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

David Heikkinen- Tudor Pickering Holt Tom Gardner – Simmons & Co. Brian Singer – Goldman Sachs Joseph Allman – JP Morgan Gil Yang – Citigroup Leo Mariani – RBC Capital Markets David Tameron – Wachovia Securities Kevin Smith – Raymond James G. Steven Farris: (Operator Instructions). Welcome to the Apache Corporation third quarter and year-end earnings 2008 conference call. Today’s presentation will be hosted by Mr. Bob Dye, Vice President of Investor Relations. Mr. Dye, please go ahead sir.

Thanks for joining us today for Apache Corporations fourth quarter and year-end 2008 earnings conference call. This morning we reported net income of $706 million or $2.09 per diluted common share for the year ended December 31, 2008. Reported a net loss of $2.9 billion or a negative $8.08 per diluted share for the fourth quarter of 2008, and the fourth quarter loss was a result of a severe drop in oil and gas commodity prices since the middle of 2008 that caused us to record a $3.65 billion non cash after tax reduction in the caring value of oil and gas properties as required by the full cost methodology of accounting. We indicated in a release earlier this year that an impairment was likely given year-end prices. For those of those of you not familiar with full cost accounting rules, we must calculate the 10% discounted after tax value of our proved reserves by country using flat year-end prices and costs for the entire life of the reserve base. If the calculated discounted value is less than our net paring value the excess must be written off. This is generally called a ceiling test write off or impairment. I want to emphasize that the reported impairment is a non-cash charge and in no way impacts our ongoing financial flexibility. Roger Plank will provide more details in his comments in a moment. 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 Web site. In addition any non gap numbers that we discuss such as adjusted earnings, cash flow from operations or costs incurred will be identified as such as the reconciliation located on our Website at www.apachecorp.com. I’ll also mention we routinely put up important information on our Website. On today’s call Steve Farris, our Chairman and CEO and Roger Plank, our President will make prepared remarks prior to taking questions and with that I’ll turn the call over to Steve. G. Steven Farris: Apache accomplished a great deal during the past year and I’d like to share with you some of those highlights. On the expiration side we had a steady stream of major discoveries across our regions, resulted in a 118% reserve replacement from the [rail] bid alone. We delivered progress on our major development projects, scheduled to come on line in the first half of 2009. And we took important steps in advancing Apache’s next generation of project. And going in, in 2009 importantly we managed our cash flow wisely, so we entered 2009 with $4 billion of readily available firepower. Three major one off uncontrollable events occurred during 2008, which really distort our reported results for the year. Production was affected by hurricanes in the Gulf of Mexico, and an explosion on a pipeline, which transports all of our gas production in Australia. As a result, our production declined 5% during the year. And if you exclude these two events production would have grown 2% in 2008. Approximately 25% of both our gross operated oil and gas remain offline in the Gulf region. We’re waiting on pipeline repairs to restore those volumes. We’re hopeful of having all those volumes restored by the second quarter of 2009, but the timing in nearly every instance is out of our control. And the third major one off event which is reflected in our earnings is the collapse in oil and gas prices and a resulting write down which Bob just outlined for you briefly. I do want to emphasize that this is a non-cash item. I’d like to turn to reserves for 2008 before price change we grew our crude reserve base for the 23rd consecutive year. In particular as I said we replaced 118% of our production through the drill bit alone and this is significant when you consider we did not book any substantial reserves from our resource place such as Ootla. So we’re talking about 232 million barrels of oil equivalent of discoveries and extensions in the year and we’re proud of our team for it. Our year-end reserve calculations included a negative reserve revision of 64 million barrels associated with year-end commodity prices, which means we close the year with 2.4 billion barrels oil equivalent of crude reserves. Nearly all of the reserves affected were located in North America, primarily represented long life oil properties in the U.S. and royalty changes and high cost gas, shallow gas in Canada. The negative revisions in North America were partially of set by positive revisions in Egypt, and that’s due to the cost recovery component of our production sharing arrangement that requires more reserves to recover prior spending when commodity prices are lower. For those of you that focus on finding and development cost, I’d like to note that our 2008 results point to a finding and development cost for BOE up over $20 a barrel and we calculated to be $23.43 from additions only. In relation to this I need to point out three major issues. First our F&D capital spending in 2008 on infrastructure was uniquely high. We spent over $700 million on facilities and platforms associated with construction and upgrades. A good portion of this is associated with projects in Australia and Egypt that will begin production in first half of 2009. Second we spent almost $950 million on developing crude undeveloped locations in 2008. And again about a third of this is on Van Gogh, which is our Australian oil development and it will move into the crude developed category in 2009. We really focused on delivering projects over booking new crude undeveloped locations, and as a result you might notice that our crude undeveloped as a percentage of our total decline from 31% to 28%. And thirdly I might point out that funding and development cost is only one side of the coin. Our resource and project profile is very different from most North American large cap independents. The other side of the coin is that our cash quote per barrel is consistently in the upper end of the peer group, which means that barrels are worth paying for. And finally in 2008 we didn’t outspend our cash flow, we didn’t chase costly deals and nor did we enter into expensive leases for large blocks of acreage with short-term expirations. As a result we entered 2009 with nearly $4 billion and a readily available firepower, which consists of over $1.5 billion in cash and short-term securities and $2.3 billion line of credit. We end the year with a 23% debt cap, half to be write down and penned if we excluded the cash we have in our balance sheet. I’d like now to discuss some of our operational highlights in 2008 and really focus on the fourth quarter developments. For the year we drove 1057 net wells, with a 92% success rate. During the fourth quarter we drilled 380 wells with a 93% success rate. On the expiration front we had a number of Apache landmark discoveries during the year, and some of those highlights include the following. In Egypt we had a steady stream of significant discoveries during the year, across basins in place and most notably the following two. [Heget] which is in the Matruh concession and the Northern part of the [Colvec] concession, we found an accumulation of 200 Bcf of gas, which will end up going through train three and four that I’ll talk about here in a minute. And on the southwestern end of the concession we discovered a West Kalabsha C-1X, which is in a Faghur basin during the fourth quarter and it tested nearly 5000 barrels of oil and day and is confirmed a new deep light oil flight. In Australia, the [Hagar] discovery found 150 BCF of gas near Varanus Island, we’re currently in the design phase of its development. In the fourth quarter we had a successful discovery in the [Bam bra nine], near the Varanus Island, and we’re studying ways to bring that back through the island. In the Gulf of Mexico the Geauxpher discovery identified a large accumulation of gas on garden bank 462, our Geauxpher project is expected to commence production in May at a net rate of about $50 million a day. And during the fourth quarter we stepped out with a successful well and garden bank 463 which was an appraisal well, shallow and we took it deeper and we found 150 feet of gas in deeper sand. In terms of our development projects, we delivered progress on the major development projects, which are going to underpin Apache's visible production growth in 2009 and beyond. In Egypt, two additional gas-processing plants are expected to reach full production of 100 million a day, and 5,000 barrels of oil a day in May of 2009. Also in Egypt, we drilled 203 water plugged wells and ended the year with up 76,000 barrels of oil per day, of gross production from water plugged field, which is a 12,000-barrel a day increase from 2007. I might point out that water plug production now underpins 50% of our crude oil production in Egypt and continues to grow. In the Gulf of Mexico, during the fourth quarter, we completed a very successful drilling and recompletion program. It's [nearing] Bank 826. We've increased production from about September of '07, from 700 barrels a day to 6,300 barrels a day by the end of the fourth quarter of 2008. In Canada, we drilled 96 coal bed methane wells during the fourth quarter, leading to a North Grant Land production record for the region, earlier this year. In the North Sea, we completed 11 new development wells in the giant Forties field, including four wells during the fourth quarter. These 11 wells flowed at a combined rate of 18,900 barrels a day of light sweet oil. In Australia, the Van Gogh development remains on schedule, with first production of 20,000 barrels of oil a day, net and is expected to come online in May 2009. Our Pyrenees development, which is operated by BHP, also remains on track and should be on in the first quarter of 2010 with an additional 20,000 barrels a day, net to Apache. And thirdly, we took important steps in shaping our next generation of projects. In Egypt, we made four discoveries in a new area called [Habba] Ridge, which is adjacent to the Asala Ridge waterflood area and East Bahariya concession. These discoveries have the potential to recover 20 to 30 million barrels of oil, through waterflooding. In January of 2009, we secured 154 Bcf, seven-year gas sales contract, which underpins our Reindeer development in Australia. Our Reindeer development will start up in mid-2011 and the contract will net back prices to Apache, three to four times the $2.00 price we've received on average over the past decade. In Canada, we completed seven successful horizontal wells in the Ootla play in 2008, with an additional five wells waiting on completion, and nine wells with surface casing preset. And we're now moving toward a full-scale development plan. I'm going to talk a little bit about our 2009 outlook, and as a result of the accomplishments that we just talked about, we project production growth in 2009, from 6% to 14% for the year. I need to make it clear that we're driving to stay within our cash flow in 2009. If commodity prices continue to fall, we'll likely land in the bottom half of that range. Currently, our 2009 capital spending levels are based on cash flow estimates, using $4.50 for natural gas, and $40 for oil, which translates in a budget of $3.5 billion to $4 billion. We will scale back spending further if commodity price stays at current levels. We're reviewing our capital monthly, if not weekly. We are a flexible and entrepreneurial organization, which enables us to make the best value decisions as market circumstances continue to evolve. Now, I might point out that presently service costs don't make any sense. Oil is below $40 a barrel, but most costs still remain at levels reached when oil was about $100. And I know service costs historically lag commodity prices three to six months, but frankly, we expect significant external cost deflation through 2009, and potentially beyond. Given that backdrop, we're following our directional plans for 2009. All regions have significantly reduced capital budgets to balance the forecasted operating cash flow. In the U.S. Central region, we remain extremely cautious drilling gas wells until net back prices improve in western Oklahoma, and also plan limited activity in the Permian Basin. Fortunately, these areas have pretty decline rates, and we do not have large acreage positions which are facing near term lease expirations. In the Gulf of Mexico, our Hurricane Ike production recoveries and the Geauxpher discovery are both expected online during the second quarter of 2009, which should offset the decline in activity. In Canada, our major focus is to drill 25 wells at Ootla, as well as fund a 30% interest in a 24-inch pipeline that will give Apache 120 million a day of additional take away capacity. In the North Sea, we finished most of the facilities upgrade in 2008, which accounts for nearly all of the budget decrease relative to 2009. And our drilling activity in the Forties will be flat with 2008 levels. In Egypt, we intend to complete funding of our gas plants and conduct a more moderate drilling program. We should show record volume growth in 2009, with the [Ceylon] gas plants ramping up. Gross operated production has steadily ramped up, and over the last week, we averaged 630 million cubic feet of gas and 148,000 barrels of oil per day of gross operated production. In Australia, we will complete funding of Van Gogh and continue funding our Pyrenees and Reindeer projects. The Van Gogh development will not require funding until we determine which market is best suited for the asset. Our Julimar discovery is more likely to participate in an LNG development, rather than supplying the domestic western Australian market. Australia will obviously have record strong volume growth with our Van Gogh development coming online during the second quarter of 2009. I'd like to close with a couple of comments. First is Apache's a 54-year-old company, and we've been through many down cycles. And truthfully, we've never been in better shape to take advantage of opportunities, and that we think will invariably present themselves. We have a portfolio diversity and balance that is a unique strength. We don't depend exclusively on North American, high volatile gas markets for our existence, and our pipeline of visible major projects is spread across our international regions. We enter 2009 with projected production growth, ample liquidity to pursue acquisitions, and historically Apache has been very successful during these periods, and I'm extremely confident that we'll emerge an even stronger company as the cycle ultimately turns. My final comment is – I hope the gentleman is listening in – it's Raymond Plank, who is synonymous with Apache. As many of you might know, Raymond retired on January 15, after being the only Chairman and Founder that we've had. For those of you who don't know him, I think you would agree he's one of a kind. He started Apache in 1954 with $250,000 from family and friends, and depending on the stock price today, we've grown to a $25 billion organization. And when you consider the adjusted price of those shares, in 1954, were $0.04, it's been a hell of a ride. So, Raymond, on behalf of our employees certainly, and I think all of them I know in this room feel that way, and all of them around the globe and our shareholders, we're very indebted to you. And thank you for your wisdom, your warmth, your friendship and support, over many, many years. And we wish you all the best. Roger. Roger B. Plank: Okay, thanks, Steve, and good afternoon, everyone. From a financial standpoint, Apache finished 2008 with a very tough quarter. Her write-down nearly eliminated what otherwise would have been outstanding earnings in a year that would have been our best ever. It’s little consolation that even with the write-down Apache's $706 million of income still stacked up as the sixth highest in our 54 years. Clearly, 2008 will go down as the year of extremes. From an earnings perspective, we had our best quarter ever and our worst quarter ever, all in the same year. Bob commented on the magnitude of the write-down and how it's calculated, and I just wanted to touch on a couple of things before moving on. You may be aware that in December, the SEC issued new rules on how to calculate the ceiling test. The old rule requires that in comparing the discounted present worth of properties against their historical costs, we must use prices, as of a single day and time and then hold that price flat, forever. The new rule updates that approach, allowing companies to use the prior 12-month average price, the theory being that this is a better price indicator than a single day's price. Three points – under the new rule, we'd have avoided a write-down all together, at least for now, because the previous months' highs, in terms of prices, would have muted the impact of recently lower prices in determining an average. However, the revised rule does not take effect until the end of this year. Secondly, we are required to use cost levels and Bob went into this, or mentioned this, touched on this, cost levels as of year end for the entire life of the properties, and clearly this doesn’t make any sense as estimating economic value of reserves at lower commodity prices historically result in lower service cost. It’s just that there’s a lag. So the calculation misses this. You just can’t assume that $40 per barrel oil revenue against cost levels generated in the $100 plus per barrel price environment and expect to have a fully valid answer from an economic perspective. And then the third thing and more importantly, this is a 30-year-old rule that’s clearly outmoded or it wouldn’t be being updated today. Obviously a 12-month historic average price is a better answer but it too has its limitations and should not be confused as a statement about market value. The point is, the methodology for calculating the ceiling has little to do with how properties are valued in the real world. It also has nothing to do with the underlying earnings and cash flow comparability of a company and capability of a company. That being said, if the calculation, it should not be ignored but it’s probably best set aside in order to make an apples-to-apples comparison of results, which is what I now intend to do in comparing the fourth quarter to the third. Prices created from the third quarter to the fourth, dropping our oil and gas realizations 50% and 36% respectively, this caused revenues to decline over 40% sequentially at just under $2 billion in the fourth quarter. Excluding the write-down fourth quarter earnings totaled $701 million or $2.08 a share. This includes a $272 million or $0.81 a share foreign exchange benefit in deferred taxes following the strengthening of the U.S. dollar and a $152 million or $0.45 per share benefit largely from a favorable resolution of tax audits. Cash from operations decreased 49% to $1.1 billion compared to third quarter. That’s a substantial decline but it’s not unexpected given that the world economy is currently in shambles. While a lot of products have no market at all today, we are very fortunate to be in the oil and gas business where all our products sell everyday. As Steve likes to say, “We don’t sell widgets.” Costs remain an issue for both Apache and the industry as a whole, as they have not come down nearly as quickly as prices. Listing cost for BOE rose to $10.91 from $10.39 last quarter, a vestige of yesterday's rising commodity price environment. The quarter also included several items outside of our base running rate, most significantly hurricane repair costs related to Ike. Our 2009 goal is to reduce listing costs per unit by 10% as our volumes rise and lagging cost declines catch up to the reality of lower prices. Recurring whole cost DD&A, and this is pre write-down, increased 10% sequentially to $13.09 per BOE. Parenthetically I'd note that each dollar of write-down is a dollar we don’t have to amortize in the future. So between that and drilling costs, which are starting to moderate, our whole cost DD&A rate should drop below $12 a barrel equivalent. G&A costs increased to $1.47 per BOE from $1.23; however, we should be between those rates as we go forward. Severance and other taxes of $2.92 per BOE, selling half on lower oil and gas prices; this could fall in half again depending on whether today’s lower prices hold. Finance expense increased $0.32 to $1.03 per BOE with the additional $800 million of 6.5% notes issued in the fourth quarter as credit markets tightened. We also completed a project financing for the Van Gogh and Pyrenees projects on which we drew $100 million in December. This increased our cash on hand enabling us to end the year with just under $2 billion of cash and Treasuries. I would caution, however, that the first quarter is expected to see a draw down in that amount for costs that carried over year end, including $125 million in Egyptian cash calls, an estimated $135 million to the U.K. for PRT tax and we also plan to retire $100 million of Australian notes that mature this quarter. Turning to income taxes, our fourth quarter effective tax rate was 40% but if you remove the noise associated with adjusted earnings, our effective tax rate would have been 36%. Steve earlier underscored many of the highlights achieved during 2008. I would add that we have a saying at Apache that “what we won’t do, is as important as what we will do.” For the longest time, I didn’t fully appreciate what that meant but can size it up like this. During the frothy upswing, Apache did not outspend cash flow, choosing instead to reduce our debt to cap and to build a significant cash hoard. We did not submit to the strategy du jour of buying in shares at new highs or jacking up dividends to unsustainable levels and we did not lower financial flexibility on deals at the peak of the cycle. We have been on the acquisition sidelines for two years. We looked but didn’t buy and as a result, we have significant firepower intact when it really counts. Would we have done some things differently had we known how rapidly prices would fall? Absolutely, but by taking a long term approach and staying our own course, we find ourselves in a very competitive position with production on the rise, access to credit at favorable rates and a meaningful amount of opportunity money with which to address today’s not insignificant challenges and opportunities. With that, we would be happy to answer any questions.

(Operator instructions) Your first question will go to David Heikkinen- Tudor Pickering Holt. David Heikkinen – Tudor Pickering Holt: I just had a quick question thinking about your Gulf of Mexico volumes and the recovery and then the additional volumes coming in from Geauxpher. What are the major systems that we should watch or is there some way we can get an idea of ratios if that comes back this year? G. Steven Farris: Well, at least from my projection standpoint, we really should be fully operational on our shut in production about the middle of the second quarter, I mean, if you look at our timing. With respect to Geauxpher, we expect to have that on in May. That will be just an event, if you know what I mean. We’ll go from zero to hopefully 50 million net to us a day. David Heikkinen – Tudor Pickering Holt: And given that you’ve been in recovery operations, normal declines, I mean you don’t get back to the pre-storm volumes, how do you think about what declines you would have as you have been trying to recover or do you have any areas where you think you've re-pressured reservoirs and you will actually get some incremental production? G. Steven Farris: You know, it obviously declines – I don’t have those numbers in front of me. I know if we, from a 2009 plan standpoint, if we get the recovery that we’re projecting we lost a little bit obviously. We wrote off a few reserves just because of the hurricane at the end of the year, but with the 50 million a day coming in from Geauxpher we should be slightly ahead to flat in the Gulf of Mexico this year. David Heikkinen – Tudor Pickering Holt: And then in Egypt, as commodity prices, as oil prices have come down, you get the splits between cost barrels and your profit barrels that impact your overall volumes. How do we think about the variability of production that’s tied to the change in commodity price? G. Steven Farris: Well, frankly, I go by our gross operated production and if you look at our gross operated production, we have been steadily increasing throughout the year and we should, when we get these two plants on, we should be at – started out about $520 million a day at the beginning of 2007. By the first – end of the – May of second quarter, we'll be at about $850 million a day of gas and about 165,000 barrels of liquid, because you really have a hard time looking at net-net numbers in terms of how you book the cost recovery component. It's just – know this, when prices go down we're going to book more per dozen. David Heikkinen- Tudor Pickering Holt: Right. Yes, you get more production as these prices have come down, and they steadily have come down so you'll have some boost to '09 that hopefully reverses itself as oil prices come back. But I was trying to think through that logic. I understand the gross is growing but you also will get a net growth as well in addition to that. G. Steven Farris: That's correct. Roger B. Plank: But there's no simple formula, we've tried to simplify it and you've really just got to run it through the model and based on whatever the price is, but you got the direction right.

David, you also have about 12 different concessions that all have their own particular cost tool. So it's very difficult, as we've spoken before, to model that because you'd have to have a model on every one. And you'd have to know how much spending we had made in every one, so. David Heikkinen- Tudor Pickering Holt: Yes, I won't be able to get that; I was trying to an order of magnitude. And I think we've talked about it before, but it's net positive versus just the overall projects that you have coming in as we lower our oil prices is it.

Your next question comes from Tom Gardner – Simmons & Co. Tom Gardner – Simmons & Co.: I just wanted to get an update on the Gas Plus and the Oil Plus programs in Argentina. G. Steven Farris: Yes, we are actually, and I think I said this on the last call, we are actually drilling wells at EFO, which is one of those projects. And we are actually restricting capital in Argentina right now, but the one area that we're not restricting is our EFO development, because we're hopeful to be able to put that gas into the market. I really can't comment on the Oil Plus because we have one project that we're doing. It's a horizontal project down there, that we just started drilling. Our first well made over 500 barrels a day, but that's early in the cycle. Tom Gardner – Simmons & Co.: And Steven, I wanted to get an update on your thoughts on the optimum timing of an acquisition, and do you see the bid-ask spreads closing? G. Steven Farris: I think, and this is my Steve Farris add on, but I think you're going – everybody is going to be very discouraged when they look at first quarter pricing. What we have the fourth quarter, even though we took a feeling-test kit, our average price was much higher than the average price is going to be in the fourth quarter. And that's not just for us, that's going to be from the Exxons to the little guys. And I think when we get first quarter realizations of what our cash flow; all of our cash flows are going to be. There's going to be a real convergence of the selling price and the buying price of assets. And I -– so we're, truthfully, we're just kind of settling our peak right now until after the first quarter. Tom Gardner – Simmons & Co.: I wanted to get your view on the oil markets. You may have been one of the few that really saw the weak environment coming to any degree. So, going forward what do you think? When would we see a recovery? G. Steven Farris: Well, and I really mean this, we do look at our business long term. So in terms of, is it going to be six months? We've got an awful lot of pain in the economy and I think you could linger it where we are for some time. Having said that, if you also think that we're still producing, or consuming, as a world 83 million barrels of oil a day and you think of how much capital is going to come out of this business. I don't know if it's two years from now or three years from now but, regrettably, I think we're going to see the same thing that we saw at $140 oil. I mean, I really do. I don't think you can stop that 83 million barrels a day on a dime. Tom Gardner – Simmons & Co.: Yes. Your thoughts on LNG, are prices likely to stay low enough domestically to keep it in Asia and Europe to a large degree? G. Steven Farris: I think the United States is facing some LNG imports in 2010. If you think about some of the very big guys in the world that have LNG coming on during that timeframe, I think it's possible that you could see bigger quantities of LNG starting to test these markets in the U.S. Tom Gardner – Simmons & Co.: Does that portend for a gas price recovery in your view domestically in 2010? G. Steven Farris: I think we're – my honest opinion and it is I think we better run to get our cost down on the gas side. I think we – people don't recognize that we've gone from a nine-year reserve life to a 100-year reserve life. And I think that's going to be indicative of prices going forward. I think, in this country, I think the guy that wins is the guy that can do it the cheapest and do it the most efficiently.

Your next question comes from Brian Singer – Goldman Sachs Brian Singer – Goldman Sachs: Two questions, first question on Julimar, you mentioned that you continue to expect that it will be associating more with an LNG project. Can you provide any of the latest color in terms of how you're thinking about timing and cost? G. Steven Farris: Well, there's two, as you know Brian, I mean there are two competing LNG projects that are very near to us over there. One is a major oil company and the other one is a major LNG player but it's smaller. And, frankly, we are discussing those options with both of them. I would expect some time in the – actually I'm going to give myself because Reindeer I said we were going to have that done for months, so I'm going to be careful. I would expect something to happen on that during 2009, in terms of some kind of commitments of where we would go with that gas. There are some differences, which I'd just as soon not go into because it's there are some differences in the structure of those two opportunities. And also of the timing of which they are going to be built or were built, which has an impact on cost. Do you understand what I'm saying? Because costs are going to come, you know, a major supplier that built our plants in Egypt, we have talked to him about building our third train now. Yes, it's our third new train, our fifth train. And they have one project around the world that they've got in front of them now versus where they were six, eight months ago. So, all of those costs, fuel costs etc. are going to be significantly lower than they were during the boom. And I think that's going to have some impact on the way we look at Julimar and where we go with it. Brian Singer – Goldman Sachs: And secondly, in Egypt and Argentina what are seeing in terms of gas demand trends given the economic climate and maybe some comments on gas prices on the margin? G. Steven Farris: Well, it's interesting because I – if you probably are going to look at the first quarter of 2009, with either a gas price in Egypt that is equal to or close to what we're getting in the United States. And that's not, regrettably, that's not because one of them is going up and the other one is staying there. It's because one of them is coming down. I don't recall what our average price was in the fourth quarter in Egypt on gas. Roger B. Plank: $4.13. G. Steven Farris: $4.13? Now, when we get new volumes on that's going to start drifting down just because it's a lower price. But we should net back to us probably in the $3.50 range to Apache. And given gas today is a little over $4.00 in the United States, and that's at NYMEX, I would suspect that our gas price in Egypt in the first quarter, with an additional $100 million today coming on, is going to be higher. Roger B. Plank: And you might have gathered from Steve comment about the fifth train that there's still very strong demand for additional [inaudible]. G. Steven Farris: Very much so. And the reason is, regardless of the price of crude oil in Egypt, they just don't have enough of it. And so what they're trying to do is whatever dollars that they can get, because basically they have to import products, so whatever price they can get for their crude oil is hard dollars and their gas is used internally. And it's still a very strong market for gas. In Argentina, and again, this is bittersweet, but regrettably, our Argentine price doesn't look so bad anymore. We’re still selling our Dow contract; actually starting in 2009 that Dow contract will be $3.50. Now that's not much gas, but in the fourth quarter of '08 we averaged $1.85. And I would suspect probably Argentine gas prices are going to continue to go up on an average. Certainly we're not going to threaten the $9.00 we've seen in the United States, but I don't think the United States is going to threaten $9.00.

Your next question comes from Joe Allman – JP Morgan. Joseph Allman – JP Morgan: Yes, thank you. Could you comment on your outlook for production out of the Ootla shale? What the production is now? What do you think about year-end '09, year later? Just give us a sense of the growth there? G. Steven Farris: Well, it depends on how we develop that right now. Right now we're drilling wells and presetting casing, and we're going to back in the fall and complete those wells. We're doing about 20 million a day right now of gas out of the wells that we've got on. Interestingly, the last well, actually EnCana drilled, but we have 50% in also, four months later is still making 5 million a day. So it's holding up very well. That's the only well that we've actually got 10 fracs on. So from a reservoir standpoint we're very encouraged about what we see. In terms of timing, we probably start ramping up production not until about the end of 2009. So where you're really going to start seeing some – depending on what happens to prices – you're probably going to see the first meaningful gas coming out of Ootla area in 2010. Joseph Allman – JP Morgan: And then in terms of acquisition, you suggested that you're in the market for making acquisitions. What are you looking for in particular and don't you have enough to keep yourselves busy now and to invest all the capital that you've got available to you at this point? G. Steven Farris: Certainly we have, and truthfully we have more opportunities than we have cash right now. And we're being very selective about how we spend those dollars. We are a growth company. Apache, in 54 years, has been very acquisitive. We do not look for acquisitions that just have production. We look for acquisitions that add acreage and have upsides and that can be a long-term part of our portfolio a la Egypt. Now we bought Repsol out of Egypt in 2001 and that was the other half of the greater call to area. And we've got 42 rigs still running in Egypt. That's going to go down, but that was a huge, huge win for us. You would hardly ever see us make an acquisition just for the production. So what we'd like to be able to do is put ourselves in a position to add some growth potential for the next several years out of an acquisition we could make when prices are relatively low, rather than buy at the high end of the market. Same reason you buy a stock when it's down is you expect it to go up. We'd much rather invest dollars in a much saner environment than we would at higher prices. Joseph Allman – JP Morgan: Okay, that's helpful. Roger B. Plank: Somebody earlier asked about the right time for acquisitions and when do things pick up? And the real answer to that is that timing's coming our way. But the real answer is in Steve's last answer to this question, and that is when we see something to which we can add value that brings us a lot of opportunities, that's in a market where you aren't stretching every assumption in order to get a deal done, then that's when you add. Rather than to try to pick the exact right time with respect to pricing because that's pretty difficult to do, as we all know. Joseph Allman – JP Morgan: And I suppose you weigh that against things like buying back stock or paying off debt and other opportunities, as well. Is that correct? Roger B. Plank: Well, we certainly do against paying down debt. Occasionally we'll weigh it against buying back stock, but I can tell you along the lines of Steve's comments about we are a growth company for 54 years. This kind of environment is the kind of environment where we vastly prefer to look for opportunities that build a better business. Joseph Allman – JP Morgan: Okay. And then, Steve, you made a comment about how – you suggested that the funding costs were higher because of the facilities and construction and other costs that you incurred in 2008. Are there others – are there costs like that in 2009 that might make '09 funding costs higher than the other ones would be? G. Steven Farris: The only place that we have significant infrastructure left, frankly, because most of it we probably see a little of it in the first quarter out of the gas plants in Egypt and a little first quarter Van Gogh. But past that, certainly Reindeer won't start up until later in 2009 – the actual construction and spending, because we don't come on until 2011. So we're pretty well funded with what we see right now. Now and again, most things there's always two sides – we'd love to have something that we could start spending money on. But right now we're pretty well funded, those projects that will come online in 2009. Joseph Allman – JP Morgan: Great, and then just two quick ones. How about pv10 for at the end of '08? What was pv10? G. Steven Farris: I'm looking around the room. Roger B. Plank: Joe, I'll get that one for you offline. We don't have it right in front of us. We're working on our K so... Joseph Allman – JP Morgan: Great, thanks. And then lastly, revisions, of the revisions, how much were approved developed and how much were PUDs? G. Steven Farris: We'll have to get that for you offline. Roger B. Plank: I'll get one for you, too.

Your next question is from Gil Yang – Citigroup. Gil Yang – Citigroup: Hi. Going back to Ootla for a second, could you, now that you're in full development mode does that mean that you're pretty comfortable with what the wells are doing in terms of what your program is in terms of fracs, completions and can you outline what you think the ITs and the URs are going to be at that stabilized level? G. Steven Farris: Well, we project that the latest well that we drilled is probably going to 7.5 v's. And that's with ten fracs. I will tell you, we've got five wells that we've actually had some production on. But we're fairly confident. At least our engineers and our petrophysicists are pretty confident that with a larger number of fracs we could recover 10 Bcf per well. In terms of our – from a reservoir standpoint now, we've only been in two areas, and we've got 400,000 acres. So we're extrapolating a long – it's more than an Oklahoma step-out. But certainly all of the wells that have been drilled so far have been very similar. This program that we're doing this winter and throughout the year will be very important to us in terms of drainage, etc. But at some level this project is going to go forward. And the question is how big is big? Certainly we're confident enough to join in putting a 24-inch pipeline that's going to take 700 million a day out of there of which we’ll have 30% of. So we’re going to increase our available capacity significantly over the next year. Gil Yang – Citigroup: What is the cost? What do you think the cost is going to level out at? G. Steven Farris: Level at I don’t know yet honestly. You’re looking at every service that we talk to comes down daily frankly and it will continue to come down until it reaches a point of which it's commensurate with a return on the prices that you’re getting for the commodity. It never fails. Gil Yang – Citigroup: All right, well, maybe I used the wrong term but in terms of your technological improvements where do you think the wells are going to cost at today’s cost? G. Steven Farris: At today’s cost about $7 million. Gil Yang – Citigroup: Seven million. And you cited I think to Joe's question about Ootla, you said that it was one well and so increasing to 5 million a day what was his IT and how long has it been and has it surfaced and is the infrastructure constrained at all? G. Steven Farris: It’s not constrained it came on actually instantaneous rate or at the 12 hour rate. It came on about 12 million a day originally and declined obviously significantly early. But it’s relatively flat for a shale well and at 5 million a day after four months is a very good rate. Gil Yang – Citigroup: Okay, and is it your view that Ootla at today’s prices would be economic? G. Steven Farris: On a well by well basis it would be economic; on an infrastructure basis probably not. But you’re going to have to spend some of that money in order to get there. You understand what I’m saying. Gil Yang – Citigroup: Absolutely. And then just a question you mentioned in the royalty in the revisions downward that royalties played a role in that could you – I thought the royalty regime sort of kicked into place at the end of 2007 so wouldn’t that have affected 2007 reserves?

No this was the first year – and it was Alberta government royalties that have the impact and were significant. Gil Yang – Citigroup: So it didn’t affect your reserves in '07 only the reserves in '08. G. Steven Farris: That’s correct. Roger B. Plank: And that was about half of the Canadian revision.

Maybe it might have been that it was announced and it didn’t come into effect until 2008. Gil Yang – Citigroup: Right, so you didn’t have to calculate ’07 reserves based on that. Roger B. Plank: Right, because it wasn’t implemented until ’08.

Your next question comes from Leo Mariani – RBC. Leo Mariani – RBC Capital Markets: Question on CapEx for 2009 you guys talked about $3.5 billion to $4 billion. I know that’s a moving target. Could you guys put any numbers around kind of where the money may get spent if it’s possible to say 20% in Australia, 10% in North Sea or any sort of [big] islands like that? G. Steven Farris: I don’t have it in front of me. Let me tell you where – we probably spent $800 million in Central region and we’re probably going to spend $400 million in the Central region. And these are just directionally if you understand what I’m saying. We spent probably $1.5 billion in the Gulf Coast and we’ll probably spend something like $1 billion in Canada, most of which is our Ootla we’re probably down $350 million there. I think we’re going to spend about $500 million. In Egypt we’re trying to be – now we had the gas plants in ’08 so you’re not looking at – it's not having as much effect on the drilling, but Egypt we’re going to be about $800 million. And the North Sea about $300 million and the rest of it is change if you understand what I’m saying. Leo Mariani – RBC Capital Markets: Okay, you guys talked about your Gulf of Mexico shut -ns being roughly 25% of your volume. Can you kind of quantify what that number is going to be? G. Steven Farris: You mean the order – actual numbers? Leo Mariani – RBC Capital Markets: Yes. G. Steven Farris: No I don’t have those numbers in front of me. I’m sure Bob could get them for you. I just looked at a curve but I don’t want to – I’d rather not say. You just need to get that number offline. I mean we’ve got it I just can’t remember that particular number and I don’t want to give you a ballpark. Leo Mariani – RBC Capital Markets: Sure okay. I think you guys were drilling some wells in the Gippsland base in Australia kind of late last year and wanted to see if you had any results out in that part. I think there was a couple big prospects you guys were looking at. G. Steven Farris: We had a very good program that turned up with some uneconomic discoveries, frankly. We drilled – the [Dore] well had a nice sand with hydrocarbons in it. It turned into being gas rather than oil which where it was in the world is not going to be economic. And the other two turned out to be – had sand in them but were actually didn’t have a charge so we drilled three dry holes there. And that doesn’t condemn the Gippsland frankly I just – the ship's gone and we’re going to study it and probably go back to drilling in 2010. Leo Mariani – RBC Capital Markets: Okay, anything else on the drawing board in the exploration side for Australia ’09 or are you guys kind of taking a break over there? G. Steven Farris: No. We've got a well up in Browse that we’re getting ready to drill. We get our ship back. We’re getting ready to drill in oil prospect up in Browse. We’ve got a project that’s offsetting our Van Gogh Pyrenees development. That’s a smaller oil play but it could be a very good add on. We’ve got a couple of gas wells that we’re going to drill in the Carnarvon basin down toward Varanus Island. We’ll probably drill because of our discussion on where to go with the gas we’ll probably drill a couple of appraisal well at our 356 our Julimar block that are going to be important wells for – to establish crude reserves if you understand what I’m saying. So we got a program; it’s more modest than it was in 2008 for sure.

We go next to David Tameron with Wachovia. David Tameron – Wachovia Securities: Good afternoon. Most of the questions have been answered just one follow-up, and you briefly mentioned I was looking at the regional F&Ds in the Gulf Coast. Can you talk X3 visions? Can you talk about – I think you mentioned there was some deep water wells included in that number. Can you talk about what exactly went into that CapEx number? G. Steven Farris: Yes. There was a significant amount of infrastructure not all associated with the hurricane. The other thing I would say is is that we have timing difference in the Gulf of Mexico and that is the difference between when you book the reserves and when you drill the wells. We drilled a very expensive well out south 10-308 that was an exploration well to a deeper target that turned out to be a dry hole. The biggest is timing differences and that's just year-over-year, if you understand what I’m saying and the Gulf of Mexico is a high cost area. I mean we saw historic high cost in the Gulf. That’s not indicative the way the program should go, but it certainly was that way in 2008 for all kinds of reasons, one of which is the hurricanes. David Tameron – Wachovia Securities: Okay, and when I look at grouping of your U.S. production how much of that – what sense [inaudible] versus Gulf Coast, like how much onshore is included in that Gulf coast number? G. Steven Farris: About $100 million a day Gross.

Your next question is from Kevin Smith – Raymond James. Kevin Smith – Raymond James: Two questions, is there price that you kind of cut back drilling in the Ootla in ’09? G. Steven Farris: We – I guess there is a price. Right now we are for a lot of reasons. One is we really want to do a pad drilling and experiment with fracs etc. in a orderly fashion. So we are going to drill those wells in 2009. That is going to be part of our program and we’re going to complete them and we’re gong to put them on. And at a if oil – I mean gas prices to decline certainly we’re spending money for the future. We’re not spending money for now when we do that. And we fully recognize that. Kevin Smith – Raymond James: Makes sense. And the second question can you give me a feel for what demand’s like in Argentina or is gas demand – are they still importing large amounts or has some of that maybe kind of fallen off. G. Steven Farris: Well we’ll see as we go into their winter but in terms of the actual need for natural gas in Argentina that hasn’t let up at all. They are behind the eight ball with respect to gas demand versus supply.

And with that ladies and gentleman we have no further questions on our roster. Therefore Mr. Dye I’ll turn the conference back over to you for any closing remarks.

Thanks for joining us. If anyone has any questions feel free to call us after the call, and thank you very much.

And again ladies and gentleman this does conclude the Apache Corporation fourth quarter and year end earnings 2008 conference call. We do appreciate your participation and you may disconnect at this time.