McArdle who's our Gas Monetization Vice President.

Yes, things are progressing on the Kitimat project. We are still working with our contractor to finalize speed. We're doing a few things to optimize both the design cost and schedule. We're continuing to work with the government on both provincial and federal on some final permitting that we would like to have before we make any decisions. And we're working with, again, multiple buyers in terms of a very long term, 20 to 25-year contracts, and that's going quite well.

Okay, I guess you guys still expect to wrap something up by the end of the year?

So we'll be when we have all those things I just listed completed.

Got you. Okay. Just going over to Australia quickly. What's sort of the plans there on the exploration front for the rest of the year and next year? Because I haven't heard too much about that from you guys lately.

We expect to maintain a 2-rig program pretty much throughout the next 18 to 24 months, drilling combination of exploratory wells, some development or exploitation wells, as well as the key development wells at Julimar-Brunello for the support of the Wheatstone LNG project, as well as the development drilling at our Coniston oil project that is tied to Van Gogh that goes with the Ningaloo Vision FPSO, that we just mentioned in a earlier question.

Got you, and it sounds like your rigs in North America, you've got like 62 of them. You're not drilling any gas. What gas price do you need to see before you start drilling some of the gas targets a little more?

Higher than today.

Your next question will come from the line of Brian Singer with Goldman Sachs.

A question on the Tonkawa. You mentioned I think it's about a 10-well, it's at about 310 Mboe or 310 boe IP. I think at your Analyst Meeting, you had a number of wells you talked about and a type curve that was higher than that. And maybe it's apples and oranges, but I just wonder if you could put into context the rates that you're seeing now you talked about in the Tonkawa relative to your expectations.

Well, I think it was over 400 barrels a day, as I recall Rod's comments. The other one is that's a 30-day average and that's actually that makes tremendous economics, and you've got a lot of mix of wells in there.

At the Analyst Day, the type curve we showed for Tonkawa, we're expecting a typical well come on for about 300 [ph] barrels of oil per day. We've exceeded that typically by 10%. We're very pleased with the results of our 30-day average IP basis, and we have a significant inventory of Tonkawa location to be drilled right in the heart of play.

Great, and then when you think about the CapEx required for some of the unconventional NGL transport options such as the rail one that you mentioned. Is that factored into your budget or is that kind of incremental spending to get the better realizations?

That's part of our budget, and it is also part of the full cycle development economics for hitting the fields, which are involved.

Your next question will come from the line of David Tameron with Wells Fargo.

Any update on Liard Basin? I know you talked about it at the Analyst Day, but is that well still holding up? And I think that was a well from last year. But is that well still holding up, and if so, what's the go-forward plan up there?

Actually, that well is still holding up. We're drilling it -- we're drilling an additional well as we speak. And we're going to drill enough wells, 10-year [ph] wells, in order to hold all our acreage, the vast majority of our acreage.

Okay, so we should just expect one rig running up there over the next year or so. Is that 6 to 12 months? Is that the right we think about it?

Yes.

Okay, moving down to some of the recent acquisitions. I don't -- as far as impairment charges go, is there -- was there any impact from NGLs in the Mid-Continent, like Cordillera acquisition or any other write-downs related to NGLs in the Mid-Continent?

No. I'm not sure what you're alluding to but that's...

Obviously, gas prices impacted impairment charges. I'm just trying to figure out what the impact of NGLs was as far as...

The impairment charge was all Canada.

All Canada, right.

Okay. So nothing -- okay. So you have a cushion left in the U.S.?

Yes.

Obviously some cushion, but how much cushion?

Well, we have 30% of our production in the Central region is oil, and majority of that is black oil. So we're in pretty good shape there. I mean, you can never say never, but it depends on what happens to oil price there.

Yes. All right. And then the final question. I know you said gas prices have to be higher. Let me ask the question in a different way. Whatever number you have in the back of your head for gas prices, how long would they have to get to that level and stay there? Are you looking at a 12-month strip, like 24-month strip before you make the decision? I'm just trying to get the thought process as to when people start looking back toward gases. Do they have to stick there for 3 months or 6 months? Can you just talk a little bit about how you think about that?

Well, number one, I think gas in this country -- most gas wells are going to be challenged and the reason is if you see prices increase, there are so many locations that people can drill gas wells. But what you're going to see is an influx of rigs and people drilling gas wells, and you're going to have -- you're going to run into the same problem. There are some things we could do right now to earn gas price, but we've got a limited amount of capital. And as Tom Chambers pointed out, price differential's about 30 to 1, and it doesn't take rocket scientist to figure out you'll drill an oil well if you got the opportunity. So that as much as what the actual gas price ought to be is really driving what everybody's doing. I mean it's your economics.

Your next question comes from the line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Actually going back to the Mississippian and the Williston plays. I heard --I got your point that you've got one rig running in each of those and you think you'll have 4 to 6 wells this year. Is there a time line you have in mind on when you will share your results in those plays? Is there like a certain number of wells you think you have to get down before you can come to a conclusion you want to share?

Well, I think we've got to be satisfied with what the conclusion we reach on both of those. I would expect us to make some results known by the end of the year. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And what would a rig ramp -- a rig count ramp look like in those plays in the success case?

Well, that is going to have to compete what we've got in the Central region and the Permian region. Certainly with our acreage position, we own a significant interest, 100%, most of the Bakken's stuff, and large interest in the stuff we have with the Mississippian Lime. So it gives us real opportunity to ramp that up if it works. And certainly, the Mississippian Lime is going to work. It's going to have to compete with capital in terms of rates of return with some of the other things we're doing. But Mississippian Lime is -- we're going to drill good wells. It's going to be whether or not -- what the economics are. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And one other kind of obvious question. Is there anything to add on the political situation in Egypt? I mean, it seems that it has been relatively news-free, at least by those standards, and so that seems welcome. But I wonder if you could add your impressions there?

No, as Rod pointed out, we haven't -- we have continued to deal with the petroleum ministry, the Minister of Petroleum and since have continued to deal with the Chairman of the EGPC. I think Rod mentioned we have 7 new gas contracts that we've just signed. If anything, frankly, what we're seeing is, is that their need for hydrocarbons is such that it may have gotten a little bit better than has been the status quo just because of the urgency nature of bringing production on.

There have been some significant political developments, for them, they announced a new Prime Minister. And he has subsequently appointed new cabinet as of yesterday, and I believe they took their oaths of office today. So we do have a new Petroleum Minister as of today, Osama Kamal, on the petroleum chemical -- petrochemical sector. So there may be some other changes associated with those ministerial changes.

I will now turn the conference back over to Patrick closing remarks.

Thank you, Regina. Thank you for participating in our second quarter conference call. The webcast replay will be archived on Apache's website. The conference call also will be available for delayed playback by telephone for 1 week beginning at approximately 4:00 p.m. Central Standard Time today. That ends our call this afternoon.

Ladies and gentlemen, this does conclude today's conference call. Thank you all for your participation, and you may now disconnect.