Roger Plank - President, Chief Corporate Officer and Member of Risk Management Committee G. Farris - Chairman of the Board, Chief Executive Officer and Member of Executive Committee Alfonso Leon - Vice President of Planning Strategy and Investor Relations Thomas Chambers - Chief Financial Officer, Executive Vice President and Member of Risk Management Committee

Daniel Morrison - Global Hunter Securities, LLC Brian Singer - Goldman Sachs Group Inc. Leo Mariani - RBC Capital Markets, LLC David Tameron - Wells Fargo Securities, LLC John Herrlin - Societe Generale Cross Asset Research Pearce Hammond - Simmons & Company International Douglas Leggate - BofA Merrill Lynch John Freeman - Raymond James & Associates, Inc.

Good day, everyone, and welcome to the Apache Corporation Second Quarter 2011 Earnings Conference Call. This call is being recorded. Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

We got the old script. This is Alfonso Leon. I'm Vice President of Planning, Strategy and Investor Relations. So good afternoon, everyone, and thanks for joining us for Apache Corporation's Second Quarter 2011 Earnings Conference Call. This morning, we reported second quarter 2011 net income of $1.2 billion or $3.17 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results, totaled $1.3 billion or $3.22 per diluted share. Cash flows from operation totaled $2.6 billion. On today's call, we will have 3 speakers making prepared remarks prior to taking questions. Steve Farris, our Chairman and Chief Executive Officer; Roger Plank, President and Chief Corporate Officer; and Tom Chambers, Executive Vice President and Chief Financial Officer. Rod Eichler, President and Chief Operating Officer is actually on jury duty today. We have prepared our usual detailed supplemental data package for your use, which includes the reconciliation of any non-GAAP numbers that we used, such as adjusted earnings, cash flow from operations or costs incurred. The 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 will turn the call over to Steve. G. Farris: Thank you, Alfonso. Despite what we're seeing in the broad market today, Apache, very positive and proud of the quarter we turned in. I know you probably know that we had record production of 749,000 barrels of oil equivalent a day, which was up 2% sequentially. We posted our second highest quarter of adjusted earnings ever of $1.3 billion, record cash flow of $2.6 billion, and actually, the only quarter of earnings we've ever had better than this was in the second quarter of 2008 when the commodity prices were -- moved to $140 range. Clearly, our results in the second quarter were strong and really were driven by our portfolio's strength and the asset rate of return focus of all Apaches. We had notable discoveries in a number of our regions during the quarter, and in addition, we took important steps forward in future growth projects which included Balnaves, our Lucius in the Deepwater, Deadwood, Wheatstone LNG and Kitimat LNG. The quarter underlines the strength of our cash flow generation. Our $2.6 billion of cash flow was up 44% from the same period a year ago. So if you analyze that, that's probably less than this today with our share of price going down today. If you analyze it, would imply share trade price at about 4x our cash flow. Cash flow is our fire power. Our balance sheet has grown to -- or cash balance has grown to $1.1 billion at the end of June, which puts us in a good position to take on new projects or asset investment opportunities if and when they arise. We're very careful with our cash and staying focused on rates of return has served us well over the years, and that's not going to change in the current environment. Rod Eichler is on jury duty, so I'm going to give you a little highlights from the operating side. In the Permian region, production increased 9% sequentially, which was driven by the absence of weather disruption we experienced in the first quarter, a very aggressive drilling program at Wolfcamp at Deadwood, our horizontal drilling results in our legacy water flood units and prior period adjustments. We operated 24 rigs during the quarter and drilled 146 wells, 13 of which were horizontal. We completed 137 wells and as we continue to ramp our frac spread capacity to catch up with our drilling activity. Our horizontal redevelopment of the Permian legacy water flood units continues to yield very positive results. The TXL South unit, one of the 6 out of 28 water flood fields in which we have initiated horizontal redevelopment hit 3,500 barrels a day, which is a 23-year record, and this field has been under water flood for 43 years. So far this year, we drilled 7 horizontal wells in the unit. A big driver in the second quarter was the TXL South unit, 5210, which is a horizontal well testing at 531 barrels a day and 450,000 cubic feet of gas a day. These wells are increasing the recovery from the field by contacting unswept reserves that would ever otherwise be left behind, and the results we've seen in this field and a number of other fields gives us tremendous potential in all of our water floods in the Permian. We ran 11 rigs and drilled 57 wells in the Deadwood field. We're concentrating our activity this year in the Wolfcamp due to land retention requirements. Gross oil production in Deadwood exceeded 5,000 barrels a day and 14 Mcf of gas a day at the end of June, which compares with 2,000 barrels a day and 6 Mcf a day at the beginning of the year. Our gas volumes have potentially plateaued in this area due to the midstream constraints, which the recently announced across Texas JV, the joint venture will address in early 2012. We expect to drill 160 wells in Deadwood this year, and at this point, we have an inventory of an additional 575 vertical locations there. During the second quarter, we completed our first climb horizontal in the Deadwood area. It tested at 77 barrels a day, which was less than our expectations. We intend to change our frac design on our second well, which is currently drilling. We continue to address and build our inventory in the Yeso, the Empire Abo, Southeast New Mexico, Rio too plus Bravo [ph] and we have a couple of new venture plays that we're working on. Apache has built a strong portfolio in the Permian, really, throughout a consistent contrarian approach over many years. And today, we have decades of attractive opportunities ahead of us. We've already identified 7,500 drilling locations, and if we stop today, we'd be able to drill wells for several years in the future. And in Central region, production increased 7% sequentially, which were driven primarily by increase in our oil production, and notably, oil production in the region has increased 60% year-to-date alone. The region ran 10 rigs during the quarter and drilled 21 wells, almost entirely horizontal. The focus of our activity were in the Granite Wash with 10 wells, 3 oil plays in the Cherokee and Cleveland and Hogshooter with 5, 4 and 2 wells respectively. Average well results across these plays continue to meet or outperform our expectations, and we expect they at least maintain our current level of activity across these plays on multiyear basis. Some individual highlights per play during the quarter included the Cherokee well that stabilized at 577 barrels of oil a day and 900,000 cubic feet of gas a day, a Cleveland well that tested 717 barrels of oil per day and a Hogshooter well that flowed at about 1,150 barrels a day and 4.5 Mcf of gas a day. Production in the Gulf of Mexico shelf region was down 2% sequentially due to the level of activity constrained by permitting issues and natural field decline. We operated 5 rigs in the region during the quarter. Reached TD on 6 wells with 100% commercial success, and we remain on track to drill up 41 wells this year and really look forward to resuming our normal pace of 60 wells next year as we begin to exploit the upside associated with our 40% acreage expansion and underexploited [Audio Gap] all Apache Gulf of Mexico [Audio Gap] If you look at that on [Audio Gap] Throughout the region, production declined about 3.5% sequentially. [Audio Gap] quarter a successful well test was conducted in the Lucius field, which is operated by Anadarko. In addition, the utilization of Lucius with adjacent acreage belonging to Exxon Hadrian partnership was finalized. These steps positioned Lucius for an investment decision this year with first production in 2014. The capacity of the facility is expected to be 80,000 barrels of oil a day and about 450 Mcf of gas a day. Apache holds 11.67% interest in the enlarged Lucius complex. We continue to progress Heidelberg and a number of other projects. Importantly, we have now received approval on 2 out of 4 exploration plans we have submitted year-to-date. We have 110 exploration blocks in the deepwater Gulf of Mexico. We're eager to get after an active exploration program to expand our position, hopefully, somewhat slimmer that we've done in the shallow waters. We're the dominant player there now. In the Gulf coast onshore, production was up 10% sequentially on the back of an active drilling program and recompletion program. We operated 4 rigs during the quarter and drilled 21 wells. We continue to build opportunities in this area, tremendous site of carbon-rich region, provides an excellent fit with Apache's exploitation capabilities and contrarian philosophy. In Canada, production was down 1% sequentially, mainly due to weather, wildfire and pipeline disruptions, in addition, the normal reduction of our activity after spring break out. We operated 3 rigs in Canada during the quarter and participated in 12 wells that reached TD. In the third quarter, we are currently projecting an approximately 1,800 barrels of oil per day and unscheduled production disruptions due to pipeline downtime and ongoing flooding in some areas. Change gears a little bit, the Kitimat LNG project, which Apache operates with a 40% interest has taken important steps forward. We're near the conclusion of the hearings for the 20-year export license, and we recently announced the acquisition of an industrial site near the project's current LNG site, plant site. And this additional site has a large amount of land, which hosted a paper mill and marine export facility in the past. Due to the timing of feed work, we are now targeting a final investment decision in the first quarter of 2012. We remain committed to a target date for first production in late 2015. Kitimat LNG is a landmark step not just for Apache but for the industry, and we are very excited about leading the charge on this project that if sanctioned, will generate large predictable cash flows for our shareholders for decades to come. Moving to Egypt. Despite what you read in the papers, Apache has no interest in entering the Israeli gas markets. I don't have any idea where that came from. Some of our joint venture folks did meet with the Israeli minister of petroleum but that was really -- had nothing to do with investing in that country, and not that we wouldn't invest there, we're very happy in Egypt. We intend to stay there for many years. We operated 24 rigs in Egypt during the quarter, drilled 53 wells with a 91% success rate. I might say that Egypt production was -- on a gross basis was actually up slightly, but was down 7% in net terms due to timing of our cost recovery and higher oil prices. Our exploration program delivered broad-based success across the region during the quarter. 18 exploration and appraisal wells yielded 13 new discoveries. Five of our discoveries were in the Faghur basin, and we made 2 discoveries in each of them through Abu Gharadig and Shusham [ph] and Beni Suef basins. These discoveries have also furthered some of our new plays as 2 of them encountered the Paleozoic, one which was delivered stratigraphic target in the Matruh basin. We're still testing some of them. Each discovery potentially opens up a population of future locations for our inventory. We should be at 26 rigs in Egypt over the coming weeks as we ramp up our activity in oil and unconventional plays in the country. In Australia, production was up 8% sequentially, reflecting improved FPSO performance in Van Gogh, stronger-than-forecasted performance at Pyrenees and the contribution of new wells onstream in our Stag field. We operated 2 rigs in the region during the quarter and drilled 3 wells, yielding 2 significant new discoveries at Zola and Valmy steep. Our Halyard development commenced production in June and averaged about 45 Mcf of gas a day and 819 barrels of condensate for the month. The Halyard explorer will continue to ramp up through 2013 with a peak production of 110 Mcf of gas a day and about 2,000 barrels of condensate as processing capacity becomes available at Varanus Island. Apache has a 55% working interest in this project. Van Gogh production averaged 8,700 barrels of oil per day net to Apache in the second quarter, which is up from 3,800 barrels a day in the first quarter. Production was halted on June 10 for a central maintenance program and resumed on August 2. Frankly, the downtime and unreliability of this third-party vessel remains a serious concern and we are currently working on a potentially longer-term shipyard remediation program for 2012. We continue to progress our project pipeline in Australia. During the second quarter, we sanctioned Valmy's oil development project, which is expected to deliver initial production of about 30,000 barrels a day in 2014 and Apache has 65% working interest in this project. In addition, last week, we announced Wheatstone LNG execution of a major debt sales agreement with TEPCO. This is an important milestone for our efforts to reach final investment decision this year. Wheatstone LNG, which is operated by Chevron, will produce 8.9 million tons per annum starting in 2016, and Apache has a 13% interest in their overall project. Turning to the North Sea, production was up 22% sequentially, driven by truly outstanding drilling results, reduced pipeline downtime and the consolidation of our interest with Nelson. We operated 2 rigs in the Forties field during the quarter and drilled 6 wells and 2 wells to highlight our first to Charlie 4 or 3, which started production at 12,567 barrels a day, which is the best initial production of any well in the field since 1990. And the second to Delta 3 and 5 commenced production at a rate of 8,781 barrels of oil per day, which wasn't too shabby either. These wells result really stand from a combination of improved 4D seismic imaging. Our refined drilling practices, we've been there a number of years now and better performance on our well completions. Forties is the largest oil accumulation in the U.K. North Sea with 5 billion barrels of oil in place. We've produced about 2.5 billion of those barrels. We expect many years of continued profitable investment opportunities in the field. We're installing the new Bravo-Charlie production pipeline, which went commissioned in September. We'll restore the remaining 4,000 barrels of oil a day of production shut in due to the pipeline issues. We are currently experiencing a field-wide 5-day production shutdown, which we expect to end tomorrow as the operator of the Forties pipeline system removes World War II ordinances found in the area. One last note on the North Sea is that one of our rigs is now on location at the Bacchus development project, which we expect to come on stream in the fourth quarter this year. Turning to Argentina, production was up 10% sequentially driven by an increase in premium priced Gas Plus contracts. We operated 6 rigs in Argentina during the quarter, reached TD on 7 wells, 5 Gas Plus and 2 vertical oil producers. Other wells that have not reached TD yet include 4 important exploration wells and a significant horizontal oil test that could open up a number of opportunities for us. Our natural gas realizations in Argentina increased from $2.18 in Mcf in the first quarter to $2.74 in Mcf in the second quarter. It was driven by second quarter Gas Plus volumes of 77 million a day with an average price of about $4.93 per Mcf. Gas Plus production is subject to a 12% royalty. One of our Gas Plus development highlights was the first horizontal multifrac drilled in Pre-Cuyo tight sands, which is flowing over 10 million a day after more than 2 months of production. We're going to follow up this concept with additional wells later on in the year. We have completed frac-ing the first horizontal multifrac well, targeting a shale formation in Argentina. We're currently opening up some of the fracs and recovering frac fluid. On a final note, in Argentina, during the quarter we gained entry into a fourth basin in the country, the Noroeste basin through a 50% interest and 516,000 acre block with both conventional and unconventional exploration opportunities. Our partner is Gran Tierra, and we expect the first well to be drilled there in 2012. And with that, I'll turn it over to Tom Chambers our Chief Financial Officer.

Thanks, Steve. Good afternoon, everybody. Apache turned in another very solid financial performance in the quarter, reporting earnings of $1.24 billion or $3.17 per share for the second quarter, up $125 million from the prior quarter. Adjusted for certain items that impact the comparability of results such as foreign currency fluctuation and deferred taxes and merger acquisition and transition costs, we earned $3.20 a share, up 11% from the prior quarter. Higher daily production, combined with significantly higher oil prices, increased cash from operations 18% over the first quarter of '11 to $2.6 billion, our best quarter ever. As Steve indicated in his remarks, our portfolio continues to deliver excellent results. Our oil and liquids volumes currently make up 49% of our total production but account for more than 3/4 of our total revenue of $4.3 billion. This was driven by the fact that the majority of our international oil production is in indexed to Brent crude price and over half of our U.S. oil production receives significant premiums to WTI prices. Our average price realizations increased 7% over the first quarter, and despite pressure on costs, our cash and pretax margins also increased by 7%. Cash margins rose to just under $47 of boe and pretax margin, which includes DD&A rose to $31.29 per barrel of oil equivalent. You can find the details of these in the financial supplement located on our website. We remain focused on operating cost, which manifests itself in our bottom line margins. In that regard, our total cash costs for the balance of the year should remain in the range of $16.50 per boe at current strip prices. At the end of the quarter, our debt-to-capitalization ratio was under 23%, down slightly from 24% at the end of last quarter. Higher prices and production plus the sale of a small Canadian property package drove free cash flow generation, enabling us to reduce debt by $380 million to $7.85 billion and increased cash on the balance sheet by $750 million to $1.1 billion. As we indicated last quarter, most of the free cash on our balance sheet is currently located outside of the United States. Turning to taxes. Our second quarter effective tax rate was 41%, on par with our first quarter, and our deferred tax percentage was 34% in line with where we expect to see our deferred rate for the year. The previously announced U.K. supplemental tax increase became law when it received royal signage July 19. The 12 percentage point increase, which takes our effective rate to 62% was retroactive to March 24 of this year and will result in a nonrecurring charge of approximately $230 million plus the catch-up charge of approximately $60 million for the year-to-date through June, both of which will be reflected in our third quarter earnings. Absent the impact of foreign exchange movements and the corresponding impact of our deferred tax balance, our worldwide effective tax rate should average around 45% for the full year, primarily driven by the U.K. tax rate increase. To sum up, we had a very solid quarter and look to continue to build on this momentum. Our focus remains on margins and returns as well as cost and production growth, which allows us to achieve our balance sheet goals. And with that, I'll turn it over to Roger.

Okay. Thanks, Tom. Good afternoon, everyone. I'm going to comment very briefly on our progress year-to-date as it's truly been at an exceptional first half. After a very active 2010 in terms of capturing opportunities to strengthen our portfolio and expand our long-term growth horizons, the digestion and integration process could not be going much better. Our first half production was up 20% from the year ago, and as you've heard, it's driving exceptional financial returns. South first half cash flow this year of nearly $5 billion is higher than we planned, enabling us to meet our debt-reduction objectives, increased our planned capital expenditures by some $600 million to $8.1 billion and build our cash balances rapidly now. Growing our production and having instant cash flow with which to pursue opportunities for continued profitable growth really gives us a true competitive edge. Our portfolio approach and earlier contrarian decisions are also paying off. Tom commented on how our ample weighting of oil production is driving our financial results. I just like to note that while our North American prices in the first half on the oil side rose $20 to $94 a barrel, our international realizations claimed $32 to $107 a barrel and on just over 200,000 barrels of oil per day that internationally, that generates meaningful additional cash flow. In international gas, along the line for not being exposed to North American natural gas markets, is also beginning to see its day in the sun. While North American realizations declined in the first half from a year ago, our international gas prices climbed 25% to just over $3.60 per Mcf. This direction is likely to continue and make an even greater impact in Apache's future as our international gas volumes rise along with international gas prices. So rising production, strong cash flow and a deep inventory of drilling opportunities, all of that puts Apache in a very strong competitive position from which it delivered continued profitable growth. Steve, you want to wrap things up? G. Farris: Thank you, Roger. I'd like to conclude our prepared remarks by thanking all of you who attended our Investor Day in New York. Actually, we had more than doubled the number of people as we anticipated. Obviously, we appreciate your time and your level of engagement. We're very conscious. This is not easy to model the full value of Apache in a diversified growth enterprises. We are -- we have 10 regions, global regions and a broad portfolio of projects and plays. We're making every effort to bridge that challenge. At the Investor Day, we had our current inventory of projects over the next 5 years and the full economics of all of them. We have more opportunities today than any time in our 6 decades as a company, and honestly, at the end of the day, it's actually putting money in the bank and making good investments and not as how good you tell a story. We may be headed over the next 2 or 3 years and some of our best years we put back-to-back in several years. And if you want to look at our future, the best way to do that is learn our past. Because if you look at our last 5 years for growth or 5 years before that, we've had significant profitable growth over a long period of time. We continue to be a driven company, and we truly are just getting started. And with that, I think we'll turn it back over to Alfonso.

Operator, we're ready to take questions.

[Operator Instructions] Your first question comes from the line of Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs Group Inc.: I have a couple of questions on the strong rates that you saw out of the Faghur basin in Egypt and the 2 wells in the Forties field. I think that represents about 12,000 barrels a day in Egypt and about 20,000 plus in the North Sea. The questions are first, how many additional similarly looking opportunities do you believe have been derisked by these wells? And second, should we expect to see a jump in production in these 2 areas or has that already been reflected with the quarterly results? G. Farris: Well, it certainly -- let's start with Egypt because it's -- honestly, we just not scratched surface in the Faghur Basin because each one of those wells are either the exploration well on a separate fault block or if it's not that first well, it's a second appraisal well. And we have a number of projects to do there. Our biggest constraint for a little while is going to be -- if you recall about a year ago or year and half ago, we put in some oil facilities to add the oil that we got at Phiops and also gas facilities because we were starting to get more gas in this area. The fact of the matter is we are going to be pretty full, it's starting in about September again for a while until we expand those facilities. In terms of our sequential growth in Egypt, you got to be careful watching the quarter out. I wish we could post both our gross operated, as well as our nets because just depending on what happens, the close of the quarter, our cost recovery. [Audio Gap] but we expect to continue to grow our oil production in Egypt. [Audio Gap] Brian, so we have tremendous opportunities there. And the North Sea, it really has been startling. We did finally process here I think about 8 months ago the 4D that we have shot and got final processing on our latest 4D, and obviously, the evolution of that technology gets better and better and we get better at it. But there's -- I think we probably have 50 prospects, but I couldn't have said that. It's a little bit like the Granite Wash horizontal well. We have had 50 projects for the last 3 or 4 years. So I would expect right now, we are constrained there a little bit with respect to facilities. We are putting in a satellite platform. I think the guys went over, the gals went over it when we were at the Investor Day. We're putting in -- I think it's going to have 18 slots that we can also, not only drill water injector wells but we can also have facilities to increase our oil production, and both of those have potential of increasing from where they are today. Yes, and that's both of those plays. Thank you though. Brian Singer - Goldman Sachs Group Inc.: And this as a follow-up to that and I apologize if you did already mention this. Did you say where growth levels were in Egypt? I didn't notice that it did tick your line. G. Farris: Well, the slide we have but I don't have it in front of me. I think we did 217,000 barrels a day or 1,000 barrels a day and 881 Mcf gas a day, but 1 Mcf a day but I don't normally see that.

And Brian, we do have that line now in our supplemental disclosure. Brian Singer - Goldman Sachs Group Inc.: And then lastly on Egypt and on Argentina, can you just talk about demand trends that you're seeing, I guess, particularly for Egypt where I know you haven't been disrupted at all, but I wonder if you've seen any changes in the pace of demand growth and then in Argentina as well? G. Farris: In Argentina, I will tell you, they are -- I got to be careful now. They need gas because they are importing gas from Bolivia, and they're also supporting LNG cargoes, pretty significantly, prices above our current price that we're selling to them. We've had indications that we will be able to produce into that Gas Plus market whatever we put into it, and well, that remains to be seen but we're taking them at their word. We'll continue to drive the increase of Gas Plus volumes. In Egypt, frankly, we have seen no downturn in demand because of the activities that have gone on over there. They've grown their demand about 12% a year for the last 5 years, and frankly, they still burn about 135,000 barrels of diesel there. So the gas price, like the gas price in most parts of the world are significantly lower on a BTU equivalent in Egypt as they anywhere else in the world. So I don't see that demand for gas abating. Our biggest problem is takeaway again, and we have now run our intelligent pig and the pipeline to the South. It has some spots in it that have 80% line loss, so we have to cut that back little bit. But we now have enough data to be able to go in there and fix that, which we intend to do, and we should be able to ramp that up significantly honestly before the end of the year. So we have potential to increase our gas production in Egypt also.

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Douglas Leggate - BofA Merrill Lynch: I got a couple of quick ones. Steve, if I could just jump on to the Egyptian follow-up questions I guess given your comments there. So just to be clear, the -- how much of the 300 million a day that you currently have, I guess, behind pipe, do you think you'll be able to release once that pipeline is fully repaired to the level of integrity you're happy with? G. Farris: I would think probably 67 million a day. Douglas Leggate - BofA Merrill Lynch: And that would be by the end of this year? G. Farris: Yes, ramp it up until the end of this year. We won't have [indiscernible] I hope I'm not getting that in front of our guys in Egypt but I think that's probably right. I had that propensity. Douglas Leggate - BofA Merrill Lynch: Now this is typically fairly rich gas, so do you get some liquids coming out of this as well? G. Farris: We do and I will tell you, we've had -- the Abu Gharadig plant had a small fire, and so we're really not being able to separate down to the liquids portion. We're getting off the time cycle, but we're able to separate the liquids. And we haven't been able to do that for about the last 3 months. That should be fixed this summer, by the end of the summer. Douglas Leggate - BofA Merrill Lynch: Okay. And I apologize for this one but I guess somebody's got to ask it. Can we just get your kind of broad update as to how the political situation is, the pipe's outlook and whether or not you're current on your payments in terms of your receipts, I should say? G. Farris: Yes, we're no different but with respect to our payments, things haven't changed a bit. In terms for Apache, with respect to -- I will tell you I was there June 7, 8. We have the U.S.-Egyptian business council meeting there. We had 24 major companies, not just oil companies but U.S. companies that made that trip, Google, Microsoft, Citibank, Exxon, a number of companies that are much obviously much larger than us and talked to a number of people. Obviously, they have -- things have changed. Certainly, I will tell you the enthusiasm there is as great as I've seen it since we've been over there 15 years. People are generally very positive. Most of them are very positive about what's going on. And they all recognize that they have -- it'll just them take awhile from an economic standpoint. But I'm, obviously, I'm optimistic because we drill wells for a living. But I don't see any real concern. We're sensitive to it, but not concerned, I guess, is the way I would put the words. Douglas Leggate - BofA Merrill Lynch: Got it. And last one for me I guess, I keep going awhile. I'll let someone else jump on here. But the last one is on Nelson. Given the extent of the success that you're obviously having on Forties and I guess the fact that Shell's been kind of sitting on their hands for quite a while on Nelson, any update you can give us in terms of progress of maybe increasing that stake or getting more involved, more active in the actual redevelopment fund if there is such a thing? And I'll leave it at that to you. G. Farris: No, I think any place we're not operator, we probably would like to get more involved. Yes, I think you asked the right question. We're going to see whether or not it's beneficial to us.

Your next question comes from the line of David Tameron with Wells Fargo. David Tameron - Wells Fargo Securities, LLC: A couple of questions. Steve, can you talk about Canada? You briefly hit it, but can you talk about exploration-wise what you're most excited about? G. Farris: We were just up there. We had quarterly review up there and spent a day and half. And I tell you, we had a lot -- the thing I'm most -- it's short term because I'm excited about a lot of number of things. I think short term is when you look for either oil or liquid-rich gas, you can find it, which I was and our folks like in what we call the Kaybob area is we got some zone discussions real potential and some of the offset players are drilling and making dang good wells. But we've got a huge acreage position in there and starting to drill some wells in there. I think we have 2 or 3, but the Provost oil play, I mean that's 3,000 feet, but it's oil. And we got probably 1 million acres in there, although it's not going to be productive, but its huge acreage position. We've got -- the good thing about having acreage is you've got lots of chances to win, and we have a huge acreage position up there and whether it is the Montney, Ridgewood liquid-rich. We've got a bunch of acreage in there. We've got it in the Gano [ph] play. We've picked up an awful lot of good acreage from BP that we didn't even put value on when we did it, frankly. We didn't need that value at the time. I would say one thing is we're going to be able to find some liquids and some black oil up there, and I really didn't expect the oil. David Tameron - Wells Fargo Securities, LLC: Okay. And are things back to normal in Canada yet, post the weather and then the rains and everything kind of slowed things down. Are you back? G. Farris: Well, we're getting back. Alfonso, you might...

Yes, we expect at this point for the third quarter, 1,800 barrels per day net of continued disruption due to pipeline downtime and ongoing flooding. G. Farris: But in terms of our activity level, we're starting to put rigs back to work. David Tameron - Wells Fargo Securities, LLC: Okay. One more question. Can you do anything with the FPSO. You briefly mentioned, but I mean what's -- just give us the current state of... G. Farris: We're back on. I don't know what the production was today. I think it's a little over 20,000 barrels a day gross in the Van Gogh field. We expect to -- if we it everything or is working right, we hope to get it up at about 34,000 to 35,000. We got the 52% in that. And it's not -- let me tell you, it's a beautiful permeable zone, which is great and you get rates out of it but it will decline. So not unlike any of the deepwater stuff in the world. But it has been very hit and miss, frankly. I don't know if you follow it, but we had a swivel problem, we had it there at excess [ph]. We had an anchor problem. We had haul it off from big step [ph]. So the last 45 days or thereabouts, 40 days, the boat owner took it off the location and did a major overhaul of a number of components, and we are just now back online the last couple of days. So we will -- it's not costing us anything other than loss production. David Tameron - Wells Fargo Securities, LLC: Okay. Is there insurance for that loss production? G. Farris: No. David Tameron - Wells Fargo Securities, LLC: Okay. But it sounds like as of now, if this works you're content where you're at right now with that. G. Farris: Yes, if we can make it run, we've had about 40% up time over the last 6 months, and that for a field that's producing black oil and 110, well Brent's 120 there for awhile, I mean that's a hell of a lot of cash flow we're missing out on.

And we do think of it as loss production but in reality it will be deferred production.

Your next question comes from the line of Pearce Hammond with Simmons. Pearce Hammond - Simmons & Company International: Steve, can you provide a little bit of overall outlook on the deepwater Gulf of Mexico? And when do you think it becomes a significant growth platform for the company? G. Farris: I tell you that's a $64,000 question. I will tell you we're starting to see, and I'm talking about not our activity level. It's much of the industry's activity level because it's -- our expectations were by the end of this year, we ought to be in pretty good shape with exploration permits, et cetera. I think it's slower than everybody expected. I think it is becoming more clear as to what you need to submit and your time frames. I mean basically, we just had a quarter review in both on the shelf and the deepwater here about a week and a half ago for third and second quarter. But if you look at the permitting of whether it's a well or development well, whatever, we just pushed the clock back 3 to 6 months from the time period it used to take, which means we're going to have to do better planning, not only in the deepwater but on the shelf and get our ducks in order and try to do it a little more systematically. And we used to be able to drag a rig out there and drill well. In terms of it being a significant driver for Apache, honestly it's going to take 3 years. I think what's happened on Lucius and Exxon's well, I mean, it's gorgeous but I think I'm not supposed to say that. They announced 700-foot column, but it indicates kind of things you can find in the deepwater. And we built a staff around the Mariner folks, but we're also building -- we have a technical group. That is a strong technical group. So I would see us, over time, increasing our interest and blocks that we've gotten from Mariner and also drilling some wells as the operator. Pearce Hammond - Simmons & Company International: And just following up on divestitures. Earlier this year, you all had mentioned about a $1 billion, I believe, of divestitures, maybe half in Canada, half in the U.S. I know you got some divestitures done this quarter. If you could just catch us up on where you are in that process? G. Farris: Roger?

Yes, we got one sale done in Canada. It was just under $200 million. It's about -- first quarter, those properties produced 25.5 Mcf a day and 500 barrels per day. And we've got another comparable sale that we're working on and would hope to complete in early to mid-September. G. Farris: And honestly, what happened is, is that we got more cash than thought we were. We're not selling what we don't think we're selling cats and dogs. And so some of the things that we were marketing, we didn't get a price that we thought was the good price and so we kept them.

Along those lines, we got a package in the U.S. that we are currently marketing, and we would have the same comments about that. If we get a price that we like, we'll take it. And because we don't have pressure to sell because we've got higher cash flow and cash, we don't, we'll keep it.

Your next question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc.: In Argentina, I apologize if I missed this, but what were the sales on -- the Gas Plus sales either during the quarter the most recent data and then the average price on those sales?

I think it's 77 million a day at 493 or something, like that. Yes, that was it. G. Farris: That's the average for the year. Fourth quarter. John Freeman - Raymond James & Associates, Inc.: And in the North Sea, I know going into the quarter, you all were expecting about 6,600 net barrels a day of production down for planned turnarounds. Does any of those turnarounds carryover in the third quarter and if so, the amount? G. Farris: No. We are currently should be back up tomorrow, but we have an unplanned event where the Forties pipeline operator, and you could figure out who that is, we had to shut in all of the oil behind that pipeline for 5 days because they found some ordinances along that pipeline. And we should be back up day after tomorrow. John Freeman - Raymond James & Associates, Inc.: Okay. And then last question for me, you all have gotten a pretty sizable position now in the Cook Inlet in Alaska, and I'm just trying to get a sense of how to think about that. I know that the concept is kind of the lack of 3D seismic coverage, so you shoot it and you get the work with it, but sort of the timing on when you would shoot it, when you actually start to drill up there. G. Farris: We had not finite number, stepping in front of our guidance, again, but we have led the contract on that, and it's going to be a large shoot and it will be 3D. And hopefully, we will be done with that by the end of this year in terms of first pass processing and hope to drill a well in 2012. We got -- its exploration play but the guys have wowed me enough me to believe that it's a real opportunity.

Your next question comes from the line of Leo Mariani with RBC. Leo Mariani - RBC Capital Markets, LLC: Just only thing that your gas price in Australia has picked up a fair bit in the last couple of quarters here. Just wanted to get a sense from you guys kind of what's caused that. Maybe there were some legacy contracts to the lower price, that it rolled off and perhaps you could just sort of address your current contracts and when some of those at lower prices may roll off in the next couple of years. G. Farris: Well, I don't have in front of me specifically the numbers. I know we are putting on some gas like Halyard going in at a higher price. But our legacy contracts really will start to roll over in 2013 and 2015. And we're also in the midst of negotiating some contracts from Macedon, which were not operator, but that will come on in 2013. The operator of BHP there but the contracts are in the 7-day dollar range. So you're going to see not just for the last 2 quarters over the next 2 or 3 years. You're going to see our gas price in Australia change significantly. Leo Mariani - RBC Capital Markets, LLC: Great, okay. And I guess speaking with Australia just wanted to get a sense of what else is on the docket this year in terms of the larger exploration wells you guys plan on drilling? G. Farris: Yes, let me think. Well, we keep extending step. Probably the best thing we have is a step around at Zola. I think we're scheduled and I'm not sure it's the end of this year or first quarter of next year. We've got play an incredible well at Zola, which is going to be big gas line for us and nobody -- we can't tell -- we're going to appraise it. But the good thing about that is, if we go to FID with Wheatstone, we have the potential of putting significant more volumes of gas in Wheatstone, which is the whole purpose of that is not just Julimar. The whole purpose of that is to expand our gas markets in Australia. We drilled a dry hole at Emerson, which was off of 356. We had totally different kind of stratigraphic play off of 356 was the Julimar area or way out to the East. And I think right now that's -- I can't think of anything in front of us this year anyway. Leo Mariani - RBC Capital Markets, LLC: Got you, okay. And I guess clearly, you guys just announced a couple of nice discoveries there in Egypt just curious as to sort of how many other wells you have left to drill in the exploration site in Egypt this year as well? G. Farris: We probably got 14 more wells to drill this year on the exploration side. I think probably -- they're actually appraised. Let me put it that way. Some are probably drilling right now, but we haven't seen the results. What we found is -- frankly, 2 things we found that I would comment on. One is the Faghur Basin area is the oilier, and we see the Sapa, oil Sapa, which is really a plus for us over there because it's not the a, b, which is upper, the upper part of the zone, lower Cretaceous is great production, but it declines quickly. And what you see out of the Sapa is they've more staying power. And the other thing I would say is that we've been pleasantly surprised with what we found on the stuff we acquired from BP because when we talk about gas, being able to pull gas out of a call though, we're to the point when we get that pipeline fixed. We're not on that pulling gas out of Gharadig. We're finding it. We're finding it Abu Gharadig acreage that got from BP, which is a real plus. Leo Mariani - RBC Capital Markets, LLC: Okay. So I guess just to make sure I understood that, are you saying you that you have drilled some exploration wells on the BP acreage at this point and you found more gas? G. Farris: Yes.

Your final question comes from the line of John Herrlin with Societe Generale. John Herrlin - Societe Generale Cross Asset Research: Some quick ones for me. How encouraged are you in Egypt for the Paleozoic, Steve? G. Farris: Honestly, the jury is still out, but I've always been encouraged by it, frankly. I don't have the settle of having data. Well, there's no reason why it doesn't exist out there. What we continue to kind of step out there and do is we encourage ourselves every time we drill down through the Paleozoic, and we continue to get encouraged by that. My thought is go out there in the middle of nowhere and drill a well. We haven't had that courage yet, because I really think that you have a real shot at it. But the last 2 wells that we drilled, they definitely had pay at the Paleozoic which is good. John Herrlin - Societe Generale Cross Asset Research: Okay, good. With Argentina, you said you were going on conventional with shale test. Say, you're successful there going forward, how hard will it be to build up infrastructure because you probably had to bring in frac tarps from all over to do it right? G. Farris: Well, yes, the infrastructure from the pipeline -- the good thing about Argentina is they got all kinds of pipelines across from that Neuquén basin. The bad thing about Argentina is they got very little service equipment. In fact, we are bringing in a very large service company's equipment to help us with not just that play, but some other horizontal oil plays also. And it's a very large company that is not housed in the Middle East.

One thing I still have to sort of pinch myself to think about is we're not getting more for gas and Gas Plus in Argentina than we are in the United States. So it's economically feasible to bring some of these service providers into the country. They need a lot of gas down there. John Herrlin - Societe Generale Cross Asset Research: That's for sure. I think it's pretty encouraging. Last one for me is the Permian. You mentioned the horizontal wells. How much incremental recovery are you going to get with the program below the water flood fields? And also, be it Wolfcamp shale exposure and how aggressive will you be on that? G. Farris: Well, the horizontal water flood, I mean, we have proven to ourselves that, that really worked. And if you put little horizontal lines on a map of all the acreage we have in water flood, it would -- you're not in that 7,500 locations that I mentioned in the Permian, which you could put -- punch more in there. So we've got a long way to go with respect to the horizontal in water flood. And it makes at all sense in the world because what most people or all of us have been doing is cycling water into permeable zones. So if you drill a horizontal well in a less permeable but still got a lot of oil in it, because we're drilling less permeable wells in the Eagle Ford and everywhere else and trying to suck oil out of there. But for oil in rich oil places, you just got to get into a little less permeable zone and frac it. And so far it's worked very well, better than our expectations there. In terms of Deadwood and the Wolfcamp, the decline, I'll be real honest with you, sorely disappointed in our first horizontal well there. And I will tell we tried some gee whiz stuffs on the fracs, and we need to go back to drilling it and see if we can get some rigs out of there, because there's a lot of people drilling wells around us that got pretty good rigs and we got 167,000 [ph] acres there. So not it's likely to be -- it could be a big play for us. John Herrlin - Societe Generale Cross Asset Research: Do you think maybe you're too distal? G. Farris: I'm sorry? Daniel Morrison - Global Hunter Securities, LLC: Do you think maybe you're too distal? G. Farris: Yes, it's possible. I don't think so. Yes, I mean, that's -- like most plays that's -- actually, I don't -- in parts of our acreage, I think because we got people that you and I could name the top 2 right off sentence that are making good wells. Some of this stuff is not rocket science you know what I'm in.

I will now turn the conference back over to management for any concluding remarks.

Thank you all for your participation. If you have any further questions, you got my number, and I'll be back in my office. Thank you.

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