Tom Chambers – Vice President of Corporate Planning and Investor Relations G. Steven Farris – Chairman, Chief Executive Officer Roger B. Plank – President and Chief Financial Officer John A. Crum – Co-Chief Operating Officer and President of North America Rodney J. Eichler – Co-Chief Operating Officer and President of International

Brian Singer – Goldman Sachs Doug Leggate – Howard Weil Inc. David Heikkinen – Tudor Pickering & Co Leo Mariani – RBC Capital Markets Joseph Allman – JP Morgan David Tameron –Wachovia Thomas Gardner – Simmons & Company International

Welcome to the Apache Corporation second quarter 2009 earnings conference call. Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations.

This morning we reported second quarter net income of $443 million or a $1.31 per diluted share, and cash flow of $1.26 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 open up the session, followed by Rod Eichler our Co-Chief Operating Officer and President of International, John Crum our Co-Chief Operating Officer and President of North America, and Roger B. Plan our President. 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 can be found on our website. Any non-GAAP numbers that we discuss, such as adjusted earnings, cash flow from operations, or cost incurred will be identified as such with the reconciliation located on our website at www.apachecorp.com. With that, I'll turn the call over to Steve. G. Steven Farris: I'd like to give you some highlights of our performance during the quarter and then I'd like to comment a little bit on the outlook for the rest of the year. Apache's performance during the quarter reflects the clear benefits of our geologic and geographical diversity, as well as our balanced product mix. Apache's production grew at 7.1% over the previous quarter and up 6.5% from the second quarter of 2008. And this strong growth performance was broad-based across our portfolio. On the exploration side, we had yet another outstanding quarter. Our continued exploration success in Egypt brings our discoveries tested to date bear at about 70 million barrels of oil equivalent on a crude [plus] probable basis. I might point out the majority of that is oil. And you'll hear shortly from John Crumb, we also had important exploration successes during the quarter in the Gulf of Mexico and in the Ootla resource play in Canada. On the development front, we achieved our objectives during the quarter bringing the Geauxpher deepwater project on stream in the Gulf of Mexico, and completing the ramp of our latest new gas facilities in Egypt. In addition our North Sea team tested a new development well at 10,500 barrels a day in the 40s field. This is pretty amazing when you consider that 40s was producing approximately 40,000 barrels per day when we acquired it in 2003. We'll continue to work through our expanding development drilling inventory there, which at the moment, consists of 77 unique targets. I will note quickly that we're pleased with our ability to deliver reductions in our operating cost during the quarter. I certainly wouldn't say we're satisfied on that front so far. We continue to push the service companies and push ourselves for even greater efficiencies. Turing to the outlook, as you can see from our performance during the quarter, our portfolio provides us with running room for strong production growth, and we continue to believe we'll be between 6% and 14% production growth for the year. Van Gogh project delay due to the FPSO's company yard incident that pushed us to the bottom end of that range. But with our region's outstanding performance thus far this year, our growth will solely be determined by how much capital we make available through our regions in the rest of the year. We continue to add to our organic resource depth for the long-term. Every additional well we drill at Ootla adds to our conviction that we hold one of the largest and highest quality plays in North America. We've received numerous inquires about the Granite Wash, which is in the panhandle of Texas and Oklahoma. And John's going to comment about our position there in a little more detail, but generally let me say we believe we hold one of the largest acreage positions in that play, if not the largest. We hold and continue to build other areas that, based on our experience thus far, could be second to none in quality and resource scale. Frankly, we prefer to focus on delivering operational results instead of extrapolating hypothetical numbers about early stage plays, which probably doesn't do us any good in the market front. Importantly, our natural gas resource plays are either held by production or through long leases. So we're not under any pressure to drill hundreds of wells at current depressed prices. We have the choice instead of maximizing value for our shareholders by focusing on near tier development capital on other growth opportunities while making sure, of course, that we capture the highest quality gas opportunities for the longer term. Our debt to balance growth opportunities and financial strength means that we can also participate in the asset market, but only when it creates the most value for Apache. During the second quarter, we closed the acquisition of our Marathon Permian properties, and we will continue to evaluate opportunities by applying our core values of discipline, patience in a contrarian's spirit that has served us well in increasing the equity value of Apache from a little over $4 billion ten years ago to $26 billion today. So now I'd like to turn it over to Rod and John and Roger. Rodney J. Eichler : I would now like to provide a quick overview of our main developments in our international regions. During the second quarter of production from Apache's International Operations with 302,700 barrels of oil equivalent per day, a 9.5% increase over first quarter. The production increase can be attributed to drilling successes in Egypt and the North Sea, as well as completion of facility repairs at Australia's Marinas Island, and successful commissioning of new gas plants in Egypt. In Egypt, net production was 158,100 barrels of oil equivalent per day, a 15.9% increase over first quarter. The region achieved new daily production records for gross oil and condensate at 163,000 barrels per day, and gross gas at 754 million per day. On the exploration side, we completed drilling and/or testing operations on five new wildcat wells resulting in two new field discoveries during the second quarter. Two potential discoveries at Cordova and Chelsea will be tested within the next few weeks, and three Jurassic wildcat wells are presently drilling. Apache has a 100% contractor working interest in all of these wells. Some brief highlights on the two discoveries and significant appraisal and development wells in the greater call to concessionary are as follows. The [Nies] 1X wildcat and the call to offset concession log 82 feet of oil pay in the Jurassic Safa sand section. The Safa tested at 1,460 barrels of oil per day. A plan of development has been submitted to the government and production expected to commence the fourth quarter. The Falcon-1X wildcat in the Matruh Concession logged 38 net feet of pay in the Jurassic Safa sand, 47 feet in the AEB6 sands, and 44 feet in the AEB3D sands. The [S] rates were 11 million a day in the Safa, 35 million a day and 2,000 barrels of condensate per day in the AEB6 and 4,400 barrels of well per day in AEB3D. The well will be initially completed in the AED3D oil zone and first production from the well should commence in the early third quarter. The Hydra-5X appraisal well, two kilometers south of updip of the 2008 Hydra-1X Discovery well the in the Shushan Concession logs 50 feet of Jurassic upper Safa sand pay and test did 3,700 barrels of oil per day and 21 million cubic feet of gas per day. A new field pay zone. The well also has 40 feet of AEB6 pay a hole. The field will be developed upon completion of a gas sales agreement with the Egyptian General Petroleum Corporation. The Phiops-5X was drilled to appraise and develop the AEB oil reserves found in the Phiops-1X discovery well that was made in the first quarter. The Phiops-5X logged 242 feet of net pay in the AEB and tested 8,300 barrels of oil per day from the AEB3E and AEB3Z reservoirs. Three additional Phiops field wells are in the process of drilling or testing. Amendments to our Sema Salon and West Gaza exploration sessions for an additional three years, to 2013 were approved by Parliament in June. These concessions encompass 3.8 million gross acres which Apache operates with a 50% contractor interest. Apache's first well in the West Gaza concession should split in October. On the development side in Egypt 72 hour performance tasks were successfully completed at the new Salon gas plants three and four, and the northern pipeline compression project became fully operational. Gross call to gas production averaged 668 million a day during June and 715 million a day in July. Upon completion of commissioning related adjustments in early August, we expect gross gas production from the Caldara area concessions to average 730 million a day for the balance of the year, a 25% increase from the $540 million a day at the end of the first quarter. Turning to Australia, net production was 37,300 barrels of oil equivalent a day, an18.5% increase over first quarter, gas and oil production increased by 13% and 34% respectively. The Varanus Island repair project was essentially completed by the end of the quarter when net oil and gas production exceeded pre-incident levels of 10,000 barrels of oil per day and 195 million cubic feet of gas per day. Current net production rates exceed 200 million a day. In our Van Gogh oil project, the Van Gogh 6H Development well and Van Gogh 12 water injector were completed. Repair work for the FPSO as a result of April's control room fire are well underway and we estimate first production at Van Gogh around year-end. On the exploration side in Australia, we drilled two new wells in the multi-Tcf Julimar-Brunello complex. [Valnase-1], a gas exploration well, was drilled to investigate two previously untested channel fans up among the root formation. The well encountered 6.7 meters of net gas pay in the B10 sand and 19.5 meters of net oil pay in the B20 sand. [Valnase-2], a gas appraisal well, found 15 meters of net gas pay in the B10 sand and 2 meters of oil pay and an oil water contact in the B20 sand. Now this oil pay is in communication with the oil pay in the B20 and [Valnase-1], thus confirming the 43 meter oil column with an additional 60 meters of probable oil column updip of [Valnase-1]. We are presently evaluating all options to commercialize this large gas resource and our process will be complete by year-end. In the North Sea, net production averaged 60,000 water barrels of oil equivalent a day, a decrease of 1% from first quarter, due to a planned 16-day build delta platform turnaround that commenced in May. Delta platform makes 16,000 barrels of oil per day. Excluding the Delta turnaround, production would have been up a net 1,226 barrels of oil per day quarter-on-quarter. Production efficiency of the 40s field was 93% during the quarter, excluding the turnaround downtime a 37% field-wide gain since our acquisition of the field in 2003. On the drilling side, we completed four successful oil development wells during the quarter. These wells contributed 2,740 barrels of oil per day for the quarter and 6,460 barrels of oil per day in June. As Steve mentioned, of note is the 40s Charlie 63 well which encountered 34 meters of pay and was brought on production in mid-June at 10,500 barrels of oil per day. This initial rate is the fields highest since 1994. We are currently drilling one development well in 40s Alpha 42 and to putting an additional industrial oil development to 40s Charlie 54 which will be on production in August. At the close of the quarter, 40s Field was producing at sustained rates in excess of 70,000 barrels a day, the field's highest stable production output since February 2006. In Argentina, net production was 47,100 barrels of oil equivalent per day, down less than 1% from first quarter. For the first half, 21 wells were drilled with a success rate of 95%. The Neuquen Province development drilling continued in Guanaco and Ranquil gas field areas. Both fields are approved to receive gas plus price incentives by the federal government. The Ranquil Co 1039 encountered 110 meters of pay in three zones in the objective [inaudible] formation. Completion operations are currently underway. In the Guanaco field, five wells have been drilled to date in 2009, four wells are on production, and the fifth is currently being completed. Four additional wells are planned in Guanaco and Ranquil Co in the second half. In Tierra del Fuego's Austral basin, the successful Springhill oil well has completed for 900 barrels a day in the Seccion Banos field. The well helped define the field's secondary recovery potential for a waterflood that will be commenced by year-end. I'd now like to turn over the presentation to John Crum who will discuss activities in our North America operations. John A. Crum : Starting with our central region, our central region produced 87,700 barrels of equivalent per day in the second quarter, down 2.2% from the first quarter due primarily to natural well declines with little new drilling activity. The region rig activity was deliberately slowed in the first two quarters of 2009 to wait until drilling and well service costs dropped to a level more consistent with lower oil and gas prices. With reduced activity levels, the region concentrated on building their inventory of opportunities and proceeded with lower cost projects targeting primarily oil such as waterflood expansions. In spite of the production drop, the regions cost reduction efforts resulted in LOE costs per Boe dropping by 1.8% during the quarter. An example of the project we proceeded with was at our [Means] Grayburg Waterflood project in Andrews County, Texas. We began a waterflood expansion that will ultimately entail seven conversions to injection and two new producing wells. This project is expected to develop over 700,000 barrels of oil. Field work on the conversion started during the second quarter with three of the conversions. The remainder of the work will be completed in the second half. Also, further evaluation of our recent Marathon Permian basin acquisition, which closed late last quarter, confirmed attractive drilling targets for oil, especially in southeast New Mexico where we just [sanctioned] 10 well programs. We are particularly enthusiastic about our position in the emerging horizontal Granite Wash gas play in the Anadarko Basin. Most of you would be aware that this has been a core area for Apache for decades. We own interests in almost 2,000 acres in the play area. We have drilled more than 100 successful vertical Granite Wash wells over the past five years and know these rocks well. Dozens of horizontal wells have now been drilled with initial rates above 10 million feet of gas per day, significantly reducing our risk as we begin rigorous evaluation of the horizontal potential on our acreage. We are presently drilling our first operative horizontal Granite Wash well, offsetting several recent industry successes. Apache has also identified other horizontal gas and oil plays on our acreage and will be testing these over the remainder of 2009 and into 2010. The central region is really starting to see the cost reductions we were looking for to improve the economics of our drilling programs. With our huge HBP acreage position, as Steve alluded to in the Anadarko and Permian Basins, has allowed us to defer activity until costs reflect the level of product prices we are experiencing. As indicated, we believe we can drill and complete a well today for roughly two-thirds of last year's costs. In some surfaces, cost reductions are continuing to drop. Early this month, we fracture stimulated the deep Springer well for $215,000. The same job last year cost us $625,000. Work-over rig hourly rates are down 35% in the Anadarko and 30% in the Permian Basins. We entered the second half of the year with 70% of the region's budget unspent. We are now accelerating our drilling and work-over programs and will concentrate on relatively shallow Permian Basin oil prospects, especially in our prolific units of southeast New Mexico. We are currently evaluating the addition of two more drilling rigs and expect to significantly increase our recondition rig activity. Moving to the Gulf Coast, the Gulf Coast region produced an average of 116,800 barrels equivalent per day during the second quarter, up 12.2% from the first quarter, a figure of $104,000. Hurricane related production restoration added 5,100 barrels to the first quarter number and Geauxpher Fields first production added another 3,100 barrels per day, while new completions and operations capital projects added another 6,200 barrels equivalent per day to the first quarter figures and offset the natural declines. At the same time, lifting costs for Boe dropped by 9.5% from first to second quarters. Our much anticipated 40%-owned Geauxpher development came online May 15th and has already produced 7.5 Bcf to date. And the two-well field continues to flow at 105 million cubic feet of gas per day. Our 100%-owned South Timbalier 287AA sidetrack resulted in a discovery. The discovery was drilled from Apache South Timbalier 308 platform into the adjoining block. This high angle well was drilled to 23,000 feet measured depth and logged 40 feet of net oil pay. The well tested at 1,971 barrels of oil per day and 8.6 million cubic feet of gas per day with over 7,000 pounds of flowing tubing pressure during that second quarter. It was brought on production May 13th and continues to produce today at near test rate levels. Hurricane restoration efforts, primarily associated with third party infrastructure repairs, continue. We expect to recover an additional 8,800 barrels equivalent per day in the third quarter. On the cost front, we continue to see further reductions in rig rates. Some of you will have noted that the flow-to-rig count now exceeds jack-ups in the Gulf of Mexico. Jack-up rig activity is now under 20 rigs from the more traditional 100 rig level. As a result, boats are now well under half of last year's rates and we are seeing similar cost reductions for support vessels. Moving to Canada, our Canada region produced 80,186 barrels equivalent per day, up 2.8% from the first quarter, primarily associated with new production from our winter drilling programs from those producing for most of the quarter and offsetting those natural declines. Meanwhile, the region was also successful in reducing LOE per barrel equivalent by 7.7%. Continued weak gas prices and the high cost environment has continued to slow our development drilling activity in Canada. We have drilled a total of 118 development wells through the first half, but with very little activity during the second quarter. We plan to drill another 53 development wells in the second half but primarily for oil targets. The province of Alberta has attempted to recover from the dramatic drop in rig activity associated with weak product prices and their ill-advised royalty increase of last year. The province has implemented a royalty incentive limiting royalties to 5% for the first year if the well is completed before April 1, 2011 as well as a $200 per meter drill royalty credit. We continue to evaluate our substantial prospect inventory with these incentives in mind but we'll generally need more cost relief and/or higher gas prices to increase our development activity substantially. Again, this acreage is held by production and it'll still be there when prices increase. Drilling for the remainder of the year will focus on oil development opportunities at Zama, Midale and the House Mountain fields. With our partner EnCana our Horn River or as we call it the Ootla shale activity remained high during the quarter. We currently have six Muskwa wells on from the 2008 program and their producing 14 million a day after more than a year on production on average. Those wells were completed with 6 to 10 fracs of bearings sizes. The first three wells from the EnCana operated 2009 program are now in production with a total of 26 million feet of gas per day being produced after more than three weeks on average. A fourth well is expected to be on production within the next week. The production rates experienced to date have confirmed our estimations that we can expect ultimate recoveries of over 10 Bcf per well. EnCana we'll finish the drilling of another 11 wells while Apache finishes our 16 well program on the 70K pad by the end of this third quarter. Completion operations for those wells will commence late this year and we would expect to be ready for first production by the end of the first quarter 2010 from those wells. We are quite pleased with the improved efficiencies that we've been able to achieve as we learn more. Drilling times have improved to as little as 16 days from our original estimation of 30 days. On the infrastructure side, the partners commission the C67K Dehydration compressor facility in late June and the new 42 mile by 24 inch sales gas line with the capacity of over 700 million cubic feet per day was put into service transporting gas from the C67K facility to Spectra's Interconnect near the proposed Capital Lake Gas Plant site. To get the project started we have hedged a net 50 million to 100 million feet of gas per day over the next three years at $6 to $7 per Mcf. Given continued soft gas prices the partners will need to continue to look for ways to reduce cost to make this play very competitive. We believe, however, that with the results to date and our acreage position, we will be able to drill some 2,000 to 3,000 gross wells per multi-well pads over the next several decades. Now, I'd like to turn this over to Roger Plank. Roger B. Plank : Apache turned in strong second quarter results in the face of oil and gas realization that were cut in half from a year ago. Mitigating the price impact were the higher production and lower costs mentioned earlier. Relative to last years second quarter our 6.5% production increase was accompanied by 16% lower operating expenses or $250 million reduction. The progress in our results is most evident when compared to the first quarter. Earnings adjusted for foreign currency fluctuations on deferred taxes and impairments more than doubled to $474 million or $1.41 per share and cash flow jumped 28% to $1.25 billion for the quarter. Frankly, these results beat even our internal expectations for several reasons. Our 7% production increase sequentially was stronger than anticipated primarily in our Egyptian and Gulf regions. Higher production contributed to substantially lower than anticipated cash cost per unit produced. But the primary thing that differentiates Apache's results this quarter is our strategy of diversified production and revenue sources. We're all painfully aware that North American gas prices fell significantly during the quarter, in our case realizations dropped some $0.73 per Mcf or 16% from the first quarter. Given the market's myopic focus on North American natural gas it may come as somewhat of a surprise that Apache's equivalent realizations for oil and gas rose 19% during the quarter. Obviously being half oil helped. Realizations climbed 37% from first quarter to $58.15 per barrel. Interestingly, however, our international gas which has now grown to over 40% of our worldwide gas production, also increased in price by 8%. This, coupled with higher production, enabled Apache's second quarter gas revenues to stay within $1 million of per quarter levels at $560 million. By holding the line on gas revenue we were able to enjoy the full benefit of our higher oil and liquids revenue, which jumped by 45% from first quarter. Oil added nearly half a billion dollars of revenue, and drove total revenues up 28% to over $2 million. At the same time costs went the other way. Lease operating expense for BOE was driven 6% lower than the first quarter to $7.58 and should remain below $8.00 for the foreseeable future. Full cost DD&A of $9.86 per BOE was down 9%. G&A per BOE of $1.70 was down 1% sequentially despite $0.26 of severance related cost for our recent right sizing efforts. Absent nonrecurring items, future unit cost is expected to fall below last year's average of $1.48. Finance cost decreased $0.05 a barrel equivalent to $1.14 on higher production volumes, while taxes other than income rose with oil prices by 23% to $2.17 per BOE, driven primarily by a petroleum revenue tax in the North Sea. Our balance sheet remains strong and we continue to maintain our financial flexibility with debt-to-cap below 25% and over $750 million of available cash. Given rising production and current prices we anticipate cash balances to return to over $1 billion by year end, absent increases in capital spending or additional acquisitions. Now that's a lot of information and detail and I think the important point is that for over 50 years Apache has made a business out of not following the pack, choosing instead to build a balanced international portfolio that delivers consistent results, and gives us competitive advantage over those tied to the vagaries of a single product price. The merit in that approach was evident in our second quarter results and they speak for themselves. I'll now turn it back over to Steve for closing remarks. G. Steven Farris: And I'd like to close maybe on the same vein that Roger ended his, to re-emphasize the point that we feel obviously is sufficiently recognized in the market, and that's the competitive strength of our portfolio balance. Roger pointed that NYMEX gas price fell 26% from the previous quarter, yet our barrel of oil equivalent revenues increased by 19%, and that's both because of our international gas prices increasing as well as oil, obviously, increasing. It's been brought to my attention recently that we are the largest international producer among U.S. independents, whether you look at production outside the United States or production outside North America. Further, our production is equally balanced between oil and gas and we have a deep resource and opportunity base for all our regions, given our position of strength as a result of many years of staying true to our contrarian spirit, our long-term perspective, discipline and operation focus. We continue to be dedicated to generate long-term growth and value for our shareholders and with that we'll turn it over to questions.

(Operator Instructions). Our first question comes from Brian Singer – Goldman Sachs. Brian Singer – Goldman Sachs: I wanted to follow up on your point on acquisitions. I just wanted to see where you stand in terms of the importance to Apache, how bid-asks are and the importance of adding new U.S. shale assets to the portfolio? G. Steven Farris: Well, everybody continues to believe that Mecca's out there, Brian, somewhere and the bid and the ask will stay pretty far apart. Although I will tell you we don't go to auctions so most of the things we look at are negotiated so that the auction process doesn't enter into the picture. With respect to shale gas in the United States, obviously we continue to look. I would think that's probably something that you'd have to look up and we'd tell you we did it rather than explain that we're doing it. Brian Singer – Goldman Sachs: And then just thinking about Australia, can you talk about how you're thinking, or your latest thoughts on sourcing Julimar/Brunella, etc. and the potential participation and status of LNG liquefaction? G. Steven Farris: Well, I don't think it's any secret that there's two competing LNG facilities that are going in there, by two major LNG producers in the world, and we are very closely approaching a time then when we're going to have to get to the point where we decide which one that we are going to go with, and that should probably happen this year. Brian Singer – Goldman Sachs: And do you think you would sign a supply contract for off-take or participate in that at the same time? Or would it initially be more of a commitment to participate just in the liquefaction with a supply contract to be signed at a later date? G. Steven Farris: Well, I think they have to go together to some extent. You certainly don't want to commit to the facility – where both of those projects are today is they're going into final engineering and design and a FID or actually investment decision, final investment decision probably won't be made for 18 months. So what we're looking at right now is which party that makes the most sense for us, assuming we don't take it to the domestic market, which party to us makes the most sense for us in the long term. And then it's going to be a process.

Our next question comes from Doug Leggate – Howard Weil Inc. Doug Leggate – Howard Weil Inc.: A couple of questions, first one is on Egypt and the second one is on the IPLA. First of all on Egypt, it seems that we all get kind of caught up looking at nonconventional opportunities here in the U.S., but you've obviously had extraordinary success over there. Can you kind of characterize, where are you now in terms of your prospect inventory? How should we think about the risking the reserves potential and ultimately can you just kind of characterize what the drilling looks like, and not just this year but whether or not you're going to recommit additional capital given how successful that program's been? And my follow-up is on the IPLA. Roger B. Plank: Well, in Egypt the project portfolio remains very robust. We'll drill 19 wildcat wells this year. We've put seven or eight down and 12 yet to go. It's a combination of oil and gas program there for the exploration drilling. That will be out of a total program of about 160 wells for the year. We have a substantial inventory. At any given time there's at least twice that number and it's constantly replenished with additional opportunities as we progress with additional treaties, seismic surveys over our large concession holdings in the western desert. Doug Leggate – Howard Weil Inc.: Roger, are these the street targets? I mean, is it as simple as saying typically we're looking at, I don't know, 5 million, 6 million barrel type of targets, oil equivalent, or is it something much more complex than that, given the multiple [plays] that you've seen over there? Roger B. Plank: Well, it ranges from the 3 million to 5 million barrel. I'm sure there's plenty of those up to the multi DCF-type, [Kasser] type opportunities, and the Matruh development lease is an example. We have a very consistent track record there. Just about every accumulation that we have tapped there – our 3Ds – has been in the 12 million to 14 million barrel of oil equivalent range in terms of recoverable size. And the key thing in each of the western desert is repeatability, both of the individual prospects as well as the amount of up-hole pace, which we frequently encounter being able to get and provide many work over opportunities in the future pre-completion. Doug Leggate – Howard Weil Inc.: Well, I guess the question sort of then, Steve, is are you ready to recommit capital or additional capital? Or is the program just going to continue at that kind of current run rate? G. Steven Farris: Well, obviously we went – our cash flow across this company went down about 50%, so what we cut capital about $3 billion out of last year's capital, somewhat across the board although there were a couple of variables, Egypt being one of them that wasn't cut nearly as much. We spent about $1.5 billion in 2008. We'll spend about $750 million to $800 million in Egypt this year and I can't imagine next year's program will be anything less than that for 2010. And the reason we spent so much in 2008 was because we had those two gas plants. We paid – the majority of the money that we – that those plants cost, really hit us in 2008. Doug Leggate – Howard Weil Inc.: And if I could just ask a follow-up then, this question's for John; it's on the IPLA. I guess the comments on hedging, is that how we should think about the sort of ceiling on your activity level in terms of the production levels you expect to get to? And I imagine the economics are still pretty challenging, or should we think you're going to go a little more aggressive up there than those volumes currently suggest? John A. Crum: Doug, we're continuing to look at that obviously as we go forward. The bottom line is we felt pretty comfortable putting those hedges in place. It certainly makes the early part of this program pretty robust economics. Looking out further we obviously are trying to push this to make the numbers make it without a hedging program. So obviously if it works that way it'll work quite well if you hold gas prices a little higher. So that's been the drill. We continue to find ways to reduce the costs there, but there is no question you need to have reasonable gas prices to make this thing become the play we want it to be. Doug Leggate – Howard Weil Inc.: Are we at breakeven yet, John? John A. Crum: Well, we think so, but it depends what you need as a gas price, so if I just had to characterize a number we think we need Henry Hub to be somewhere in the $3.50 to $4.00 range for us to kind of come out even. Anything less than that we're going to have to get our cost out.

Our next question is from David Heikkinen – Tudor Pickering & Co. David Heikkinen – Tudor Pickering & Co: Just a quick question on IPLA, where are you expecting costs to go, just talking about the 16 days and the number of stages? John A. Crum: Yes, we're really feeling pretty good about what the two teams have been able to do with our drilling efforts. Obviously that, getting less days out there will pull your cost down pretty quickly. I will say, though, just to make sure I'm kind of covering this, we tend to turn around and add another frac job every time we save a little money on the drilling side, so in the end we feel pretty comfortable that we're still in this $9 million to $10 million completed and tied in Canadian dollars for a well. But as we're able to continue to drop those costs, then you've got to make then the decision should you add another frac job to the horizontal or should you go ahead and save the money and go to the next well? David Heikkinen – Tudor Pickering & Co: On the capacity side, I guess about the hedging volumes or hedging equating to volume. Can you remind us just the pipeline and plant capacity that you have committed or tied up? John A. Crum: Yes, so what we have is a pipeline that will handle about 700 million feet a day coming out of the Horn River Basin. Now several other of the industry partners are part of that as well. Apache's portion of that is a 30% ownership, so that would certainly make in this first stage it would be over 200 million of capacity down that line. We have an additional probably 50 million capacity down through our old Missile plant arrangements. What we tried to do here is we tried to tie this to some commitments we made to Spectra for processing and then to TCPL as they bring in a new transport line that will take gas to the east. Those are all set to come in sort of 2012. David Heikkinen – Tudor Pickering & Co: And then on the Gulf of Mexico, looking at Geauxpher volumes, can you talk some about how that ramp in production has occurred and kind of some of the competitive drainage and what the current rates are? How are you thinking about the project right now? John A. Crum: Well, obviously we're quite pleased with Geauxpher itself and we find ourselves in a pretty good shape on competitive drainage situation because we've got a little better capacity coming out of there then the offset players. But that said, I guess you've got to see where this is going, obviously, when you're making $105 million a day you can drain a lot of gas pretty quickly. It will decline at some point. David Heikkinen – Tudor Pickering & Co: Are there additional fault blocks or additional opportunities to drill the Geauxpher or how do you think about testing around there. John A. Crum: Yes, there is. The issue for us is our interest is lower in the offset so we're not in a real rush to do something right now. David Heikkinen – Tudor Pickering & Co: On the exploration side, just remind jus what you have going in the Gulf of Mexico. I know Arden was drilling, any other exploration that we ought to be thinking about. John A. Crum: Arden was drilling and it has resulted in a dry hole. We have no other rank exploration going on at this time. We continue to run a couple of the platform rigs working our kind of traditional areas. David Heikkinen – Tudor Pickering & Co: Thinking through Gulf of Mexico a lot of smaller parties have insurance issues and rig availability issues as you go into hurricane season. Can you remind us do you have business interruption insurance or do you have any insurance, Roger or John, as we get into hurricane season? Roger B. Plank: We have business interruption but not in the Gulf of Mexico this year. David Heikkinen – Tudor Pickering & Co: It was too expensive? Roger B. Plank: It got way too expensive. We have physical damage insurance through Oil Insurance Limited in Bermuda as a mutual, and that's up to $250 million in coverage above the deductible.

Our next question comes from Leo Mariani – RBC Capital Markets. Leo Mariani – RBC Capital Markets: I was wondering if there was any update on the Eagle Ford Shale if you guys have done anything there recently, picked up any acreage or drilled any new wells. G. Steven Farris: Well, we have a pretty good acreage position in there presently we have about 450,000 acres through the oil side and some in the gas side. In fact, we're re-looking that. We're not drilling a well at the present time. We're re-looking pressures and core analysis to try to figure out we drilled a horizontal well that was a very marginal well, frankly, on the gas side. Leo Mariani – RBC Capital Markets: Jumping over to the North Sea, your latest development well was obviously one of the advanced to ever drill over there at 10,500 barrels a day. Is there any difference that you guys need with that well and if you kind of consistently had better success recently apart from that [inaudible]. John A. Crum: We've picked a number of these targets inventory that Steve referenced earlier based on the continuing valuation of the 4D seismic that we run out there, in which case we look for potential unswept areas for the long-term water flooding activity in the field, and the 4D63 Charlie 63 well was no exception. In fact, it was using 34 meters of [hasting], which was even larger than our pre-drill expectation. You can't see everything on the seismic and even you have to detail the geology as best you can between the wells and the seismic information. So it was a very pleasant surprise we have really a large inventory and we hope to be able to find a similar opportunity like this and then match the 77 wells that are yet to be drilled. Leo Mariani – RBC Capital Markets: A follow-up question here on the Horn River, [Hadean] gas bonds were up pretty nicely sequentially from the first quarter to the second quarter. Did you guys get contribution from the Horn River there or was that just your regular way of winter drilling program. John A. Crum: That was pretty much our winter drilling program. Obviously, we put some of those wells from the '08 program on late last year. These volumes we just got we really just got those on production in July.

Our next question comes from Joseph Allman – JP Morgan. Joseph Allman – JP Morgan: On the Horn River Basin play the shale, when you talk about 10 Bcf or more per well, are you talking about in a specific area or do you really think across your acreage position you could average 10 or more Bcf per well? John A. Crum: We have a pretty extensive acreage position there with our partner in Canada we've got well over 400,000 acres, so I guess I will temper that with saying we feel pretty good about that number in the Two Island Lake area. So we've drilled a lot of wells across the acreage and really have had some fairly consistent results. So feeling pretty good about it overall, but I think I have to tell you that in the Two Island Lake area we're pretty confident in these numbers. Joseph Allman – JP Morgan: So the 28 or so wells that you've drilled in the I think 10 that you've got producing, all of those are in the Two Island Lake area? John A. Crum: No, three of those are in what we would have called the Dilly area up to the northeast, and it is true that up in that are you would expect that the shale's are slightly thinner but not much thinner. In the Two Island Lake area we are concentrating our activity there primarily to feed infrastructure and reduce our overall costs. So we're basically working in the same area together to keep our costs down. Joseph Allman – JP Morgan: And the Two Island Lake area, what kind of acreage position is specified to that area? John A. Crum: Well, I think you've seen the maps that we've got out on that, but that's kind of right in the heart of our acreage. I mean we've got acreage south of there and north of there it's the biggest chunk of that 400,000 acres would be in this general. Joseph Allman – JP Morgan: So in that area have you tested the four corners of that area pretty much? John A. Crum: We have got tests pretty much in the four corners – I don't know about the four corner of it but we've tested across all of our acreage position and feel like we've got pretty consistent shale thicknesses and in fact have gas rates out a significant portion of the area. We haven't drilled horizontal wells in all those places. Joseph Allman – JP Morgan: In terms of the decline curve, could you describe what the decline curve is looking like for your most mature wells? John A. Crum: I think that's what's giving us a lot more confidence. The wells we drilled last year as we started putting more and more fracs on them we're finding that yes these decline like many shale's very quickly, but we appear to be flattening out a little quicker than what we were traditionally basing our estimations on. So to give you a sense for that, I think I've told you in the past about the 10 frac well that I guess came on production in September of last year. That well is still making 4.5 million a day after write-out a year. So that kind of makes us feel pretty good about where these numbers can flatten out to. The fracs we're doing this year, one of the wells we've got on has 12 fracs, the other two have 14 and that's going to be a number we'll probably stick to some where in that range and probably do a little experimenting with even higher numbers.

Our next question comes from David Tameron –Wachovia. David Tameron –Wachovia: You guys talked a little bit about Granite Wash, can you go into more detail on the acreage position and what you've seen from the wells who have participated in, etc? John A. Crum: We have participated in another horizontal well and had reasonable results out of that. We have acreage in and around a number of these successful plays that are underway right now. The number I gave you of around 200,000 acres to give you it straight on how we've pulled that up we hold a huge acreage position in the Anadarko basin, more than 500,000 acres so it depends on where this play goes ultimately. But what we did is kind of draw a circle around the area where we've seen successful horizontal tests so far and then counted up the acreage we had within that circle. So that's where we came up with around 200,000 acres in the current active play of the Granite Wash. I think the other piece is the guys are continuing to look given our acreage position as horizontal drilling crews at some of these type plays work better and better and we continue to look at other things. And we've got a number of similar style plays that we're looking at horizontal plays in, as well, both oil and gas. David Tameron –Wachovia: I would assume most of this is HBP, but do you have the rights all the way down through like Atoka and more along on your acreage. G. Steven Farris: In most cases that's exactly the case, and so a lot of these wells we've drilled over the last five years we would have been going after Atoka or Granite Wash targets, so we've got a lot of information in the area that's why we feel quite confident about it. And as Steve point out, this is all HBP acreage. We're not in a big rush, especially given the prices, there's no reason to run out there. So we're going to try to learn a little bit from the industry as we go and then go out and make the right calls. David Tameron –Wachovia: Do you care to give us your gut on where this [breaks] in, how far, how wide? G. Steven Farris: It's a big area, I don't have a map in front of me but we're figuring we've got 250 sections in the play and we certainly don't have all the land. David Tameron –Wachovia: Let me jump to something else, can you tell me how many rigs you have running on the natural gas side in the U.S. right now? And you might have mentioned that number, I might have missed it. G. Steven Farris: Our crystal ball on what's going to happen to natural gas prices, is that the question? David Tameron –Wachovia: No, how many rigs do you have running today in the natural gas? G. Steven Farris: We've got probably eight, nine. Nine in the U.S. and a couple in Canada, John? John A. Crum: Up to four. G. Steven Farris: Four, so we've got 13 rigs running. David Tameron –Wachovia: On full year CapEx outlook, obviously depending on prices but if prices stay where they're at today, are you guys still tracking to the 3738 number and that kind of prorate the first half obviously but seeing where prices are at today, where do you think you'll come out on CapEx side? G. Steven Farris: I think we'll be in that range. I mean, number one, I don't think we've seen costs come down as much as they're going to come down. Number two, we have a very good year going and we might gear up a little bit at the end of the year to start 2010, but right now we're staying with where we are. David Tameron –Wachovia: The additional CapEx dollar right now, where would that go in your portfolio? G. Steven Farris: It would be oil anywhere around the world, frankly.

Our next question comes from Tom Gardner – Simmons & Company. Thomas Gardner - Simmons & Company: Just a couple of follow-up questions on the Ootla just based on your previous comments, it sounds like you feel you've, at least from a reservoir standpoint have de-risked most of your acreage there. And can you comment on your development spacing and what that might be in the play? John A. Crum: Yes, obviously we're continuing to experiment with that to some extent and getting a couple of complete pad developments done will be a key indicator on this. Right now just if you average this out, it'd run to the five wells per what we call drilling spacing unit in Canada, which is slightly bigger than a section. And then obviously the number of fracs you put on it would kind of give you an indication of spacing if you book 14 fracs on that that kind of puts your spacing if you put it in vertical sense and more like ten acres. So that's where you get in to some pretty big numbers on this. We do feel pretty good about the acreage overall because we're seeing similar results from similar size drag jobs across the acreage. Now obviously there's still a lot of work to be done up there when you have a 2 million acre basin, but we're feeling pretty good about the resource itself, it's a matter of getting the economics right. Thomas Gardner - Simmons & Company: Can you speak to the royalty and tax situation for the Ootla there in Northeast British Columbia? John A. Crum: Yes, British Columbia has been pretty forward thinking on trying to get some of these new developments off the table and they've got a royalty structure, which granted we're still working our way through. But it really is around trying to develop the resource and then the province will take more like a net profits interest if you will. So what they do is they take a royalty or a net profits interest, whichever is greater. What we like about that is it allows you to go ahead and make some investments and then if they turn out pretty well, the province obviously gets a bigger interest. If they don't turn out well at all then we don't get penalized so tough. That's the real difference between the way they've done it and the way Alberta set their up. Thomas Gardner - Simmons & Company: Last question just jumping to M&A and the North Sea, given that the majors probably no longer consider this province in the area of growth, do you view them as perhaps strategically exiting that and is this an area that you may feel fits the Apache profile going forward for an acquisition? G. Steven Farris: Well, I think sooner or later that if you look at who has the big fields and at least the U.K. North Sea, its BP, Shell and Exxon. And do I think they'll focus on that in the long term? No I don't, although if you look at what the contribution of the North Sea still is to each one of those companies, it's pretty large. And the one thing that I would say is all North Sea fields aren't created equal. And I think we've seen that from 2005 forward and a number of people have gone out there, especially a lot of little guys have gone out there and tried to make a play out of it and it's much more high cost and much more intense from a technology standpoint. And actually even we realized back in 2003 but I think we have definitely got out some of the learning curve and it would be an area that we would focus on if the right opportunity came along.

There appear to be no further questions at this time. I would like to turn it back over to management for any additional or closing remarks.

Thanks everybody for joining. I just wanted to mention that Steve Farris, our CEO Chairman is going to be CNBC at 3:30 Eastern Time 2:30 Central Time, so you might want to catch him there. And for those of you with any additional questions, I'll be in my office after this call. Thanks for joining us.

That concludes today's conference. Thank you for your participation.