Rodney Eichler - Co-Chief Operating Officer and President of International John Crum - Co-Chief Operating Officer and President of North America Roger Plank - President, Principal Financial Officer and Member of Risk Management Committee G. Farris - Chairman of the Board, Chief Executive Officer and Member of Executive Committee Thomas Chambers - Vice President of Planning & Investor Relations and Member of Risk Management Committee

Philip Dodge - Stanford Group Company Brian Singer - Goldman Sachs Group Inc. Mark Polak - Scotia Capital Inc. Sachin Shah - ICAP David Tameron - Wells Fargo Securities, LLC John Herrlin - Merrill Lynch Douglas Leggate - BofA Merrill Lynch Leo Mariani - RBC Capital Markets Corporation

Good day, everyone, and welcome to the Apache Corporation Third Quarter 2010 Earnings Release. Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

Thank you. Good afternoon, everyone and thanks for joining us for Apache Corporation's Third Quarter 2010 Earnings Conference Call. This morning, we reported net income of $765 million or $2.12 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results totaled $791 million or $2.19 per diluted share. Cash flow from operations totaled $2 billion. On today's call, we'll have four speakers making prepared remarks prior to taking questions. Steve Farris, our Chairman and Chief Executive Officer will lead off followed by Roger Plank, our President; John Crum, Co-Chief Operating Officer and President, North America; and then Rod Eichler, Co-Chief Operating Officer and President of International. We prepared our usual detailed supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discussed, such as adjusted earnings, cash flow from operations or costs incurred. 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. G. Farris: Thank you, Tom and good afternoon, everyone and thank all of you for joining us for our third quarter 2010 results call. Those of you who have followed us for many years know that Apache has a truly unique culture and is involved with strong sense of urgency and paramount of our employees and an independent mindset. And Apache's culture really is that the heart of how we build value and has taken us from very humble position not so long ago to where we are today. And I don't think there's anything that exemplifies more our third quarter, what that culture is capable of delivering for our shareholders. On the portfolio side, we announced the $7 billion acquisition of three entire upstream operating regions from BP and the Permian Basin, Canada and Egypt. These three positions have an excellent fit with our existing carriers and provide us with a rich inventory of growth and value enhancement opportunity for years to come. It was July 20, the last conference call, we were just announcing this step, and we were getting ready to get on a plane to go sell stock and debt for this important step forward. And while we clearly believed that the transaction had all the ingredients to make a great deal for our shareholders, we really didn't know how the share price would react, given the amount of new stock we were about to issue. Well, as most of you know, the stock actually went up by 5% in the three days after we announced, and this is opposite of what generally happens. Internally, we took that as an endorsement of Apache's ability to generate value out of the transaction. Obviously, we're honored with the vote of confidence. I want to ensure all of you, we'll do everything humanly possible to make good on this investment, to create long-term value for our shareholders. As of about an hour ago, we have now closed all three of the BP packages, if you haven't looked at the Wire, we just closed Egypt today. But we are integrating the people and starting to get our arms around the assets. In addition, we expect to close on our merger with Mariner Energy when the vote ends on November 10. We couldn't be more pleased and excited about the opportunity set we are building into our portfolio with the $11 billion in acquisitions. Through these steps we have added years of inventory to our core regions and have built the right footprint in what we believe are two new areas for us, the Deepwater oil exploration and LNG. LNG, for us, means the monetization of large North American gas resources at oil length prices. We've taken these steps on our own way which is the Apache way and we're confident that we'll constitute important foundations for Apache's continued growth and profitability during the coming decade. On the operating front, in the third quarter, we had a very successful quarter, with production was up 10% year-on-year and our costs and expenses on a per unit basis, excluding DD&A, it was down 3% year-on-year. John, Rod and Roger will give you more color on our results and developments during the quarter in a moment. Before getting to that, I'd like to put 2010 in a broader context, starting with where we were at the beginning of 2010 and what we look like going into 2011. If you recall, in February of this year on our 2009 year-end conference call, we were very bullish on what we've received in the acquisition market. We had amassed over $2 billion of cash on the balance sheet, and with commodity prices at more reasonable levels, we indicated that we would be very actively pursuing acquisition opportunity. Little did we know how attractive it would become. After the dust settles, and we have closed on all $11 billion of assets, apache's share count would have increased by approximately 12%, and we project we will end the year with a debt to cap of under 27%. Now on the flip side, on the production side, we are projecting December 2010 average production to exceed 775,000 barrels of oil equivalent a day. So if you use the first quarter 2010 as a baseline, when Apache's production averaged 586,000 barrels of oil equivalent, we're entering 2011 with a third more firepower than we entered 2010. That added firepower will give us more cash flow to exploit the 3.8 million acres we acquired across three of the most prolific core areas; Canada, Permian and Western Desert of Egypt. And the new core areas we've added in deepwater Gulf of Mexico has over 125 undeveloped blocks and interest in two world-class discoveries in Lucius and Heidelberg. Obviously, we're extremely excited about what we've been able to add to what we consider an already formative base and the opportunity that they bring to continue to add long-term value to our shareholders. With that, I'll turn it over to Roger, John and Rod to talk about 2010 and '11 in a little more detail. Roger?

Okay. Thanks, Steve, and good afternoon, everyone. Steve commented about how 2010 is shaping up and in a minute, I'm going to give a further glimpse of what may be a truly outstanding 2011. But before delving into next year I'd like to provide a few key highlights, financial highlights to the current quarter. We think we have fine results, even though there were a lot of moving parts with all these transactions closing. Production was up 3% over second quarter to a record 667,000 barrels of oil equivalent. Oil and liquids were, once again the king, representing just over half our production, but over 3/4 of our revenue. Cash costs per boe were essentially flat with second quarter while DD&A was up 3% as you might expect, given that our acquisitions remain at prices above our historic reserve cost. Debt ended at $6.5 billion and debt to cap at 23%, and that excludes $1.2 billion of cash on the books at quarter's end. Also, just of our year of acquisitions doesn't overshadow the considerable progress we're making on the organic side of our business. You should know that from the first quarter to the third, our oil production jumped 17% or 48,000 barrels per day, and over 3/4 of that growth was attributable solely to drilling and development activities, primarily in Egypt and especially, Australia. Turning to 2011. We're just now in the early stage of the core of next year's plan, but one thing seems certain, our year-over-year production growth should be well into the double digit. Exactly how much our production growth depends on our ultimate capital budget, which will be fine tuned between now and the year end. Our preliminary however, our capital budget is likely to reach or exceed $7 billion, up from around $6 billion this year and well within cash flow at prices currently indicated for next year. We've hedged oil for 2011 to protect cash flow and its current active capital campaign. While we believe that the supply and demand outlook strongly favors oil, with over 3/4 of our revenue tied to oil and liquids since last quarter, we've hedged 54,000 barrels per day for 2011. We used costless collars with floors between $65 to $70 to protect the downside and ceilings between $95 to $103 to retain upside potential. We now have about 100,000 barrels per day hedged in total for 2011 or just over 1/4 of our post-merger liquids production. In addition to ensuring sufficient cash flow and capital to get after the upside on recently acquired properties, we are focusing particular attention on our extensive inventory of oil and liquids prospect for next year. I can't tell you how nice it is to have a deep inventory of oil prospects already enhanced and not have to join the herd chasing after high-cost oil opportunities after essentially the train's already left the station. I would like not to hedge any additional North American gases at today's low prices. And we are continuing to focus capital on those international gas projects, which are commanding substantially higher prices. Everyday oil remains at this lumpy levels since more debt reduction than earlier anticipated. Additionally, to ensure that we make a major dent in our debt, which should peak following the Mariner merger at over $8 billion, we anticipate selling $1 billion of property sometime in the first half of 2011. We're just now in the process of determining which properties we'll be selling. So it's a bit early to tell the precise location, timing and impact of those sales. The combination of high oil prices and property sales meant lower debt and greater financial flexibility, consistent with an A-rated company. With double-digit production growth pretty much a shoo-in for 2011, a portfolio that's low in oil, a deep inventory of drilling opportunities and a strong financial position, we look forward to what could prove to be a better year in 2011. John?

Thank you, Roger. Our third quarter North American activity has been dominated by the efforts associated with the integration of more than $10 billion in assets, being added to our portfolio this year. We closed the BP Permian transaction in the third quarter and the Canadian piece closed in early October. We took over operations in the BP Canada properties on Monday of this week and welcomed almost 300 new Apaches. We will take over the BP Permian assets December 1, meanwhile, we expect to close on the Mariner merger next week after their shareholder meeting on November 10. Third quarter North American production was up over 7% versus second quarter to just under 309,000 barrels equivalent per day. Fourth quarter volumes will be up substantially as we see the impact of BP and Mariner acquisitions. Gulf Coast production increased 7% from the second quarter. Drilling activity offshore continues to be severely impacted by the permitting process associated with post and conduit requirements. While our Gulf region has received seven of the first 12 permits given to the Gulf of Mexico, requiring both NTL-05 and NTL-06 compliance. They remain significantly behind the plans for the year. At least for now the lack of clarity on the process makes it difficult for the BOEM [Bureau of Ocean Energy Management] to approve anything in a timely fashion. We are however, presently running five jack-up rigs and one platform rig offshore, drilling primarily for oil targets. With permitting delays resolved, we expect to have a very strong 2011 drilling program with the addition of the new assets from Devon and Mariner. Our third quarter project of note is the redevelopment of the hurricane-damaged Eugene Island 330 field now underway. Three wells have already been drilled and are expected to add some 2,000 barrels a day, with additional drilling to extend into mid-2011 on the 63% working interest field. In the Permian region, we increased production by 21% on partial quarter BP volumes at a very active drilling program. Permian region production is expected to be up again on the fourth quarter as core BP volumes and the Mariner assets are added in. The BP and Mariner transactions allow our newly formed Permian region to add substantially to an already robust oil Permian drilling inventory with at least 3,000 new identified locations. The region was already very active in the quarter with seven rigs, drilling 73 new wells, while 116 wells were completed as we caught up on a backlog of frac stimulation work. With the addition of the Mariner properties later this month, we expect to keep up the 20 rigs running in the Permian for 2011. We also reached agreement with Concho on the BP, more above the Yeso play in New Mexico. Apache acquired a 60% working interest in the operatorship of the joint properties. We have identified 800 drillable locations in the play and expect to be very active there next year. The region continues to evaluate horizontal drilling potentials in a variety of well known producing intervals in the basin. We continue to have success with horizontal completions in all water fluid operations notably North McElroy in the Grayburg formation, TXL South in the Clearfork and Shafter Lake in the San Andres, where we're seeing IPs in the 250 to 400 barrel a day range. The Central region also increased production by 7% from the second quarter. Importantly, distributionally gas coverage was up almost 29% on their oil productions. The region activity continues to be dominated by horizontal multi-stage frac operations in the liquid-rich Granite Wash play in Western Oklahoma and the Texas Panhandle. We expect to drill 40 horizontal Granite Wash wells this year. The first 19 are currently on production and producing a net of 2,600 barrels of oil a day and some 40 million feet of gas. As in the Permian, we continue to look for additional applications for horizontal drilling. With this in mind, we recently test what we believe to be the first horizontal test on the of the Hogshooter Wash interval of the Granite Wash play. This morning, we announced two very successful tests. Each well produced the initial rates of over 2,000 barrels of oil a day and continue to average more than 700 barrels a day and 3.5 million feet of gas after two months. We expect to drill 10 additional Hogshooter tests in 2011. Our Canada region production decreased 1.8% from the second quarter. That figure will be up substantially in the fourth quarter as we add in BP volumes and ramp up at Horn River. Our 50%-owned Horn River production continues to build and reach the 100 million per day gross raw gas milestone in August and is expected to reach 200 million per day by first quarter of 2011. We have 18 new wells on production in 2010 and expect to bring another 12 on during the remainder of the year. We will leave the year with 24 wells already drilled and awaiting completion. As mentioned earlier, our Canadian region is quickly integrating BP properties with the help of the 300 new Apaches who moved in last Monday. While it's a little crowded in our Calgary office, while we complete the space build out, we wanted to get the things together as soon as possible. The most notable operation in the BP asset base in Canada is the Noel field producing from the Cadomin and Doig intervals. In addition, the field appears to have significant modeling potential, for which testing is now underway. Noel field production is currently at 62 million cubic feet of gas per day and is expected to reach 96 million by the end of the year and 125 million by the second quarter of 2011. The region is especially excited about the strong drilling inventory and the multitude of workover recompletion opportunities that are available with the new BP acquisition. And now Rod Eichler will give you an update on international.

Thank you, John. Apache's international operations saw a good quarter, averaging 359,000 barrels of oil equivalent per day, with production increasing in three out of the four countries of operation. Egypt's gross production increased 3% to 323,000 barrels of oil equivalent per day. Net production was only up slightly resulting from timing differences in the PSC cost recovery mechanism. New production from Faghur Basin fields and discoveries as well as from our mature development lease help push gross operated oil and gas production above the 300,000 barrels of oil equivalent per day mark for the third consecutive quarter. Phase 2 of the Faghur Basin infrastructure project designed to upgrade capacity to 40,000 barrels of oil per day was completed on schedule on September 30. The acquisition of BP's risk-rated assets is complete. All contracts and agreements have been finalized and the final approvement from the government of Egypt was received today, closing occurred about an hour ago. Upon assuming operatorship, in terms of pinging on the 24-inch Abu Gharadig to Dashur pipeline will commence and we expect it to be completed by year end. Minor modifications of the existing system will be completed during first quarter of 2011 that will allow high liquid yield gas from the Faghur Basin to bypass the Salam gas plant and be directed to our existing 18-inch southern pipeline in the newly acquired Abu Gharadig plant and onward to the national gas, we had at the 24-inch Abu Gharadig to Dashur pipeline. So on gas train five and the Southern Pipeline loop projects should commence in early 2011. FEED studies with both the gas plant and the pipeline expansion have been completed. Negotiations to enter into EPC contracts are expected to be completed in the first quarter with project completions forecast in late 2012. With the addition of the BP properties [indiscernible] continued drilling success in the Faghur and the two basins and each production infrastructure improvements for 2011 drilling campaign is set to be a busy one, with the forecast number of exploratory and appraisal tests up over 50% compared to 2010 and total well count expected to exceed 200 gross wells. In Australia, net production decreased a modest 5% in second quarter. Gas production decreased due to lower customer nominations, while oil production decreased due to natural decline in the Van Gogh oilfield. Van Gogh [indiscernible] had a 52.5% working interest, averaged 23,700 barrels of oil per day net during the quarter, and the field has produced 11.2 million barrels gross, since startup in February, achieving project pay out in late September. On October 4, we shut in Van Gogh production in the FPSO production seals in the swivel portion of a detachable torque boring [ph] of DTM system were found to be leaking and no hydrocarbon or liquids will leak to the ocean. The failure of all swivel seals at the same time is pretty much impressive, and it's not an event that could have been reasonably foreseen. The result is that we have gone from a total seal failure to restarting production in 19 days. The temporary repairs have restored partial production to approximately 2,500 barrels of oil per day gross. Permanent repairs will allow Van Gogh to return to full production and 40,000 barrels of oil per day gross by mid-December. The BHP-operated Pyrenees FPSO development, in which Apache has a working interest that ranges from 28.5% to 31.5% continue to perform well in the third quarter, with net production averaging 23,600 barrels of oil per day, up 2,300 barrels per day on the second quarter. Total production from Pyrenees from start up through September 30 was 17.1 million barrels of oil gross. Pyrenees continues to believe in the steady 94,000 and 98,000 barrels of oil per day gross. Delta, Halyard and Devil Creek development projects remain on schedule to deliver first gas to the Western Australia domestic market in 2011. Halyard, in which Apache has a 55% working interest has a one-well tie back of the 2008 halyard gas discovery to our Varanus Island hub. First gas expected in May 2011. The Halyard project is designed for future well tie-ins expected at exploration success in the greater east far area. For example, Apache recently acquired a 55% in operatorship of the adjacent Spar field. The Spar-2 appraisal well drilled in October found 163 feet of net gas play in the Upper Morrow objective. Upon testing and completion of this well, we've tied into the Halyard system. The Devil Creek development project in which Apache has a 55% working interest, is 60% complete through September and are scheduled to deliver first gas from our Reindeer field by November of 2011. Fabrication of the Reindeer Wellhead Platform is 90% and installation of the 16-inch onshore raw gas pipeline from the beach process to the gas plant has been completed. To expand our exploration drilling inventory in 2011 and beyond, we've acquired eight new blocks in the Carnarvon Basin via purchase of Faghur getting over 10,000 square kilometers of new exploration acreage, thus increasing our total acreage position in the basin by 35. Apache will operate all eight blocks at average to the 52%. 4,600 square kilometers of new drilling site will be acquired in these blocks, starting in December of 2010. Australia continues to offer attractive gas prices for new long term domestic contracts for further existing products. In addition, we made progress in monetizing our Julimar gas, signed two separate hedge of agreement for 20-year supply of LNG at oil-linked prices. One of these agreements with the Tokyo Electric and the other one is with KOGAS [Korea Gas Corporation]. We also continued to add growth to our pipeline with the sanction of the Macedon domestic gas development project and the successful appraisal of our 2009 oil discovery at Balnaves. In the North Sea, production was flat in the second quarter. Increased output from our drilling program is offset by planned downtime at Bravo and Charlie platforms, an active drilling program that continue in Forties during the third quarter. Two of the field's four platform rigs will be in continuous operation. In addition, by quarter end, the Lowen Gorilla Seven jack up will begin a six-month drilling training campaign over the Echo platform. Drilling has not taken place in Echo since July of 2005. A satellite platform bridge linked to the Alpha platform is progressing for installation in 2012. This project will allow expansion of critical utilities for the field, including expanding power generation, fuel processing capacity, high-pressure gas impression, dehydration, and most importantly 18 new slots for drilling. During the quarter, a new time lapse or 4D seismic survey was completed in Forties, with fast-track process data, coming available in time to influence the drilling locations previously referenced to Echo. 4D Seismic imaging has driven the majority of drilling success at Forties for the seven years. This data, along with additional drilling slots and for the Alpha satellite platform should enable Forties to maintain steady production in the 60,000 barrel day range over the next three plus years. In Argentina net production is at 7% for the second quarter. Gas production increased 11% as a result of the successful 2010 gas plus drilling program in Neuquen, The TDS San Sebastian drilling program and the increase in the order demand. For the gas plus pricing program, we've signed one gas contract for 28 million feet gas per day in August 2010 with Pampa Energy and we expect to sign a second contract with Pampa to 25 million a day this month. These two contracts were effective January 1, 2011, and specify a $5 per million BTU gas price for three years. These contracts will go a long way in pulling up our basket price in Neuquen Basin of our $3 per million BTU. In support of these contracts Apache has drilled 18 wells a day in two fields in Neuquen Basin, with production capacity of 47 million cubic feet of gas per day. Additional wells are currently drilling. And by January 1, 2011, Apache will have more than 53 million feet of gas per day available to satisfy these higher-prices gas contracts. That concludes our prepared remarks, and we'll now be happy to open up for questions.

[Operator Instructions] Your first question comes from the line of Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs Group Inc.: I wanted to see if you can give us an update on what you're seeing in the LNG markets in terms of willingness and maybe price sensitivity, the long-term contracts and then an update on how you're thinking about Kitimat? G. Farris: Well, we were in a situation where we were really just gone out to the market because of our Wheatstone. The Wheatstone 2 contracts that were signed was very important and we wanted to have that gas on the market before we really started to actively procuring contracts at Kitimat. Right now, we're very early. Of course we have an awful lot of interest of potential buyers that want to buy gas. I don't think that there's any question, and I hear it all the time. Is it going to be gas-related? There's no projects in the world that are going to build an LNG-facility based on a gas price. It's going to have to be based on an oil price. And it's really too early to tell what that slope is going to look like, Brian. Brian Singer - Goldman Sachs Group Inc.: Separately in the Granite Wash, can you add a little bit more color regarding what zones you drilled and how you see the potential for further running room and in extent of the liquids content and the oil content that you saw with these two wells, extending to other parts of your acreage.

Brian, obviously, this is first time we tested the Hogshooter in a horizontal fashion. So it was really good results. There tends to a little shy shower in the sequence, and obviously, as our liquid yields -- the issue, of course, is that, that extends across the entire acreage base. The good news is these wells are more than five miles apart, so it's not like this is an isolated area. We have some 200,000 acres we control in this play. So obviously, we'll be casting this with additional wells next year. We presently plan 10 Hogshooter intervals alone. We continue to test the additional intervals within the Granite Wash. That sequence can change anywhere from two to eight or so separate little sand intervals. And so we're going to continue to figure out where the best place to go with our future drillings. Obviously, it's liquids. Brian Singer - Goldman Sachs Group Inc.: And what do you see with the current infrastructure? If there are any infrastructure constraints at what level of rig count you could take it up to as more of a capacity perspective? How aggressive could you ramp that up, if you want to next year?

The natural gas prices does have something to do with that. Obviously, these high liquid yields helps our economics substantially. But I think a lot of the infrastructure issues are associated with gas back outs and the bottom line is these kinds of prices, conventional drilling's kind of drying up. So we haven't seen any real change. We would expect to run some 10 Granite Wash rigs next year.

Your next question comes from the line of Doug Leggate with Merrill Lynch. Douglas Leggate - BofA Merrill Lynch: I wanted to start off with the production guidance. So the production discussion, I guess, you had a few minutes ago. If we just look at what you're saying about December, and let's assume we took Q3 as a flat rate for October, November just as a starting point, and then run December for next year, assuming that new projects offset declines, I guess, you could have about 19% growth rate year-over-year. Am I smoking something, or is that in the ballpark? And then what, really, do you see as the key project moving parts for next year that could change that one way or the other? G. Farris: Well, I think your math is probably pretty correct. The real question obviously is, and it always is, and people don't want to hear it, is commodity price. Because you really got to have capital to put on these properties. And right now, frankly, we have very good oil prices and I don't know whether the fed's buying treasury is going to help -- the bond market is going to help the economy, but it's damn sure helping the oil price. That's good news for us. The 50% of our production is on the oil side. The real question besides commodity prices is what we sell and when we sell it? We're dedicated to getting our debt to cap down and that is we're at below 27% at the end of the year. If we sold $1 billion, I mean, it would help us greatly to be down in the same category we were at the beginning of the year and we really haven't identified those properties yet. But we're going to have -- I mean, if you just look at the metrics, you're going to have good numbers next year, it's going to be hard not to frankly. Douglas Leggate - BofA Merrill Lynch: Capital expenditure on the BP assets that you've acquired, could you identify what step up might be, I think, when you did the deal you suggested BP was something planning something like a $400 million, $500 million CapEx plan. What would your numbers likely to look like on those properties? G. Farris: In fact, all our Corporate Engineering Group and our planning group have just now made a loop to everyone of the regions, including the Permian and Canada. Quite frankly, John mentioned the Yeso play. I mean, we've identified 800 locations. It's a question of how many rigs you want to run out there. This isn't a question of how much money could we spend. It's going to be how much money will we spend in each one of these areas. Because, frankly, you could double that number in the Permian Basin right now. In terms of opportunity sets and the real issue is going to be how do we balance that portfolio. It's going to be one of our real strategic issues this year. Douglas Leggate - BofA Merrill Lynch: I just wanted to drill a little bit on a couple of specific assets. Egypt, first of all, so the pipeline looks like it's going to be taken care of next year. What is your latest thoughts in terms of how much of your 300 million a day, you're going to be able to open up. And finally, Mist Mountain, you never really seem to talk about that too much. Any thoughts on the 8 trillion cubic feet asset that doesn't really seem to get much of a profile? G. Farris: The first part, dealing with the $300 million a day, and this is referencing the shut in gas that we have on wells that have already been drilled and completed in the Collin [ph] area. The existing pipeline, and I'm talking about the remote components to evacuate the gas to this new route. One is our Southern 18-inch gas pipeline, prices are in place for the last decade, of which KX [ph] and BP abrogated plant and then lanced [ph] onto a 24 inch abrogated short pipeline. That line is old and have been derated and is really carrying about 40 million to 45 million cubic feet of gas a day at present. Our expectation is to be able to add because the configuration of gas plants downstream, the gases are slightly different composition that we have in the northwestern part of desert. We're bringing the two gas down there. And it's our expectation as the pipeline pigs out, it can be rerated to its original rating approximately 150 million a day that we should be able to add about 85 to perhaps 100 million a day into that line from Marmacu [ph] Basin fields sometime in 2011. That'll be incremental to the existing gas which is going down the line right now and bring it to its full capacity.

And on Mist Mountain point, obviously, that's coal bed methane in Southern Canada. We see that project needs a substantial amount of additional research and certainly consultation before we're able to move forward. And most importantly, it needs some higher gas prices, so we're going to continue to work it. It's obviously pretty exciting to play with that kind of resource in place. So I don't think you'll see us massively drilling in Mist Mountain next year though.

Your next question comes from the line of Leo Mariani with RBC Capital Markets. Leo Mariani - RBC Capital Markets Corporation: Want to get a sense of if you guys have come up with sort of an approximate of well inventory of projects in the Granite Wash at this point in time?

We have a substantial inventory. And I can tell you that the inventory is somewhat dynamic. We continue to move different wells to the top of the list but there's an excess of 1,000 locations that we know we have out there. So it's just a matter of which ones we're were going to drill first. Like I told you, we think we can keep about 10 rigs running. The only issues out there today have been access to frac equipment and that'll probably continue to be an issue. Leo Mariani - RBC Capital Markets Corporation: And how many wells you think you guys can drill in a year with 10 rigs out there and what do those wells cost you, roughly, a piece to drill?

We're spending about somewhere in the $5 million range, sometimes it's $6 million, depends on how many times we frac these things. But one of the interesting pieces we're were doing, we did do a dual lateral this year. We have not completed the second lateral yet. But that could change our price structure on a per lateral basis substantially. We will complete the second lateral early next year, and then we'll some good feel for where that can go. So 10 rigs we can drill a well of roughly every month. So if you have 10 rigs running, you could drill 100 wells roughly. Leo Mariani - RBC Capital Markets Corporation: In terms of when you guys are talking about in Egypt, it sounds like your Phase 2 with Faghur, when you start up here, I guess it already has. So trying to get a sense of what the incremental volumes are going to be from that Phase 2? G. Farris: Phase 1 was completed back in May and that was the initial early production facility that ended up 20,000 barrels of oil per day. That was completed on scheduled. Phase 2, which we're ramping up an additional 20,000 to 40,000 which was complete at the end of September, and that is what's currently producing. We have a Phase 3, which is really to capture the 35 million to 40 million cubic feet of gas per day that's associated with oil. And that’ll be complete probably in the second quarter of 2011. Leo Mariani - RBC Capital Markets Corporation: I just want to clarify one of the comments I thought I heard in the call. Did you guys say that your thoughts your North Sea Forties production would be in the low 60,000 barrel a day range for the next, roughly, three years. Is that right? G. Farris: That's correct. Leo Mariani - RBC Capital Markets Corporation: I just wanted to get a sense on the Permian. Kind of where you guys thought you were in terms of evaluating some of these new horizontal plays out There. Is Kind of early days for you? Have you done some test wells? Can you give us a sense of kind of where you are there?

Well, I gave you a few examples of some things we've done and I think, we have tested eight different horizons out there with horizontal wells already this year. And we're finding some interesting results. I got to tell you, I'm not ready to share all of that information because was obviously some of that's critical as we gather up acreage around our successes. But we have had good results we've shared with you, a somewhat surprising benefit horizontal in these old water plugs. We'll just continue to be amazed. We're drilling wells that come in at 400 barrels a day on fields that have been 60, 70 years old and had been water flooded and on 10-acre spacing. So we think the potential for horizontal drilling in the Permian is just unbelievable, really. Leo Mariani - RBC Capital Markets Corporation: Looking at production real quick. I think you guys were just talking about getting to just over 775,000 barrels a day in December. I guess, if I just kind of think about the math from a high level, that you guys are adding somewhere around 140,000 barrels a day from acquisition and producing about 660,000 barrels a day a little bit over that I guess in the third quarter. If I add those two up gets me closer to 800,000. Is there any declines between that 800,000 and the 775,000? Maybe your Gulf volume is expected to drop a little bit or can you provide any color on that? G. Farris: We don't anticipate to shoot the gun all the time. So we're comfortable with 775,000 right now.

Your next question comes from the line of Philip Dodge with Tuohy Brothers Research Philip Dodge - Stanford Group Company: This might be a question that would be better at the next conference call, but let me try it anyway. How do you stand on what you might do on the Mariner properties after the closing? And can you reveal whether Mariner itself has applied for any drilling permits either on their shallow water or even on their operated deepwater?

Yes, I can tell you that we will have some substantial activity, especially associated with the shallow water on the shelf. That stuff will be merged into our existing Gulf of Mexico shelf operation. On the other side, Mariner has got a number of applications in certainly associated around tie backs of existing projects that they want to get tied back to existing platforms. We expect those to clear relatively soon and be able to proceed with this work. This was stuff that would have been done by now, had the moratorium not come into play. We presently do not have any wells in process for permitting to drill. And we would expect that to come in 2011. Philip Dodge - Stanford Group Company: Unrelated on hedging, you seem to be doing a lot more than you were a few years ago, when you'd sort of reluctantly admit that you were hedging even though the company is much larger, and therefore, greater protected against risk then at that time, So I'm interested in the thinking of that? G. Farris: Let me, then I'll have Roger. I think more of in terms of where we find ourselves, we have a absolute debt that is higher than what we had in the past. And if you look at our financials we're in the same with anyone else. I mean, they are oil dependent. We're 50% of it on the production side, 75% of our rate of revenues. We just bought a bunch of assets. We want to spend some money on. So what we looked at is to make sure that we could protect a capital budget in 2011 and also make sure we could pay down some debt, which is -- and we haven't found ourselves in that position in some time.

I guess the only thing I'd add, Phil, is -- and hopefully obvious , we've got a tremendous inventory and things to do with all the acquisitions that we need, and so when you do ratchet up the debt and need to make progress there. What we don't want to have happen is do that to the detriment of being able to after the upside on these properties, while continuing with our base long-term company builder-type project. So this probably ought to be considered, to some extent, as you're right about our size, in some extent, ought to be considered as sort of a one-off for an unusual set of circumstances, where we want to both pay down debt, and also get after the upside of these properties.

Your next question comes from the line of Mark Polak with Scotia Capital. Mark Polak - Scotia Capital Inc.: Question for you on the Wheatstone, with the recent sales agreement you've signed just curious where that leaves you now, in terms of how much uncontracted gas there is? How many more deals to do and then are you looking at sanctioning decision, kind of late 2011 there? G. Farris: With regard to the volumes, the Wheatstone project phase that we're involved in, about 5.83 million tons per annum is the gross size of facility. Apache's net share of that will be about 0.95 million tons per annum. To date, with the announced TEPCO and the KOGAS deal, we would have placed in the market about 0.75 million tons per annum or about almost 80% of the allowable throughput volume that we want to share. So that's a really good start. As far as the final investment decision, that's pretty much on track for a time line would lead us into probably summer time of 2011, early third quarter. Mark Polak - Scotia Capital Inc.: On Egypt, similar rate just on Salam 5. Wondering where you guys are out there in terms of time. G. Farris: We've completed the FEED studies this past quarter, at the end of the quarter. And we expect in the first quarter to enter into EPC contracts, that we're going through the process for the joint venture companies right now to select the vendors and do the corporate negotiations on the price. We expect that we've done sometime in those 120 days. We also started construction.

Your next question comes from the line of John Herrlin with Societe Generale. John Herrlin - Merrill Lynch: What’s your unamortized property cost level on a dollar basis right now, post all the acquisitions?

I don't know John, I have to get back to you after the call.

With the Gulf of Mexico, I mean, we all hope that the BOEM works quickly, but in the event that they don't, will you just throttle back or would you accelerate with more on-shore type development for next year? G. Farris: The one thing I will say is that we are certainly not out of opportunities in terms of the Permian Basin, in terms of Canada, in terms of Egypt. Our biggest challenge for 2011 is how we allocate the cash flow that we have. It's not in terms of looking for opportunity, it's more as making sure we spend money on the right opportunities. So the Gulf of Mexico, it wouldn't bother me -- I wouldn't like it because I think that's the wrong answer, the United States. I don't think -- we're not worrying about where we're going to put capital next year.

I'm just mention, Thomas Chambers and I were talking about this earlier that when the guys in the regions submitted their request for capital, somewhere between $8 billion and $9 billion. So when we talk about $7 billion or 7-plus billion of capital. It's not because we don't have any more to do with this. There's lots more to do and that's really -- that number will probably go up in terms of what they could do as we do get our arms around the BP properties and the Mariner properties. John Herrlin - Merrill Lynch: Normally, you talk about services costs, and we've heard many other companies kind of complain about the rise of frac costs, what are you seeing in your areas? And how are you managing, because you weren't vociferous this time, Steve? G. Farris: You can't have $3.80 gas and have comps like we have them, not forever. And I have no idea about other's economics. It would be very difficult in our economics just to drill a horizontal gap well in the United States right now. And costs are a big component of that. And I will tell you, sooner or later that's going to change, that's got to change.

Your next question comes from the line of David Tameron with Wells Fargo. David Tameron - Wells Fargo Securities, LLC: The Hogshooters, is that near the Marmaton? Is that near the Des Moines? Where exactly is that in the...

In the press release, we gave you the actual location of those two tests we did. But yes, there is Marmaton in the area and there's certainly, Granite Wash A, B and C as well. So the press release has the actual location. David Tameron - Wells Fargo Securities, LLC: I was trying to get more of the -- where it's at in the play. Is it above the Marmaton?

It's high in this section. This would be one of the shallower intervals in the section. David Tameron - Wells Fargo Securities, LLC: Did you ever give well costs? And if so, I might have missed it.

On the Granite Wash wells? David Tameron - Wells Fargo Securities, LLC: Yes, the most recent wells.

It depends, again, on the well. but we can spend somewhere in the $5 billion to $6 billion range, again, depending on the number of fracs, because that's really the key in these things, depends on when you put six fracs or 16 fracs. David Tameron - Wells Fargo Securities, LLC: Steve, you touched on this briefly, but if you think about the hurdle constraints for the next couple of years, get your program done, I mean, you said you have too many projects, but to get the program done, you want to get done. What's the biggest hurdles standing in way right now, as you see it? G. Farris: Well, for the most part, it's all pretty well laid out. The real decision we're going to make frankly and we haven't even -- is much money we spend in the Horn River. Because if you -- we anticipate we will be ready for actually get six contracts on Kitimat, but we spent probably $370 million there this year, John?

Yes. G. Farris: And it was on purpose because we were really wanting to make sure from a reservoir standpoint that the reservoir's as good as what we thought it was. Obviously, we found out, it wasn't as good as we thought it was. And now it's a question of how do you balance your current capital against future opportunity. And that's going be one of the toughest things we're going to have to decide here in 2011. David Tameron - Wells Fargo Securities, LLC: And there's a thing about program execution. It sounds like you have all equipment, the people, I guess, you added the people with the BP transaction, but you have the people, the equipment in place to get the program executed? G. Farris: We're going to spend $6 billion in 2010. We spent quite a bit more than that, I think in 2008. So from a manpower standpoint, our organization can spend that. I can't emphasize enough the most important thing we have in front of us and the challenge is how we allocate the cash flow that we generate, because that is key to making sure this -- we take advantage of what we bought.

One challenge we got on the Permian on the BP property is these properties weren't for sale 30 days before basically we got to them. So they weren't all put in pretty packages and subdata is an issue, and it is going to take us a little bit of time to get our arms around exactly what the opportunity set looks like. So we've got some data challenges, but we're turning into it and we'll get after that fairly shortly.

Your next question comes from the line of Sachin Shah, with CapStone Global Markets. Sachin Shah - ICAP: Just want to get an update on the shareholder vote for Mariner on the 10th. Just kind of anticipated timing of close, thereafter?

I think that question was about an update on the vote of the Mariner deal. And with not getting into specifics, I think... G. Farris: I'm not sure we can answer this question. Right now, we've got about 45% of the vote in that I understand, and you'd have to be... Sachin Shah - ICAP: Just to clarify I wanted to find out the closing of the transaction after shareholder vote. G. Farris: It is immediate. As soon as the shareholder vote is counted and it's official, we will then own Mariner Energy. Sachin Shah - ICAP: You've announced a lot of transactions this second half of the year. I just wanted to find out, as far as pipeline, going forward, are you going to be as kind of aggressive as you've been thus far? G. Farris: In terms of the acquisition pipeline, I think, we're going to kind of slow down here a little bit. Frankly, we don't plan acquisitions. We never have. One of them was very fortuitous for us, obviously, the biggest one we did. But in terms of going forward, we had a pretty good asset base then, and I think, we have a truly formidable asset base now. So we're out there looking to grow just to grow. Sachin Shah - ICAP: You mentioned earlier about the stimulus, being a positive kind of tailwind for oil prices. How does that kind of influence your thinking about getting or acquiring opportunistic assets or assets on a opportunistic basis?

Can you repeat the question? I'm sorry, we're having trouble hearing you. Sachin Shah - ICAP: So you mentioned earlier in the call how the stimulus from the government is probably somewhat of a tailwind in relation to oil prices and helping oil prices kind of move higher. And so kind of that train of thought how does that process allow you to kind of think about acquisitions and acquiring assets going forward. G. Farris: I might just comment that my mind hasn't really gone to that yet. Because we do as we have indicated -- we got to make a dent in our debt. And we also have plenty on our plate from an investment standpoint. And I also, Apache haven't been around for 50-plus years. You don't want to jinx this thing by counting on it. So we start to look at it day-to-day, and every day that goes by is another day that we pay down a little more debt and put ourselves in a position ultimately where maybe we could be back on that trail. But I don't think we look at that as imminent but clearly at this price. Our internal price forecast that we're using is $70 on oil. So anything above that looks like gravy at this stage.

There are no further questions. Presenters, do you have any closing remarks?

I just want to say thank you for joining us today. If you got any further questions, I'll be in my office after the call. Thank you.

This concludes today's conference call. You may now disconnect.