Bob Dye - Vice President of Investor Relations G. Steven Farris - President, Chief Executive Officer, Chief Operating Officer, Director Roger B. Plank - Chief Financial Officer, Executive Vice President

Tom Gardner - Simmons & Co. David Tameron – Wachovia Securities Brian Singer – Goldman Sachs Leo Mariani – RBC Capital Markets David Heikkinen- Tudor Pickering Holt

Welcome to the Apache Corporation third quarter earnings 2008 conference call. This call is being recorded. Today’s presentation will be hosted by Mr. Bob Dye, Vice President of Investor Relations.

Thanks for joining us today. This morning Apache Corporation released third quarter 2008 results which totaled net income of $1.2 billion or $3.52 per diluted share and cash flow of $2.1 billion. Today’s discussion may contain forward-looking estimates and assumptions and no assurance can be given that those expectations will be realized. A full disclaimer is located on our website. In addition any non-GAAP numbers that we discussed such as adjusted earnings, cash flow from operations or costs incurred will be identified as such with the reconciliation located on our website at www.apachecorp.com. I’ll note that we routinely put important information on our website. As an example last week we had an analyst meeting in Houston and we currently have slides from that meeting on our website for your review. On today’s call Steve Farris, our CEO, and Roger Plank, our CFO, will make prepared remarks prior to taking questions. With that I’ll turn the call over to Steve. G. Steven Farris: Thank you for joining us for our third quarter earnings conference call. During the quarter Apache’s international portfolio once again demonstrated its strength and momentum through drilling success and our sustained progress in delivering our pipeline development projects, and strong earnings of $3.52. I’d like to echo Bob’s comments and thank all of those who attended our yearly analyst conference last week in Houston. We really did appreciate the opportunity to walk through some of the details of our portfolio and the growth plays that we have that we’re presenting around the world. I’d encourage those who did not listen to view our website and listen to our webcast. Today in my remarks I’d like to review just quickly our position and our outlook, and then give you some activity highlights from our regions. First of all, Apache’s in a very strong and honestly differentiated position in the current volatile environment. Our portfolio is balanced which benefits our shareholders across multiple business environments. That means we’re balanced across products, pricing benchmarks, international basins and play types. We also hold strong positions in all the places we operate. We’re the number one producer in Egypt’s Western Desert. We’re the number two producer in Western Australia. We’re the number one producer in the US Gulf of Mexico shelf. We’re the number three producer in Oklahoma. Along with our partner in Canada we’re the number one producer in the Ootla shale play in Canada. Our strategic platforms in building value in mature basins, our international exploration and global graphs are aligned with long-term realities for this energy industry. We’re financially stronger than we’ve ever been. We have seven development projects underway that alone are expected to add about 120,000 barrels of oil equivalent to our production over the next four years. We have a resource depth as we updated in our conference last week with 9.8 barrels equivalent of resource potential on our 36 million acres across the globe. Finally and probably most importantly, Apache’s culture has gotten to this point and that strength will continue to guide us in the future. I’d like to summarize quickly our immediate outlook. In the short term we intend to live within our means. We’ve been living within our means for a number of years now which puts us in a very comfortable relative position in the industry. We’re going to stick with our conservative principles and we review our investment plans on a quarterly basis. We’re going to remain focused on execution on two fronts: Delivering our pipeline of development projects and continuing our exploration in our ace countries of Australia, Canada and Egypt. We have a strong balance sheet. We have approximately $2 billion in cash plus another $2 billion available in credit facilities. We’ve stayed out of the asset market for some time now as the recent spike in commodity prices made good deals hard to find. Things are clearly changing now at least presently and we are going to evaluate asset opportunities selectively. We have a lot of opportunities within our portfolio and we’re not in any rush. We’d only consider opportunities that would advance our portfolio and generate long-term value for our shareholders. Last week we provided production growth perspective for 2009 of 6% to 14%. I know that’s a wide range. I think everyone would agree that uncertainty is abnormally high right now. Assuming we do recover the 2008 shut-in volumes in Australia and the Gulf of Mexico that I’ll go over in a minute, we would grow at about 6% and we expect our development projects should add another 6% to 7% for the potential of a 13% to 14% growth rate. But within that range our annual growth rate will depend upon the level of capital spending for the year and our planning process has just begun. Frankly until we get closer to 2009 and get a better idea of price and cash flow, it makes no sense to zero in on capital number at the present time. I think if you back up a little bit, we don’t make widgets. The opportunity ahead for us has never been greater. Despite the recent downturn, the world still needs energy to the tune of 85 million barrels of oil a day and ever increasing quantities of gas. Just yesterday the International Energy Agency’s upcoming annual study was quoted by the Financial Times as having found oil fields globally to a decline rate of 9.1% per year and 6.4% expected even with large investments to the tune of $360 billion. I noticed today that the IEA has said that the article was misleading and several months old but I think it does point to the fact that no one can deny that there needs to be tremendous capital in order to meet the demand over the next several years. In any event we’re going to continue to be conservative and to balance our capital program with our cash flow. With the frenzied boom time activity coming to a halt we believe it’s an opportunity to build long-term value. I’d like to address specifically the results for the quarter and Roger’s going to cover the financials in much more detail. I’m going to speak to our production for the quarter. Production as you saw I’m sure in the release was 511,000 barrels of oil equivalent a day. That’s 7% below the second quarter of 2008 which is entirely due to the outages in Australia and the Gulf of Mexico, and we expect to recover substantially all of those volumes by year end. In Australia we restored partial production on Varanus Island during the third quarter of 2008 but we still lost a net of about $75 million a day and about 2,800 barrels of oil per day due to the pipeline explosion which is relative to the second quarter of ’08. Net production of 4,000 barrels of oil per day and 78 million cubic feet of gas a day remain shut in and should be restored by year end. In the US substantially all the production variance relative to the second quarter of 2008 was the restful of Hurricanes Gustav and Ike. Most of this shut-in production was due to pipeline and processing facility issues. As of now we anticipate those to be cleared by year end. Only 12% of our shut-in production is associated with platforms that we actually operate. Apache had four operated and two non-operated platforms which were lost. These contributed volumes of about $7.5 million a day and 1,200 barrels of oil per day in the previous totals. We expect to be able to recover all but about 1,100 barrels a day from those leases because a couple of the platforms that were lost were processing platforms instead of producing platforms which will allow us to take the production to alternative processing locations. We’re currently producing about $250 million a day and 38,000 barrels of oil per day but by year end we expect the worst to be behind us. For the year the one-off Varanus Island and hurricane events reduced our annual production growth by 3% each or 6% in total. These events didn’t affect our reserves and actually if we’re able to restore the production by year end, it gives us a leg up on 2009 growth. I’d like to now cover our regional operating highlights. For additional details I encourage you to review a lot of this material which is on our website from last week’s analyst conference. In the central region we have expanded our acreage base in the Stiles Ranch which is in the Texas Panhandle threefold since the beginning of the year and gas production exceeded $90 million a day in the area for the first time during the third quarter. In East Texas we drilled the [Folk 6H] horizontal well which was in the Bossier formation and it’s averaged about $8 million to $10 million a day for the first 90 days of production. We have the potential to drill as many as 12 offset wells. In the Gulf region the Geauxpher 2x deep water well at Garden Bank 462 is currently completing. We expect net production of about $50 million a day from the development area which should come on during the first quarter of 2009. We see the potential to drill at last three additional wells on that block next year. Also in the Gulf region during last week’s conference we showed for the first time our acreage position in the Echelford shale in Central Texas. The Echelford underlies the Gideon’s Austin Chalk field in Berlison, Brazos, Washington, Lee and Fayette counties and we have now over 450,000 acres, 425,000 of which is HBP. We have just drilled our first extended lateral. We put 10 fracs which is an experiment actually. It came on yesterday pulling over 525 barrels of oil per day. I’ve got to warn you these are early results. We have very little idea what the decline rate will be but I can tell you for sure that this rate exceeds our expectations. In Canada recent production results from wells we drilled with our partner in Canada, Ootla, suggests 7.4 bcf per well utilizing a 10-stage frac completion. Frankly we believe that there’s further reserve upside in completing these wells with even more frac stages which is what we plan to do this winter. At 7.4 bcf per well this play works with [Henry] gas prices of about $6 and represents a net recoverable resource potential of 9 to 16 tcf for Apache. In the North Sea our third quarter production achieved its highest average in two years. We’ve drilled nine wells this year that produced at a peak rate of about 17,000 barrels of oil a day during the third quarter of 2008. We have now developed a four-year drilling inventory of over 60 wells which are targeting more oil production potential like the nine wells we just completed. In Argentina we completed our 2,500 square kilometer 3D mega shoot in Tierra del Fuego which is an island on the southern tip of Argentina and have identified over 100 potential features to drill in the future. In the [Niakin] Provence we’ve had notable successes there and expect upcoming production from areas to qualify for the premium sales price under gas plus programs. In Australia we continue to develop four major projects to remain on schedule. During the third quarter we drilled primarily development wells in Carnarvon Basin. We do expect we have now taken custody of a rig for our Gibson Basin exploration program which should start next week and also potentially exposes the company to some meaningful oil reserves. Finally in Egypt we achieved record production, made four discoveries during the quarter, and East Bahariya concession which is in the [Abergudique] Basin. The D1X well found 61 feet of upper Baharia pay along the same 13 mile ridge as the C1X well that we reported last quarter. The D1X tested 1,145 barrels of oil a day and could have another water flood potential pending further appraisal along that ridge. Our third well on the ridge, the E1X actually has currently been logged and has Upper Baharia in it also. In the East [Bennie] Swift concession which is in the [Bennie] Swift Basin days are East 1X well tested 930 barrels a day which is from Aboroash G and also has water flood potential associated with it. These two discoveries are important because they potentially add to our inventory of water flood projects. We’re currently producing 37,000 barrels of oil a day from eight different water flood projects that we have undertaken in Egypt just in the last two years. In the Matru Basin on the Khalda offset concession the Sultan 3X wildcat made a gas connance safe discovery tested 5,027 barrels of oil per day and 11 million cubic feet of gas a day from [Jurassic sopic] formation. Finally yesterday I think we announced the West Colopsha concession we drilled a well that discovered oil and tested 4,746 barrels of oil per day again from the Jurasic sopa at 14,600 feet. This well is a look alike to the Heckit 2 well that we reported last quarter that’s still actually producing over 2,000 barrels a day. Both wells tested black oil from a much deeper horizon than we earlier thought possible. It’s a much cooler basin than the [Shoshone] Basin where we have the cosser gas. It opens an oil play fairway of potentially 800 square miles, mostly within Apache operated concessions and we plan several wells next year to evaluate the play. Now I’d like to turn it over to Roger. Roger B. Plank: As the credit crunch gave way to global downturn, Apache turned in solid third quarter results and earnings nearly doubling the year earlier period. Cash flow increased by $0.5 billion or nearly 1/3. 43% higher oil prices and 49% higher gas prices in the quarter enabled oil and gas revenues to climb $870 million from third quarter ’07 to $3.4 billion. This overcame a 9% reduction in volumes and enabled earnings to outpace all but the prior quarter. As we’ve indicated in press releases and on our website, the Australian pipeline incident and Hurricanes Gustav, Ike, et al put a dent in our third quarter production. As discussed at last week’s conference these incidents constrained third quarter production to 511,000 barrels of oil equivalent a day. I’d reiterate that this production is not lost forever but rather deferred. As Steve indicated, we anticipate volumes should be restored between now and year end. Foreign exchange again impacted the quarter’s results, this time on the plus side given the rebounding US dollar. Normalizing the impact of foreign currency fluctuations on a deferred tax results in adjusted earnings of $3.19 per share versus $2.17 in the third quarter of ’07. Now if we compare third quarter to the second quarter of 2008, a $9 per barrel and $0.66 per mcf decline in oil and gas realizations coupled with a 7% decline in production reduced oil and gas revenues by $535 million and earnings by $254 million or 18% sequentially. Cash flow likewise declined $196 million or 8% sequentially. Cash margins declined 13% with lower prices making an impact but remain quite strong at nearly $52 per barrel of oil equivalent. Including DD&A our total pre-tax margin decreased a little over $8 to a still respectable $38.60 per barrel of oil equivalent. Now turning to cost details, lifting costs included a number of items that caused their increase to $10.39 per boe from $8.90. The start of repairs at Varanus Island and repair and maintenance work in the Gulf Coast plus increased workovers and power costs in both Egypt and the central region were primarily responsible for just over half or $0.83 per boe of the increase. Lower production accounted for the remaining increase in our unit costs because most of your base lease operating expenses offshore is fixed. It doesn’t go away with shut-ins. It just gets divided amongst fewer barrels which brings the cost per boe up. Hurricane repairs will continue to pressure lifting costs until covering our insurance deductibles. Physical damage insurance coverage is subject to a net deductible of around $7 million in Australia and $70 million in the Gulf of Mexico. The Australia deductible was satisfied in the third quarter and the Gulf deductible should be satisfied around year end. Based on present expectations we have more than enough insurance to cover costs above our deductibles in both the Gulf and Australia so once we’ve reached the deductible limit our lease operating expense should revert to normal. Full cost duty NA increased 1% sequentially to $11.93 per boe consistent with recent drilling costs. General and administrative costs decreased $0.35 to $1.22 per boe. Absolute costs were down $21 million, the result of lower stock-based compensation expense. Leaving aside any changes in stock price, rising fourth quarter production should enable a rate of somewhere around $1.25 to $1.50. Taxes other than income increased $0.53 to $6.48 per boe with $0.42 related to lower production and $0.11 primarily related to higher North Sea volumes and revenues resulting in increased PRT taxes. Finance expense decreased $0.07 to $0.71 per boe on greater interest income given higher average cash balances. I think as most of you are aware, earlier this month Apache issued $800 million of five and ten-year bonds. This will add about $13 million to our quarterly interest expense while adding to our overall fire power as well. Having the ability to tap capital is nice. To do it in the peak of the credit crisis at an average cost of under 6.5% is frankly exceptional. The proceeds arrived October 1 so after third quarter’s end. We anticipate our cash balance at year end to be around $2 billion +/- depending on prices and the timing of production recoveries. This includes working capital changes for the impact of third quarter capital carryover into the fourth quarter and also reduced receipts following hurricane and Varanus production curtailments. Turning to income taxes, our third quarter effective tax rate decreased to 34% from 38% in the prior quarter. As mentioned earlier, our deferred tax expense benefited from the strengthening US dollar by $113 million reducing our effective tax rate. Our deferred tax percentage increased to 51% from 22% in the second quarter and that just reflects significantly lower current tax estimates given lower commodity prices. Given the heightened volatility of both commodity prices and the US dollar, estimating our future deferred tax percentage and effective tax rate is difficult at best. Also difficult to predict is the exact timing of production recoveries due to factors beyond our control such as when damaged pipelines will come back on line. At last week’s conference we took a stab at our estimated average 2008 production and came up with a range of 540,000 to 545,000 barrels of oil equivalent a day. You can do the math to arrive at a fourth quarter estimate but I’ve got to tell you there is a lot going on here that has potential to impact fourth quarter volumes in either direction. Despite the short-term uncertainties, Apache’s financial condition and outlook are sound. In the face of changing global economic circumstances not only are we in a position to carry out our business strategy, Apache is well positioned to take advantage of the inevitable carnage that springs from adversity. We are by no means immune to substantially reduced oil and gas prices or the bleak world economy. However given our ways, we earlier took steps that put us in good stead relative to our competitors. Because we didn’t chase the upswing too hard and avoided outspending our cash flow, we’re among the fortunate few with access to capital at a reasonable cost. Our A- credit rating, which is ignored most of the time, has proven itself invaluable in accessing additional capital in today’s difficult environment. Debt, even taking into consideration the additional debt that came with the bond issuance, is a manageable 20% or so of our total capitalization and cash of around $2 billion is an opportunity fund. Our unused credit facility commitment totals $2.3 billion. It’s committed for the next four years and while you really don’t know until you test that or draw down from the banks which banks will fund and which banks won’t, I will tell you that our lead bank indicated recently that they have had draw downs literally thousands over the last month and there was only one bank that didn’t fund. It shouldn’t surprise you that was Lehman and they are not amongst our banks in our credit line. If you add the $2 billion and the $2+ billion of unused credit facilities, at least in theory we’ve got potential fire power or dry powder of some $4 billion. The final point I’d make is that there’s nothing like rising production to mitigate the impact of falling prices. Although we don’t yet know our capital expenditures or our precise production for ’09, it’s hard to imagine a scenario under which we would not grow production next year. These advantages give Apache an important leg up on our competition in terms of turning adversity to advantage, and while difficult times challenge every company Apache’s at its best in tough times such as the environment in which we find ourselves today.

With that we’d be happy to open it up for questions.

(Operator Instructions) Our first question comes from Tom Gardner - Simmons & Co. Tom Gardner - Simmons & Co.: Steve, I appreciate your analyst conference last week and I appreciate you sharing your views on the M&A markets where you basically said that you thought things might get worse before they get better. Is there anything you’ve seen in the last week that might alter that view at all? G. Steven Farris: I think it starts with the global economy and I’m certainly not an economist by any stretch of the imagination but I don’t see anything out there that leads you to believe that things are going to get better before they get worse. To me the real proof in the pudding is going to be what consumer spending’s going to be between Thanksgiving and Christmas, and I question whether or not we’re going to have any kind of robust consumer spending during that timeframe. But in terms of overall oil and gas, the only silver lining and it depends on where you’re coming from, frankly although it hurts our earnings and our cash flow things getting worse are not a bad thing for a while. Costs come down, rigs are laid down, people start paying real numbers for acreage rather than paying way too much for acreage. So in our business that’s not a big thing to put those costs on the books at a lower cost. Having said that, we have created a just-in-time inventory certainly in gas in this country if you just look at the type of things that are being drilled. But my question is, how long can you not drill before you start having a problem again? Roger B. Plank: I’d mention too is when you live it you see it a little bit differently but in a capital intensive business like ours, it takes a while to put the brakes on capital programs because you make commitments in advance. So when cash flows drop rapidly with prices you really don’t see the damage for a quarter or two. So, unless you see some kind of snap back in prices which is highly unlikely at this point in time the chances are that it is the same as Steve indicated last week, it’s going to get worse before it gets better. A lot of those things don’t play through to company’s balance sheets for a quarter or two. Tom Gardner - Simmons & Co.: Just jumping over to Egypt, you’ve had continued exploration success there, can you discuss your thoughts on the possibility of getting some extensions on those concessions lives, particularly in the Khalda area? If you were to enter negotiations would that diminish your current metrics? G. Steven Farris: For those of you who may not be familiar, concession agreements have a term that is an exploration term and then you have a development lease and a big portion of Khalda is in a development lease which then has a term of 20 to 25 years. Our greater Khalda area doesn’t expire until 2023 and 2024. We renegotiated that back in 2005 and extended those concessions from 2010 and 2011 to 2023 and 2024. All of our other concessions in Egypt that are development leases have at least 20 years to run. So, from that standpoint we’re in pretty good shape. On the exploration side we have some exploration acreage that will start turning over in 2010 that we’re intent on over the next 18 months to work with the government to extend. Tom Gardner - Simmons & Co.: Just one last thought on the concession agreements, when they expire how is the equipment handled? Do they purchase it from you or is it just turned over to the government? What’s the compensation? G. Steven Farris: Well, the way the concession agreement works is we basically have been repaid for all of the equipment that are associated with it through a cost recovery. So, it is basically after the cost recovery period legally the Egyptian government.

Our question comes from David Tameron – Wachovia Securities. David Tameron – Wachovia Securities: A couple of questions, Roger you referred to it briefly but the LOE, can you go through that again? You said you have $70 million deductable in the Gulf and you think that will be met by year end, is that what you said? Roger B. Plank: Yes. We have to chew through our deductable before the insurance proceeds kick in so we’ll have a higher LOE per BOE cost than what would otherwise be the case until we get through that and that should happen right around year end, maybe it will trickle in to the first quarter in part but most of it will be behind us at year end. After that we’ve got sufficient insurance that any incremental costs would be covered by that so you wouldn’t see it in our numbers. David Tameron – Wachovia Securities: What does that hit for the quarter? Does that hit in LOE? Roger B. Plank: Well, I’m specifically addressing LOE. David Tameron – Wachovia Securities: And that’s where the insurance deductible, that $70 million hit during the quarter. Roger B. Plank: LOE, yes. What tends to happen is your LOE costs are the ones that you – you also have capital costs but those typically are later on so they get covered more by the insurance if you know what I’m saying. So yes, you’ll see it in the LOE. David Tameron – Wachovia Securities: Then a question for Steve, you talked about the Eagleford and at the conference that was more focused on the oil side, can you talk about the potential on the gas side in that same property? G. Steven Farris: In fact we’re drilling two wells that we think will be in the gas window as we speak. Certainly, if you move down to the gassier part of the Austin Chalk which many of you might have read, Petrohawks, now we’re quite a ways to the northeast of the Petrohawk acreage but there’s a high in between the two but both of them are over old Austin Chalk fields and they drilled in to gas window of the Austin Chalk and we’re drilling these two wells in the gas window of the Austin Chalk and we anticipate them being gassier. Actually, we anticipate them being gas. Certainly gas can move through the shales a little bit easier than the oil. Although, I’ll be real honest with you, I’ve got to be careful, I really wasn’t expecting that kind of rate out of the Eagleford in the oil sites. 525 barrels a day if it will roll over will be very, very economic. David Tameron – Wachovia Securities: When do you anticipate giving us an additional update on that? G. Steven Farris: Well, we’ve got another well that we’re getting ready to frac. We’ve got four wells down with horizontals in them that we’re fracing. We just fraced a second well and we should have some results in the next month. It will take a month to understand the decline curve associates with this first well that we’re talking about. David Tameron – Wachovia Securities: Then one last question, and I think it was Roger that mentioned it, you talked about fourth quarter volumes and you said that there’s a number of factors. Any other big factors besides the GOM and Australia, the timing of those two that we could look at in fourth quarter as far as the swing on the volume side? Roger B. Plank: Those are the biggest although we also have late in the fourth quarter, 100 million a day net and 5,000 barrels a day net in Egypt that will begin to come on line so the timing of that could also impact. David Tameron – Wachovia Securities: And you scheduled that for late 4Q? Roger B. Plank: Right.

Our next question comes from Brian Singer – Goldman Sachs. Brian Singer – Goldman Sachs: One quick question, any update on the Australia gas contract, my apologies if you mentioned it earlier. G. Steven Farris: No, other than that we’re continuing to noodle very small points Brian. Brian Singer – Goldman Sachs: In Egypt, I guess any signs, maybe it’s a little early but can you talk about anything you may be seeing in terms of gas demand and any implications from a potential decrease in economic growth there and what that means for your ability to extract additional price increases there? G. Steven Farris: I think we showed a chart at our analyst conference on terms of the growth rate in Egypt, what it’s been domestically. It’s significant, if you look at that chart, look on our website, the last three or four years it’s been about a 22% and they have targeted natural gas to back out oil so I don’t see that diminishing. The one thing I will say is that not unlike any other country of the world, Egypt watches what happens to natural gas in this country. At current prices the ability to set down and talk about meaningful price increases when you got a NYMEX where it is priced today is going to be more difficult when it was at $9. Having said that I think over time for two reasons, one is they have to have investment for natural gas and they have to have infrastructure which we have been doing both. And, the need that they have I think over time that will happen. I just think what is happening in this country has an impact on what is happening in Egypt. Roger B. Plank: The one thing I would say, you may have noticed in our numbers in the blast packs that our average price in Egypt was $5.62 for the quarter. So, we tend to talk about most of our gas which is capped at $2.65 but we also have an old, I think we’re the only company with an old sort of legacy contract that is tied to crude oil that has dragged that price up. So, Steve’s point about prices coming down, all of a sudden that $5 gas looks more attractive. G. Steven Farris: The thing is we’ve got to be careful, we’re going to start diluting that as we come on with our [Crawford] gas because that’s 100 million a day contract and if we go up to $7.50 on gas all of a sudden you’ve got $6.50 at $2.65 against that prices versus what you’ve got today which is about $3.50 versus that price, $4.50 versus that price so you’re going to start diluting that contract. That contract is until 2013, that existing contract that we have.

Our next question comes from Leo Mariani – RBC Capital Markets. Leo Mariani – RBC Capital Markets: A quick question on your Egyptian gas lines this quarter, it looks like you guys posted a pretty healthy increase. It is my understanding that you didn’t have your [inaudible] plant coming on for a while, just curious as to why you had the nice pop in the Egyptian gas here in 3Q. G. Steven Farris: Well, specifically what has happened is that we’re starting to put more gas – part of our gas takeaway is going through the Obaiyed plant which is a Shell plant and that Shell plant we have the ability to produce 150 million a day until they get some work done and then we can go to 210. What’s happened is Shell’s production is falling off so we’re getting a bigger share of that plant than what we anticipated. We have had hot days of over 200 million a day going through the Obaiyed plant. Leo Mariani – RBC Capital Markets: Jumping over in to Canada real quick, your gas volumes have been declining pretty steadily over there. Do you guys have any sense of when you think that will kind of turn around and flatten out and maybe start growing kind of what point in time you think that can happen? G. Steven Farris: I’m pretty encouraged given the amount of capital we put in Canada, our ability to keep that relatively flat frankly. The other thing you’ve got to keep in mind is that in the second quarter we sold about 15 million a day net of Canadian gas so you’ve got to be careful when you compare quarter-to-quarters. What’s happen with Alberta with respect to the royalty our big growth in Canada is going to be from our Utla play over time. In fact, if you wanted to be very optimistic over the next four or five years the Utla play net to Apache could be the same as what we are producing today. We’re producing about 25 million a day right now. Our plans for the winter right now with our partner is to drill a multiple of the wells that we’ve drilled in the past and we’ll have the capacity to take that gas out of there also so that ought to help our production going in to next year. Leo Mariani – RBC Capital Markets: Then you’ll start to see some impact once we get in to spring of next year from increased Utla? G. Steven Farris: Probably spring and fall because what we’ll do is drill those wells in winter and actually frac them and hook them up later in the spring/summer time frame. Leo Mariani – RBC Capital Markets: And what’s your capacity up there out of Utla in terms of your net share? G. Steven Farris: Well, our capacity right now is about 25 million a day which we will be working on this winter and increase that significantly.

Our next question comes from David Heikkinen- Tudor Pickering Holt. David Heikkinen- Tudor Pickering Holt: Just a question about Argentina and any thoughts around the pension plan nationalization and kind of the moves there relative the thoughts at the analyst meeting of being able to increase pricing over the long term? G. Steven Farris: I think you’re seeing an administration that is trying to sure up their financial position. I don’t know what the out crop is. I know we have a number of Argentine employees that were pretty long faced when they heard that news. The fundamental problem in Argentina if you take out the things that go back and forth with respect to different laws and stuff and unions, etc. they have a fundamental problem with meeting demand, whether it’s on the crude side or the gas side. Again, I would refer you to our website but now their supply is less than their demand and they’re having to import LNG or use diesel or make propane natural gas by putting air in it. What they’ve done is come up with a program that is called gas plus that basically allows you to contract directly with a supplier at whatever price the market will bear. Part of our program for the first part of next year – right now actually and the first part of next year is going to be drilling those gas wells in the [nic] and to test the resolves of the government to actually make that work. I mean there is a law in place and the only time you will know whether or not that is really going to stick is when they get in to the winter months which is our summer months and they need gas whether or not they’re going to redirect that gas in to the residential market. But, I think fundamentally things have to change there. David Heikkinen- Tudor Pickering Holt: How do you internally assess risk of nationalization? G. Steven Farris: I have very little concern about a true nationalization in Argentina and the reason is they don’t – I don’t know what they’d use for money to invest in order to do anything different than anybody else does. What you really continue to be concerned about is they have an export price on oil, they depressed the price of natural gas and what happens is they bleed you to death if you know what I’m saying. But, in terms of actually walking in and nationalizing I think that would be – obviously, they could do anything, they’re the government but I don’t think it’s in their best interest to do that, if you just look at it purely from a self interest standpoint. Roger B. Plank: One thing it took me years to figure out that’s so obvious now that I look back is if you think about nationalizing where that’s happened in the past is where a country is exporting and getting all sorts of cash over and above what’s being invested in the country. A country that doesn’t have enough energy in and of itself and doesn’t have the cash to invest, there’s a symbiotic relationship there, they need capital and if they had excess oil and were exporting oil they wouldn’t need it. So, it’s a lot harder to say, “Get lost.” Because, what are they going to do for money.

At this time with no further questions from the audience I’d like to turn the call back over to Mr. Dye for any closing or additional remarks. Robert J. Dye: Thank you very much for listening in and if anybody needs me after the call I’ll be in my office.

That does conclude today’s presentation. Thank you for your participation. You may now disconnect your lines.