Good day everyone and welcome to the Apache Corporation third quarter 2009 earnings conference call. This call is being recorded. Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

Good afternoon everyone and thanks for joining us for Apache Corporation's third quarter 2009 earnings conference call. This morning you'll see we reported third quarter net income of $441 million or $1.30 per diluted share and cash flow from operations of $1.3 billion. Adjusted earnings which excludes certain items that impact the comparability of the results totaled $534 million or $1.58 per diluted share. On today's call we'll have four speakers making prepared remarks prior to taking questions. Steve Farris will kick off the session. He's our Chairman and Chief Executive Officer; followed by Rod Eichler our Co-Chief Operating Officer and President, International; then John Crum our Co-Chief Operating Officer and President of North America; and Roger Plank 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 is included on our website. Any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or costs incurred, will be identified as such with the reconciliation located on our website. In addition, we have posted some supplemental financial information for the quarter on our website as well. All this information can be accessed at www.apachecorp.com/financialdata. With that, I'll turn the call over to Steve.

Apache delivered solid production growth during the third quarter. Production was up 19% against the same period last year and up 8% on a year-to-year basis compared to last year. In a moment, Rod and John and Roger will walk through our progress during the quarter. First I'd like to highlight three specific recent developments that we've had. The first, as you may have read, we're going to pursue the development of a liquefied natural gas export hub in Western Australia which is in cooperation with Chevron and Kuwait's KUFPEC. The project is called Wheatstone and will give Apache a steady cash flow base for 15 years. This cash flow base will be based on production net to Apache of 190 million cubic feet gas per day and 5,100 barrels of condensate per day for 15 years without decline. We expect the natural gas to be marketed on a long-term contract basis at Asian LNG prices. These are linked to oil prices and represent a significant premium to North American gas prices. In addition to project's realizations, we'll have the benefit of contractual stability for the duration of the project which enhances our portfolio balance which is in contrast to the boom and crash volatility of North American natural gas prices. Apache's mission is to create long-term superior value for our shareholders and this project is an outstanding example of it. Looking beyond the immediate project, we have a very large prospective acreage position in Western Australia and the Wheatstone infrastructure goes right through the middle of much of it and it's expected to provide the means to monetize our ongoing exploration discoveries at premium and stable oil length prices. The second item is the recent developments that we've had in Argentina where we've signed a gas contract for $5 and aim for our gas. We have an outstanding resource base in Argentina and we built at a very low cost compared to others because we got in when others gave up. And it's been our belief all along that the economic fundamentals ultimately prevail, and regulated hydrocarbon prices would have to adjust to meet energy demands as they did in this country in the 1970s. The agreement is a great example of how fundamentals ultimately do prevail, creating value for our shareholders. The third item I'd like to highlight is our Granite Wash play in central region of the US. I think you might have read this morning, we reported the results of our first well there which started production at 17 million cubic feet of gas a day and 800 barrels of liquids per day. I might say with these kind of liquids, you can make very good economics at very low gas prices. We control over 200,000 acres across the play and we currently plan to drill 20 wells in 2010. We built one of the leading acreage positions in North America which has not been over the last few years but really over the last decades. Drilling and completion innovations continue to unlock new opportunities and the Granite Wash is a great example of that. Also importantly, substantially all of Apache's North American acreage is primarily held by production which allows us to pick development timing to maximize the value of our shareholders. And with that, I'd like to turn it over to Rod and John and Roger and then we'll go into Q&A.

Thank you, Steve. I will provide a quick overview of the main developments in our international regions. During the third quarter, production from Apache's international operations was 316,700 barrels of oil equivalent per day, a 4.6% increase over second quarter. The production increase can be attributed to drilling successes in the North Sea as well as a full quarter of restored production from Australia's Marinas Island. In Egypt, net production was 155,600 barrels of oil equivalent per day, a 1.6% decrease from second quarter. The net decrease was due to higher oil prices resulting in lower cost recovery barrels under the PUC, combined with lower cost recovery. By contrast, gross BOE per day for the quarter increased by 16,700 barrels per day or 6% from 273,800 to 290,500 barrels of oil equivalent per day. During the quarter, Egypt region achieved new daily gross production records per gross oil and condensate at 174,600 barrels of oil per day and gross gas at 823 million cubic feet gas per day. On the exploration side, we completed drilling and/or testing operations on six new wildcat resulting in two new field discoveries during the third quarter. Four wildcat wells are presently drilling. Apache has a 100% contract of working interest in all but one of these wells. Some brief highlights of the two new discoveries and significant appraisal and development wells in the greater call to concession area are as follows. The Chelsea-1X wells had (inaudible) call the offset concession tested $19 million a day of gas and 650 barrels of condensate from 31 feet of upper Safa sand and 1,800 barrels of oil per day from 38 feet of AEB sand. A development lease is pending approval by the government and production is expected to commence by year-end. The Prince 1-X wildcat in Las Clavellinas session logged 66 feet of upper Safa pay. The first zone of three to be completed, taxed at a rate of 20 million a day and 1,100 and 106 per day. Apache had a 64% working interest in this concession. In the Phiops area of the Faghur Basin, perhaps it continues to have exceptional developmental results in Cretaceous AEB formation which has been an important driver of production growth. This quarter, our success continued with one re-completion of an existing well and two new appraisal wells. The field discovery well, the Phiops-1X was recompleted from the Safa to AEB at a rate of 4,600 barrels of oil per day. Also during the quarter, Phiops-2X encountered 143 feet of AEB oil paid and tested up to 7,200 barrels of oil per day. The Phiops-6X logged 157 feet of the same AEB oil pay as awaiting completion. This wells extends a Phiops accumulation Northwest on to our (inaudible) session. Perhaps at the Phiops field Production at the Phiops field is presently facilities constrained at 6,500 barrels a day. Expansion to 8,000 barrels a day is planned by year end and expansion to 20,000 barrels a day is targeted by third quarter 2010. On the development side, gross call to gas production which averaged 668 million cubic feet of gas per day during June, averaged 702 million cubic feet of gas per day during the third quarter and 750 million a day through September. As a result of full completion of the Salon three and four gas plants. Two shutdowns are scheduled in the fourth quarter at shales of biogas plant that was result of the deferrals about one Bcf of call to production. Turning to Australia, net production was 48,400 barrels of oil equivalent per day a 30% increase over second quarter. Gas oil production increased by 40% and 4% respectively. This increase is primarily due to having the full quarter's production following completion of Varanus Island repair project in the second quarter. In our Van Gogh oil project which Apache operates with a 52.5% working interest, final inspection repair works were on track to deliver FPSO to the field before the end of the year. All development drilling and subsea installation is completed with post production expected by year-end. Production is anticipated to ramp up to a peak of 20,000 barrels a day in 2010. The nearby BHP built and operated Pyrenees FPSO developer project, in which Apache had a 28.6% working interest, is also underway with development drilling and subsea installation progressing as planned. We expect first production in late first quarter of 2010. Production is also anticipated to ramp up to a peak of 20,000 barrels a day in 2010. We broke ground at our Devil Creek gas plant in September. Earthworks have commenced at the site no major onshore and offshore construction contracts have been awarded. We anticipate first gas from our Reindeer field in third quarter of 2011. Apache operates this project with a 55% working interest. We also entered feed for the BHP operated Macedon domestic gas developer project during this quarter, with a final investment decision expected in June of 2010. Apache has a 28.6% working interest in this project. During the quarter, drilling activity has been focused on the Coniston appraisal project with five wells having been drilled to date. Apache operates this project with a 45.7% working interest. Two wells in this program the Novara 3-H and Coniston 2-H. have been production tested at rates of 5,500 barrels per day and 11,200 barrels a day respectively. Additional wells will be required to fully delineate the pool in the fourth quarter. The Coniston accumulation is likely to be developed as a tie back to the Van Gogh FPSO. Last week, as Steve mentioned, Apache 284 and Foreign exploration company, announced our election of joined Chevron developed the Wheatstone Liquefied Natural Gas hub in Western Australia. Apache includes Exxon in an exclusive agreement to supply gas from our Julimar and Brunello discoveries and become foundation equity partners in Chevron's operating Wheatstone project facilities. This project unlocks 2.1 trillion cubic feet of gas reserves at two of Apache's largest discoveries and generates steady net sales of about 190 million per day and 5100 barrels of equivalent say today it's a 15 years of prices spent at oil prices. Apache has a net 16.25% interest in Wheatstone Phase I development. As a foundation partner Apache will also have the opportunity to participate in future expansion of the project providing additional options for gas commercialization. The final investment decision on the first phase of the project is slated for 2011 after the feed is completed. Turning to North Sea, net production averaged 67,800 barrels of oil equivalent per day an increase of 12.5% from second quarter, due to strong drilling results and increased field product efficiency. Production for the third quarter ranked as a second best quarter ever for the North Sea region since Apache became operator of the project in 2003. Production efficiency for 40s field averaged 94% for the quarter exceeding downtime excluding downtime for annual emergency shut down valve testing on the main export line from the 40s Charlie platform as well as a temporary repairs to a section of 35 years old 20 inch pipe near the base of the Bravo riser and Charlie platform. Including these two downtime events, production efficiency still averaged 90%. Production for the fourth quarter will be impacted by a shut down of Bravo platform. The platform which approves is approximately 11,500 barrels of oil per day has off-line throughout October but is expected to resume full production by 6 of November. The Bravo export piping which I mentioned previously that underwent temporary repair in August is undergoing permanent replacement of 80-meter section of the pipe which will complete the online replacement of Bravo that would be in 2008. On the drilling side, we drilled and completed five successful oil development wells during the second quarter. These wells contributed 3,600 barrels of oil per day for the quarter and 5,200 barrels a day in September. I've noticed the 42 Spraberry 33 C42 wells which is a 109 meters of field play and would go on production in September at 3,300 barrels a day. An indicated new oil pool discovery was made last week with the pilot hole drilled from the 40s (inaudible) well which intersected 15 meters of net pay in (Inaudible) and sands about 150 meters above the main Forties reservoir. This reservoir is equivalent to the driven sands which occur in the Echo platform area. Preliminary estimates on 5 to 6 million barrels of oils in place of which 2 million barrels of oil maybe recoverable. This discovery will likely qualify for a small field development application yielding up to 75 million pounds sterling and supplemental corporation tax break incentive as well as not being exposed to the PR2. Finally in Argentina, nets production was 44,900 barrels of oil equivalent per day down 4.7% from second quarter. The reasonable drilling program concentrated the Neuquén basin and things to be successful. During the quarter, a total of seven wells were drilled and completed adding gross product of 570 barrels of oil per day and 26 billion cubic feet of gas per day. The development program in the Ranquil Co field dominated the third quarter activity with three new wells drilled to four completions for a total production net of 360 barrels per day and 20 million cubic feet of gas per day. Most of the border Ranquil Co 1038 which generated 312 feet of pay at the average depth of 8,000 feet and was completed in three zones in the Pre-Cuyo formation initial production rate of 166 barrels per day and 8 million per day gas and the Ranquil Co 1039 which had 269 feet of pay and is completed in two zones in the same formation initial production rate of 60 barrels per day and 5 million a day gas. In addition the (inaudible) [X-20 2001] located in the Baja (inaudible) block tested two zones at the Khalda formation at an average depth of 3,000 feet at a rate of 4 million a day. This successful extend to the well has set up three or four additional locations in the field in late 2009 and 2010. In September, Apache received approval for two gas plus projects in the Neuquén and Rio Negro provinces in the nuke invasion sell to 50 million per day of gas to a power plant for $5 per million BTU. These two projects were the first projects to be approved by the government of Argentina to encourage development of tight and unconventional gas reservoirs to displace imported gas. In the next three years Apache will drill 12 wells in the AC field in the Neuquén province and 36 wells in the EFO field in Rio Negro province to support this project. Without the higher gas prices, these development drilling projects would not be feasible. Apache Argentina has since submitted five additional projects for gas plus approval. Today I'd like to turn the presentation over to John Crum who will discuss activities in our North American operations.

Thank you, Rod. In our central region we produced 88,400 barrels equivalent for the quarter, up slightly from the second quarter. We had very little drilling and work over activity during the first two quarters as we waited for cost to reflect the 2009 product prices. In the meantime, we concentrate on building and upgrading our inventory. During the third quarter we began to measure drilling and work over recompletion program with emphasis on oil prospects and gain change or gas opportunities. We have now ramped up activity to a present level of eight drilling and 34 work over recompletion rigs running in the region. Results from the drilling and work over programs offset the regions natural decline. We expect fourth quarter to be up even more due to some notable new wells and a full quarter of activity. Overall, lifting costs were up 3.9% to 796 per BOE due almost exclusively to the additional work over activity. Base lifting costs were actually down as our cost reduction efforts continued to show. The region performed a 100 work over and recompletion projects during the quarter adding more than 1800 barrels equivalent to production volumes. On the drilling side, with emphasis on oil production, 70% of the central regions third quarter wells were drilled in the oil rich Permian Basin at shallow depths. On the Texas side of the basin, we drilled six [Delaware] wells in our TXL north and south units. The wells averaged just over 100 barrels of oil per day each and will result in a 20 well infill program planned for the first quarter of 2010. Apache has been particularly active in the New Mexico side of the basin maintaining three drilling rigs and five work over rigs during the quarter. In the last quarter, we drilled 27 new wells that came in producing an average of nearly 100 barrels of oil per day. We have an outstanding drilling inventory ranging in depth from 4,000 to 8,000 feet that we now expect to provide around 100 new wells per year in 2010 and 11 in New Mexico alone. In the Anadarko Basin, Apache completed the Tyler 2-55. This was the second well in a four well drilled to earn farm-in from BP. The well found 125 feet of pay in the Atoka wash at 17,000 feet and has been on for a month now averaging 5 million cubic feet of gas per day. Additional tests are scheduled in each of the two remaining BP sections for 2010 followed by an infill development program. As Steve mentioned this morning we released results on Apache's first operated horizontal Granite Wash well. The results were great. The Hostetter #1-23H in Washita County, Oklahoma has been producing the sales for the past four weeks and they are still flowing at 17 million cubic feet of gas a day with some 800 barrels of liquids. We have just completed drilling our second operated horizontal Granite Wash well on our Stiles Ranch acreage in the Texas Panhandle almost 50 miles west of the Hostetter well. Logs indicate more than 4,000 feet of hydrocarbon saturated sand. We will begin completion operations next week. The Granite Wash has long been a core stacked play for our central region where we drilled hundreds of vertical wells over the past decade. As a result we now control over 200,000 gross held by production acres in the play. Horizontal multi-frac technology has vastly improved the potential recoveries. The high associated liquid shield should make this play competitive with any other resources plays. We now have two horizontal rigs running in the Granite Wash fairway and the lot of 30, November. We would expect to run four horizontal rigs through 2010 resulting in at least 20 new wells. In our Gulf Coast Region, we produced an average of 123,300 barrels equivalent per day during the third quarter. That's up 5.6% from the second quarter. While the region maintained a modest level of rig activity for the quarter, three significant new wells added 2,100 barrels equivalent per day while continued hurricane recoveries and a full quarter of our Geauxpher field production more than offset the regions natural decline. Overall, lifting costs were up 4.6% to $1,282 per barrel, driven by increased work over expense and higher than planned hurricane recovery repairs. The significant new wells for the quarter included a re-completion of the 100%-owned South Timbalier at $308 which was brought on at 440 barrels per day. Re-development work continues at Ewing Bank 826 as we brought on the A11 sidetrack producing 1,200 barrels a day with Apache holding 100%. After settling the new platform and a new fault block discovery at (inaudible) Island 8376, the C-1 well is now producing 1,015 barrels per day. We own 48% working interest and plan three additional wells for 2010. Hurricane restoration efforts continue and we believe there is an additional 7,000 net BOEs to be added as the repairs are completed. We expect to get most of that volume by year end, but now have little control of the timing since remaining work is third party pipeline work. Knock on wood, but we have had no hurricane evacuation this year and we don't expect any for the remainder of the year as the weather cools. Our new two wells, deepwater Geauxpher field at Garden Banks 462 which came on production in the middle of the second quarter continues to produce strongly and average 98 million cubic feet of gas on a gross basis some 39 million feet net for the quarter. We expect to be more active late this year and into the next, as the region is built of robust inventory and solid drilling prospects. As such, we've contracted three jack-ups and two platform rigs for anticipated 2010 program. In Canada, the region produced 78,700 barrels equivalent per day, down 1.9% from the second quarter. The drop in production was primarily due to natural declines without supporting production from new well activity and from turnarounds at our Zama complex in Northern Alberta. The third quarter in Canada is usually difficult to show gains as we typically have very low activities levels in the second quarter due to the lack of access as we go through the winter break-up. Somewhat offsetting these declines however were the results from new wells coming on production at our Two Island Lake area in the Horn River basin which will be described later. We drilled 17 wells during the third quarter and expect to drill an additional 19 before the end of the year. The region listing cost per BOE were up 14% to 986 for the second quarter with almost half of that increase associated with exchange rate increases. The remainder is due to one-off costs associated with planned turnaround activity at Zama, Virginia hills and Snipe Lake. The region remains well under budgeted total dollar listing cost for the year due to their cost cutting efforts. While costs have responded to the lower product prices and the Alberta Government has attempted to respond to the downturn with some royalty adjustments, conventional gas well drilling in Alberta remains challenging with a significant portion of the cost savings being wiped out with higher exchange rates. We did drill a modest 11 well Nevis coal bed methane program on high-graded prospects that generated post drill economics showing an 18% after tax rate of return. The remainder of the third quarter conventional program focused on oil targets. We drilled 12 wells off recent 3-D seismic in our core shallow cretaceous (inaudible). Post drill economic show the program generated 32% after tax rate of return. We are especially pleased with two (inaudible) wells that combine for a total of 270 barrels of oil a day and two rigs channel wells that came in for a combined 166 barrels of oil per day. The region is preparing for a winter program to start late in the fourth quarter again focused on oil. Three wells are planned for Zama, four at Midale, six at House Mountain fields. Positive results from the winter program will lead to additional 2010 wells. At Horn River, two more wells at our 50% owned EnCana operated 70-J pad came on production at more than 10 million cubic feet of gas per day each. The four wells from the 2009 program continue to produce at more than 24 million feet per day after more than three months of production. The results support our new estimate of expected ultimate recoveries of over 12 Bcf per well for our 14 frac well. The Six (inaudible) wells from our 2008 program which utilized six to ten fracs per well, continued to meet expectations as well producing another 11 million cubic feet of gas per day after more than a year of production. We presently have the Apache-operated 16 well 70-K. pad and the EnCana 11 well 76-K pad fully drilled, and are waiting on completion operations. Completion operations in the 70-K pad Apache operated, will begin in December with fracking operations commencing in early January. First, production from that pad is expected in April but we'll ramp up quickly as we expect to frac all of the wells before bringing the pad on production. EnCana will immediately follow with the fracking of the 11 wells on the 76-K. We should have all 27 new wells on production near mid year 2010. Meanwhile, Apache has moved to the 52-L pad where we'll drill an additional 11 wells, experimenting with longer laterals with up to 20 fracs and wider spacing to optimize future development plans. Those wells are expected to be drilled by mid year and will be completed in the second half of 2010. EnCana has moved their rig to the 63-K pad where they will drill 14 (inaudible) wells by the end of the second quarter again followed by completion operations in the seconds half of 2010. As mentioned last quarter in support of the Horn River development, we have hedged a net 50 to 100 million cubic feet a day over the next three years at $6 to $7 per Mcf. We continue to find ways to reduce costs and improve rates and the recoveries which we are expected to make this a very competitive play for the long-term. And now I'll turn over the call to Roger Plank.

I've got a potential laryngitis. So, I'll do my best to croak my way through these remarks before turning it back to Steve. Apache's strong third quarter results were driven by higher oil prices and record production of both oil and gas. Despite severe capital reductions this year, we grew daily production 3% sequentially to 607,000 barrels equivalent, piercing the 600 mark for the first time in our 50 plus years. Our balanced production mix also served us well with equivalent realization climbing 7% sequentially with 12% higher oil prices offsetting a 1% decline in our gas price. Earnings adjusted for the impact of foreign currency on deferred tax, of $534 million or $1.58 per share reached a high for the year during the quarter. Record production on higher realizations drove earnings 12% higher than the prior quarter. Cash flow from operations of $1.3 billion also reached a high for the year. Substantial free cash flow enabled cash balances to rise by over $0.5 billion to nearly $1.4 billion at the close of the quarter. As a result of stronger than planned cash flow and declining drilling costs, we've loosened up our purse strings on our capital budget to around $4.1 billion from an initial budget of just north of $3.5 billion. Turning to operating costs, our cash operating costs on a unit basis increased just under 10% sequentially, primarily on seven stacks and PRT with higher oil prices. Excluding these other taxes, our controllable cash operating costs were up only 1.5%. With production up and prices presently above third quarter averages, we anticipate a strong finish to a topsy-turvy year. Our long-term outlook for production growth remains strong with production plateauing at third quarter levels, until we get beyond the shut-ins in Egypt and the North Sea which we haven't mentioned. Production growth should get off to a fast start again next year as we bring (inaudible) online at our Van Gogh and Pyrenees developments and production rams up at (inaudible) in the first half of the year. Also for 2010, I'd note that we have beefed up our hedging position, particularly on the gas side in the face of burgeoning North American gas supplies. We hedged an average of 410,000 MMBTu per day of our projected 2010 North American production. Approximately 90% of the hedged volume was swapped at an average price of $5.60. The balance was hedged using collars with average floor and ceiling prices of $5.65, and $7.55 per MMBTu. For reference, hedge prices of $5.60 in 2010 compared very favorably to our average year-to-date realization in North America of $4.10. On oil side, we now hedged an average of 35,000 barrels per day for 2010 mostly utilizing collars with average floor and ceiling prices of $65.70 to $78.50 per barrel respectively. For perspective, these hedges represent 12% of our daily third quarter oil volumes, 21% of our worldwide gas volumes and 36% of just our North American gas volumes. Before closing I wanted to note a subtle but important change taking place at Apache over a period of years. For most of our history Apache has lived hand to mouth largely dependent on the vagaries of the US gas market for our cash flow and earnings. And our balance portfolio approach has taken hold however, we diversified our sources of revenue and captured new opportunities for adding value. Today, we have a growing complement of meaningful discoveries in large scale projects around the world each of which can really move the needle. In years past we didn't have the wherewithal to spend $1 billion on infrastructure in Egypt's western dessert to bring to market a backlog of gas discovery. The weight for first cash flow would have been just too painful particularly with no free cash flow at the time. However, we've evolved in recent years and having actually made that investment we now flow as John indicated over three quarters of our BCF of gross gas in Egypt day in and day out with no decline for five or six years or even longer with the addition of new discoveries. We have similar high impact assets in Australia where our Reindeer discovery for example is on track to flow 60 million cubic feet of gas per day growth beginning in late 2011 for seven straight years without decline and with the potential for extending the contract further. Then going to go and Pyrenees while different in that production will peak in the first few years are similar in that they are significant large scale discoveries that once online add meaningful volumes some 40,000 barrels per day or so net to production during the first half of 2010. Our decision to saddle up with Chevron on the Wheatstone LNG project for the discoveries is another natural step in Apache's evolution toward large scale long lived impacted projects. We are cognizant of the need to balance these long-term capital intensive projects with near term investments that cash flow and pay the light bulbs but the prize in this case is 150 to 200 million cubic feet of net gas tied to oil prices every day for 15 years. That's not just the different type of asset, it's a company builder. (Inaudible) tells me that learning about low stock price multiples is Bush league so I won't go there but surprising to say that somewhere along the line Apache has grown into a very different and stronger company with a growing number of impactive high quality assets that create a solid foundation for continued profitable growth. Steve?

Thank you, Roger. I'd like to close our comments by taking stock of a little bit of what Roger where it was delivering and building a pipeline of long large, long-term, stable and diverse energy projects. And I think all of you have probably seen a chart with the news in recently showing our major granite growth projects that are expected to contribute close to 140,000 barrels equivalent of new production to Apache by 2012. And those are the big projects we have been investing in during the recent quarters. If you visualize that diagram, we've delivered the Salon gas plant three and four in the Asala ridge waterfloods in Egypt. The Geauxpher development in the Gulf of Mexico during this year already. And that means we've done all the work and invested the capital required and as there are aggregate production, contribution of those projects will hold steady for a good number of years. As a result, we now have the benefit of those steady production in cash flow for an extended period. We've heard many times today the next tier of projects in our pipeline will benefit Apache's growth next year. That's Van Gogh and Pyrenees and also (inaudible) expected to come on stream and ramp up during 2010. In addition, we have a large and growing pipeline of major projects to support our growth beyond 2010. These include some of the things that Rod pointed out, Phiops discovery in Egypt, Halyard, Reindeer, Macedon, Coniston discoveries in Australia, and our fifth Salon plant in Egypt. And we are adding to go this pipeline steadily. This quarter alone we've added the Wheatstone as a major 15-year project. The Granite Wash as a resource play with literally hundreds of locations. I might point out that this entire pipeline is organically generated within our broad global portfolio and continues to be built through organic means we grow through the (inaudible). I would like to say that while major growth projects matter, Apache's real underlying momentum is all the wells we keep on drilling and recompleting across our asset base. And I know it becomes difficult to understand what on earth we're referring to as we fire away an endless series of names of discoveries and production enhancements projects around our global portfolio but that's who we are and the real activity that defines how we grow production and create value in this company and I believe we do it as well or better than anybody out there. I'd like to conclude by summarizing what I believe are our 25 plain messages this afternoon. Our production growth we've had record production growth for 2009. As Roger pointed out we'll probably plateau in the fourth quarter just because of some of our shut-ins that Rod mentioned but we've had great momentum in 2010 to continue to deliver growth in the years ahead. The Wheatstone LNG project gives us a 15-year steady plateau, 190 million cubic feet of gas and 5100 barrels of condensate per day which was stable cash flow contracted at oil link prices. We have entered into a contract to sell some gas out of Argentina for $5 an M, which further validates our view that Argentina for the long-term is going to be a good place to invest and we have a large resource potential in that country. We have a leading position in the Horn River basin which keeps getting better. John pointed out we are now looking at recoveries of 12 Bcf per well with 14 fracs and we're experimenting with even longer laterals and more fracs. That developments program will grow in 2010. And finally, we drilled our first granite wells that flowed 17 million per day, still flowing 17 million per day and 800 barrels of liquids. We have hundreds of locations across this play. Our initial plan is to drill 20 next year. And I'm very conscious that this is a lot of information but we have a lot of information to report. And I want to thank you for your patience and we'd like to turn it over to you for your questions.

(Operator Instructions) And we'll go first to Brian Singer with Goldman Sachs.

First question on Coniston, the wealth you highlighted earlier seems to have relatively high rates and I wondered if you could provide some more color on the resource potential there and capacity available that's leading to your decision to tie that project back versus potentially developed new infrastructure.

We're constant and we drilled five wells to date and probably have another two or three wells to complete delineation structure when the rig returns to this area sometime in early December. We currently from our current view of the field from the first five wells we drilled and the test results for the two wells which I mentioned this is probably has a gross recoverable oil accumulation in the vicinity of about 35 to 40 million barrels. It's within 10 kilometers of the Van Gogh FPSO development so it's very likely and we of course early in the stages of doing the development assessment. But we very likely tie it to the Van Gogh FPSO.

Secondly on Wheatstone, you had highlighted the potential for that project to development 2.1 Tcf. What do you see as your discovered resource at Julimar and Brunello as well as any nearby fields and how should we think about your interest in resource available for potential expansions beyond these first two trains?

Well, we have 2.14 Tcf which we referenced is our kind of our P50 reserve case. We have significant upside to that. We have a lot of satellite projects in the area which could access those production through that facility by virtue of their near proximity. In fact its one of the beauties of the Wheatstone development for us at LNG as it really allows us to bring a lot more of these previously discovered, but isolated accumulations into the marketplace.

Maybe I missed it, do you have a sense of what that could represent? In other words, are there discoveries that you may not have deemed commercial in the past that could now become commercial above and beyond to the 2.1 Tcf?

A bunch are there in the (inaudible) area I which I mentioned, which is right next to the Van Gogh and Coniston and (inaudible) area is the gas development there. Probably four projects we've identified in there, we probably add up to 150 Bcf resource potential on our existing licenses, and we have others which could be delayed and also in the area between Pyrenees Island and the Wheatstone central production platform on existing lands. I don't have a number to give you this afternoon.

And we'll go next to David Tameron with Wells Fargo.

Can you comment on the acquisition market? I know it's something you talked about this time last year, then prices ran ahead of you. Can you talk about your current thoughts there?

Yeah, personally I think it's a little too early to the tell. We are more active as we said a number of times in looking for and at things to buy. I think we find ourselves in a good position with (inaudible) and Apache because we are very selective right now in terms of what we look at because we've got to weigh that against the opportunities that we have on our plate internally versus things that we're looking at. And quite frankly, the real bottomline is, we haven't found anything that competes with what we do for a living right now.

Any general feel for the market, are oil properties still tight? PV-10 [PAC] numbers, can you give me any color there?

While I can't say that there' is nothing that you can look at, and I will tell you, to be real honest with you, the value of the oil to reality is really better and the reason is because people don't have the same view of Mecca coming out there as they do on gas prices, because if you look at a lot of things that are happening out there and if you looked at the current date, the cash market today they don't make sense. You have to look at the strip which is why you see an awful lot of folks out there hedging, because you have to look at the strip to make those things economic. So, honestly the value difference between oil is much smaller than the value difference between gas right now.

And then, up in Ootla Horn River, can you talk about what's your current well cost? What are they running?

John?

Well, we're still working on the 10 million per well but I think I have mentioned to some of you in the past, we tend to start experimenting and adding more fracs. We expect to get our per frac cost down to somewhere in the range of $300,000 per when we start this program, because we're going to have our own water supply and that's been a big cost element in our past jobs, we've had to haul water in with trucks.

Okay. And right now those fracs are running what 600 or 700?

Yes, absolutely.

All right. That's all and we talked in, did you are say you want to get the 10 million. You are not at 10 million today yet, are you?

No. We weren't at 10 million on the ones we've drilled earlier this year. But again, we're having to truck water in and doing less jobs. You can imagine we are about to start on a program where we'll do 16 wells with some 14, 15 fracs per well. So, that gives you some benefits of scale that we have not been able to take advantage of in the past.

Next, Joe Allman with JP Morgan.

In the Granite Wash, what is your net acreage there?

We've got roughly 75,000 acres of net, but we were in a position to, you're probably aware in Oklahoma you can propose a well with any amount of acreage in a section. So, we would expect to pick up additional acreage going forward with well proposals.

And then back to the Horn River basin. I think John you said something about an additional 11 million per day. I just kind of missed what you were saying. Can you talk about that?

Yeah I am sorry. I probably didn't make that clear. We are making $24 million a day out of those four wells that we completed this year. The six wells that we did last year make it another $11 million.

And then sticking with the Horn River Basin, could you help with the economics? What price do you think you need to get an adequate rate of return? And just help us on the decision to sends some gas through LNG versus any through pipe and what the costs involved there are?

Well I think we've shown you some numbers in the past in some presentations where we're around $4 at kind of a break-even point and obviously, that's going to be a little bit of kissing your sister at that number, but we can make it work there especially if we can drive out additional cost. And it tends to be a little bit of a chicken leg thing as realizations go down, we drive the cost down and we get it over the line that way. Obviously, we'd like to get $5, $6, $7. That's why we've hedged some of that gas this year.

And then just very quickly in Egypt. There are three types of wells that you're drilling there, Upper Bahariya AB in Jurassic. Is the cost sort of on average for those three about $3.5 million and remind us what the average reserves per well you're getting there?

Well, there's quite a bit of difference in depth between the three zones. Most of Bahariya development work is typically in the 6,000 to 8,000 foot range and those wells can be as cheap to drill and complete as $1.5 million, $2 million. The AEB wells are typically drilled between 10,000 and 12,000 feet. You are looking at probably $2 to $2.5 million for those wells and the Jurassic wells that can be from 12,000 to 14,000 feet. You're probably looking upwards of $3 million to drill and complete those wells. As far as the reserve sizes go, individual Bahariya wells, for instance the mature waterflood areas of (inaudible) in vicinity of 100,000 to 125,000 net barrels of oil reserves per well, but of course we have hundreds of those wells there. Those are the shallowest wells that we can drill and complete inside of like ten days. These range up to the higher end reserves which can be few hundred thousand barrels per well in the East Bahariya developments which are under active waterflood right now and if the primary successes there have been very significant, that we developed in 2007-2008, again 2009. And then lastly the Jurassic wells, the reserve range all the way from the big (inaudible) wells which have daily rates that can test from $40 million to 50 million per day plus large degrees of condensate. The number of typical Jurassic well would probably be in the 3 to 5 million barrels of oil equivalent per well.

And we'll go next to David Heikkinen with Tudor Pickering Holt.

Just following up as you think about Egypt and what you've done with the waterflood volumes growing over the last several years, how would you think about continued waterflood growth over the next year and two years on an annual basis?

In waterflood program we current have about very 40 active waterflood projects and the oil reservoirs really have done themselves well to this kind of secondary recovery, and we intend to keep growing that. In fact we've been successful in bringing up that waterflood oil volume up to about 70,000 barrels a day currently at about the 160,000 to 170,000 barrels a day we produce gross. And that includes condensate. So, if you back out the condensate about half of our daily oil production, the black oil production of Egypt comes from waterfloods and secondary recovery activities. We would like to continue to grow that because it really flattens the normal decline that you normally see on primary producing wells and this will give us a nice firm base going forward. These fields are, for the most part the most recent fields which we have some 14 or 15 waterflood projects underway right now our the newest and as a result have very long lives of long flood production plateaus.

And you are not waterflooding the A, B just in the area?

(Inaudible) saw the water so that two of these in the activity is in the Baja. We had some activity AEB in the called area. The bulk of our activity and most of oil volumes right now is coming out of the east Baja area which is principally from (inaudible) Bahariya sands.

And then maybe on the Horn River basin as you think about increasing reserves for well I always get curious about how do you think about original gas in place now and kind of percentage of gas recovery and that would then lead to a number of wells per section?

Yeah, David, some of these exercises I mentioned we are going to be doing some more experimenting between ourselves and our partner we certainly are looking into a lot of things to increase the recovery that you would expect out of the area. I don't know that we are really changing our in place numbers. I guess there is still some debate about what that number is. What we certainly know about horizontal and multi-frac technology is as we drill the wells closer together and put more fracs in it we are going to recover higher percentages of the original gas in place. So the real key here is just get into that optimum number where you are spacing between the wells is getting as much gas as is economic to do and not wasting any more than possible. So obviously we could put a frac every 50 feet and recover even more but that's probably not economic.

How do you think about the 16 wells that you're drilling, what spacing are you putting those on?

Well, the 16 wells that we just drilled we are on roughly 250-meters between the wells. And then putting, we had planned on putting 14 fracs. Now we'll tell you, we drilled two wells on the 16 well pad. We went up to 2200 meters of length where we had been at 1600 meters. So we will be doing some experimenting on those longer reach ones. On the pad that we are going to, we are going to take half the pad and take the spacing out to 350 meters and another half the pad and take it to 400-meters between wells. And that's where the real wind can come from. We think we can get the frac length to connect between the two wells, if we can stretch out that space and get longer reaches then obviously we will take less well bores to recover the same amount of gas.

Okay. And then on as you think about gas discovered in Australia jumping around a little bit what would you say your P90 resource is so far tied to Wheatstone, injuring it's probably in the 1.6 to 1.9 TCF range.

P90 is 1.6 to 1.9 and P50 is the 2.14 that seems like a pretty tight range, is that fair?

Well, the P50 is 2.1.

Okay.

It is, let's back up. The P50 is right now based on what we drilled, okay? So what you're looking for is additional gas drainage out of existing oil bores or existing in the area. With still have some other thing to drill out there.

I was thinking about a distribution of what you've already drilled but that 1.6 to 1.9 thanks.

And we'll go next to Leo Mariano with RBC.

Good afternoon here, guys. A question about Argentina. You guys have this $5 GAAP plus projects that you're working on. You talked about drilling it sounded like pretty close to 50 wells between the two projects over the next three years. Curious as to how much incremental reserves and production you guys think that can drive and when you expect some of that production to come online and what the costs are associated with that?

We believe the production online pretty quick in this area because we have infrastructure and these are all mostly in premature development areas so hook-ups are pretty quick. These wells as you heard are relatively shallow. They range anywhere from 3,000, 8,000 feet in most of those gas plus project areas. So those are pretty quick. Just a matter of applying the capital to be able to have the rigs to do it. We've had a pretty soft capital program down there this year which we are now ramping back up, now that we've had some agreements with the sales and industry or other operators with the government and the labor factions to be able to bring up production and make increase investment and exchange for these incentives for increased gas pricing.

Okay. So what's your estimate of reserves you guys can bring online with that program over the next couple of years?

That was a number of wells we have drilled. We report a modest decline each quarter of this year mostly because of the natural decline in the production. We would be able overcome that very easily by drilling more wells. We also had a large number of waterflood opportunities in Argentina. So it's pretty straight forward economics. I mean I don't have, it's quite a range of the program we have down there to be able to specify a certain reserve per well number.

Okay. I'm just trying to get a better sense of what the kind of incremental economics are. You guys mention that at current pricing they don't work but it's $5 that work so I'm trying to get a sense of where in between the brake even is and how much money you're making?

Current pricing in Argentina depending on what market you are selling the gas into can anywhere be from 80 cents to $2. So $5 is a pretty good deal.

Okay. I guess jumping over to the Horn River basin here you guys have talked about trying to bring 27 wells on in the second quarter of '10. I'm just curious as to whether or not you guys are going to have any restructuring production constraint to that point in time or you think you are going to be able to flow all those wells full bore.

I think we will have to bring them on a little bit at a time if we get the results we've been getting you couldn't bring all 27 on obviously at the same time but of course we will bring on one pad at a time. We think that we are in pretty good shape on take away capacity in the Horn River basin into 2011.

I was going to say what is that take away capacity you guys expect in 2010 out there in Horn River?

Well, we are still trying to put the schedule together on exactly how we'd do it but we have actually signed up for 100 million per day capacity through Spectra and we expect to pick up and whatever, that's net to us and Canada has done the same so that can expect to pick up some additional capacity of required from spare that they have available.

Okay. Looking at Egypt obviously you guys have had really strong growth there the last several quarters as you brought on Salon and you had a couple of oil discoveries got your waterfloods ramped up. Just curious if you can talk qualitatively to what the production ramp is going to look like in Egypt in 2010. Are we going to be kind of growing slower from here as just more of your oil comes online or what can we expect there?

In terms of the budgeting process right now for 2010 but I expect that based on our the inventory that did not get drilled in 2009 based on our capital restrictions this year that's all carried over 2010 plus the new projects I expect to return to a level of drilling activity very similar to what we experienced in 2008. Continued growth in production as I mentioned the Phiops field development is very significant or very likely to get to 20,000 barrels per day by mid third quarter of 2010 and we expect to expand the facilities even beyond that because it's a little bit remote area just to the west of our normal operating operations in (Inaudible). So I expect a continued good growth in Egypt from 2010.

Now from a gas standpoint. I had mentioned a number of big gas wells the last couple of conference calls we've had and we are starting to get to the point where we are getting gas back up with all those infrastructure improvements and so we are actively working on a Salon gas train five scenario and additional pipe lining that would be coming on in two years hence or three years from now so that's all in the works working with the government to try to develop those similar ideas. Ourselves as well as other operator they have stranded gas from the area. in the area. Right now we are able to manage our gas streams to maximize our liquid production. So we are rotating our gas wells to be able to maximize condensate productions in the new plants.

I guess final question on the North Sea here. Obviously had really strong production in the third quarter. You mentioned hitting another sort of undiscovered pocket kind of adding some reserves up there. Just curious as to what you folks think the reserve upside is up there. I know you got some pretty detailed models out there?

All right. We have a rather exhaustive development model for the 40s fields. It's almost a 5 billion barrel oil in place field which a couple bill barrels have been recovered and there's a significant amount of oil to be targeted to be recovered to ongoing operations which we've been very successful or ramping up our drilling program based on application for the seismic to target the unswept zones or pods that have not been swept by our long-time waterflood activity there. More and more we continue to fine-tune our work based on our field development model. I see a very robust inventory of drilling opportunities in (inaudible) field going forward. Even though we drilled a number of wells this year, I see a healthy drilling program going forward with a lot of new prospect ideas such as brim and sand prospect which was intentionally targeted in the field and (Inaudible) is a good place and will yield good opportunities.

Our final question comes from Joe Magner with Macquarie.

Good afternoon, thanks. I apologize if I missed the details earlier. Two questions. When do you think you will be in a position to provide preliminary volume growth in CapEx guidance for next year? And then, second, with growing contribution from numerous large multiyear projects, what should we think about in terms of longer term average production rates or sort of minimum rates going forward?

Well, we are going through our, truthfully we are going through our planning cycle right now. We should be in a position by the end of November to start talking a little bit about what we are seeing with respect to our growth for 2010. And on a long-term basis, you know, we historically have not given long-term guidance. I think what we've said at least at our Apache conference in Houston a year and a half ago that based on the opportunities that we have and the projects that we have depending on how much capital question throw at it we can grow at double digits for the next four years. So but that is all dependent on how much capital you spend.

And it appears we have no further questions at this time. I would like to turn it back to management for any additional or closing remarks.

I'd like to thank everybody for joining us today and I will be in my office if anybody has any further questions after the call. Thanks.

And that concludes today's conference. Thank you for your participation.