Steven Farris – CEO Rod Eichler – Co-COO & President International John Crum – Co-COO & President North America Roger Plank – President Tom Chambers – VP IR

Bob Morris – Citigroup Brian Singer - Goldman Sachs Joe Allman - JPMorgan Doug Leggate – BofA Merrill Lynch David Tameron - Wells Fargo Ben Dell – Bernstein Brian Lively – Tudor Pickering [Marvin Hayes – CVP] Ken Carroll – Johnson Rice

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

Good afternoon everyone and thanks for joining us for Apache Corporation's fourth quarter and year end 2009 earnings conference call. On today’s call we’ve taken a little bit different approach from previous calls and intend on using our remarks to provide additional context for the 2009 results and 2010 year ahead. Therefore in order to allow you to focus more on the comments, we’ve prepared a detailed supplemental data package and placed it on our website. This supplemental information plus the reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or costs incurred can be found on our website at www.apachecorp.com/financialdata. 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 at the same URL. On today's call we'll have four speakers making prepared remarks prior to taking questions. Steven Farris will kick off the session and he's our Chairman and Chief Executive Officer; followed by John Crum our Co-Chief Operating Officer and President of North America; then Rod Eichler our Co-Chief Operating Officer and President International; then concluding with Roger Plank our President. With that, I'll turn the call over to Steven. Steven Farris : Good afternoon everyone and thank you for joining us for Apache 2009 year end results earnings call. The year 2009 was obviously a difficult year for the industry due to the sharp drop in commodity prices, and the weakened economy. Going into the year Apache decided to reduce our investments to ensure that we lived within our means, without need to tap the capital markets or dilute our portfolio. So we ended the year with growing 53% fewer wells than we did the year before and investing 40% less capital. We have ramped up activity somewhat toward the end of the year but we really won’t start seeing the benefits of that until in 2010. So in that context we’re very satisfied that the Apache’s team managed to increase production by 9% for 2009. We came out of the year with more cash on our balance sheet than we had going into it. And we did this without diluting our shareholders’ ownership of our upstream portfolio. On the cost side our cost management efforts during the year were successful. We managed to reduce lifting costs for BOE by 20% during 2009. And overall we had strong cash flow from operations after a dismal first start. We generated over $5 billion and had adjusted earnings of about $1.9 billion. This performance is a testament to the strength of our team and the quality of our portfolio around the world. Every Apache employee is focused on maximizing value and growth on every property. And this is easy to claim but very difficult to actually do. It involves an awful lot of geoscience and optimization work but every location, pre-completion, work overs, all add to real value and real growth and you’ll see that in our 2009 performance. I’d also like to highlight that in 2009 we replaced 101% of our production improved reserve terms from drilling and modest acquisitions despite growing less than 50% of the wells we drilled in the previous year. And our finding costs for all of Apache globally was about $16.00 per BOE. And the way we really look at that number is internally, its about $13.86 per BOE for all regions excluding the Gulf Coast. And the reason is is that Gulf Coast have a very unique profile, a high cost high cash flow business. To try to give you a little more flavor for that, at the end of the year we ran the full project life internal rate of return on our Gulf of Mexico crude reserve which came out to be almost 30% on a before tax basis. Now that number includes all cash flows from the time we entered the properties and the future cash flows at strict prices. It included $1.1 billion of net hurricane costs, and it also includes $1.5 billion of future capital costs. Doesn’t give any credit for new reserves we will continue to add on these properties. So in the aggregate it means we generated an internal rate of return of almost 30% on a before tax basis on more than $10 billion of capital. If you look at it on a net present value basis, excess of 10% is $7.4 billion. And that’s why our Gulf of Mexico portfolio is a great source of value generation for our shareholders. We also took meaningful strategic steps in 2009 including our entry into the global LNG business by our participation in the Wheatstone project in Australia. And also becoming the operator of the potential Kitimat LNG export project in Canada. LNG provides decades of stable cash flow which represents a very interesting contribution to our portfolio of assets for the long-term. We have received many inquiries since we became operator of the Kitimat LNG project in January and I think all I’ll say at this stage is that it’s a very promising concept and we believe it could work and be very impactful but at this point we’re simply conducting a [feed] study. We have a long way to go before Kitimat potentially becomes a real export asset on the ground. That sums up everything I’d like to say about 2009 and its 2010 that matters, so I’d like to outline what we’re planning to do for the year and what it means to us. We’ve been a growth company for 55 years and we focus on long-term growth projects, balanced across our commodities and geographies. We don’t follow the latest market fashion because we found that they tend to change and we’re better off just sticking to fundamental principals of profitability and balance. In 2010 its going to be no different. We expect another year of production growth in 2010. Our international regions have continued to deliver a visible pipeline of growth projects and deep drilling inventories. In North America the aggregate will have another stable year similar in 2009 while our new growth plays [inaudible] and gather some momentum. Overall we expect Apache’s net production for 2010 to grow between 5% and 10% over 2009 and due to project and activity scheduling we anticipate the first quarter of 2010 will be slightly up over the fourth quarter of 2009 and then it will accelerate after the first quarter. As you’ll hear from John and Rod, we are executing on a broad and strong portfolio of plays across our global acreage but will sustain our growth and returns for the long-term. The 662 net wells we’re planning to drill this year will advance 32 development plays and 25 exploration plays across our portfolio. To give you a piece of data, the development drilling we do in 2010 alone will contribute 100,000 barrels of oil equivalent net to Apache by 2011. The basis for this growth portfolio is simple, the right critical mass of highly prospective acreage around the world much of which it is held by production, a good organization with real value and delivery focus and a creative application of technology. With that let me pass it to John who will discuss North America. John Crum : Thank you Steven, at the onset of 2009 Apache adopted a cautious approach to North American expenditures in order to allow time for costs to adjust downward to levels reflecting the challenging commodity price environment. Overall we [kept] 2009 investment in North America by near 50% from the 2008 level. We are very proud of the fact that our regional teams were able to hold production essentially flat, down 1.3% while drilling 61% fewer wells in 2009 than in 2008. While I won’t suggest it will be available every year, our large base of HBC properties provided our teams with many opportunities to optimize production from existing wells. This production level was also achieved without any meaningful contribution from new growth plays such as the Horn River and the Granite Wash which we will be ramping up significantly in 2010 and beyond. You will note fourth quarter North American gas production was down 4.4% from third quarter. That’s mostly due to severe weather in Canada where we had widespread freeze up problems. Just a few of the more important 2009 highlights include the start up of [inaudible] in May. Eight months later the two well field is still producing 78 million a day gross, that’s 31 million net to Apache. The Horn River activity ramp up we drilled a total of 42 gross wells but only completed four. The four wells were completed last summer and continue to produce in excess of four million cubic feet per day each and they [inaudible] our reserves for awhile in excess of 10 BCF for each well. We hold a 50% working interest in that activity with partner in [Canada]. The horizontal Granite Wash activity, our first operated Granite Wash well the Hostetter 1-23H in Wheeler County, Texas, came on production in late September and continues to produce at a gross rate of 9.5 million cubic feet of gas per day with 600 barrels of liquids. Addition drilling continues confirming the potential of our interest covering over 200,000 acres across the play. And then finally the acquisition of the Marathon interest in the Permian Basis gives us some 200 quality in fill development locations for oil in a core area. Moving on to 2010, as we look at 2010 we’re going to increase our activity level across North America. The benefit of our very deep portfolio of acreage across the continent which is primarily HBP is that we can adjust our focus to any number of plays as the circumstances dictate. I will now outline our current 2010 North American operating plans. It should be noted in, I think this applies across our international regions as well, that while these are our current plans, we will continue to be a nimble value driven organization that will adjust our plans as necessary through the year to maximize value creation for our shareholders. In 2010 we plan to run an average 26 drilling rigs in North America, nine in the central region, seven in the Gulf Coast region and five each in the Permian and Canada regions. We currently plan to drill 413 net wells in North America for this year, that will be up from 282 in 2009. Of this 2010 total of 381 will be development wells and 32 exploration wells. On the development side we expect to run 22 rigs, the top drivers of this activity will be in the following four programs. First our development in the Horn River Basin in Northeast British Columbia with our 50/50 partner in Canada. As mentioned earlier we drilled 42 gross wells in the Horn River Basin in 2009 while only completing four. With our pad style developments we are significantly more efficient if we drill all of the wells on the pad before we start completion operations. The 2009 completed wells were the result of the last four wells on the EnCana operated 70-J pad. EnCana drilled an additional 11 wells on their 76-K pad and another five wells on their 63-K pad by the end of the year. Meanwhile Apache drilled 16 wells on our 70-K pad and an addition seven wells on the 52-L pad during the year. We began completion operations on the Apache operated 70-K pad with 16 wells in January. We are now approximately one third of the way through our frac stimulation program with more than 90 fractures complete. We expect to get another two pads done with 25 to 28 gross wells completed before the end of the year. So in all we would expect to have 42 to 44 additional wells on production by the end of 2010. There is a little play in the timing as we continue to experiment with the number and sizes of fracs per well to optimize future development. Our efficiency continues to improve through the program and we have completed as many as four fracs in a 24 hour period on several occasions. As our drilling activity continues we expect to leave 2010 with more than 30 wells drilled and ready for completion in 2011. We are targeting a 2010 exit rate of more than 100 million cubic feet of gas per day net from the Horn River but most of those volumes will be coming on in the second half of 2010. As Steven mentioned during 2010 we expect to conduct a feed study for an LNG plant operated by Apache on the west coast of Canada at Kitimat, British Columbia. This facility if we decide to proceed with it could allow export of significant gas volumes from the Horn River Basis as well as other Apache plays in North America. Second, our continued development program in the Gulf of Mexico shelf, we currently plan to run an average of four rigs through the year on development plays and drill 29 development wells here, up from 17 last year. Our activity in the Gulf this year is off to an excellent start with positive results on all eight wells drilled so far. For perspective the developments associated with those successes alone will generate a net present value of over $120 million with a 67% after-tax rate of return on some $95 million of expected capital invested. Third, our horizontal Granite Wash development program is expect to involve an average of five rigs during 2010. We have 29 gross wells, 17 net, in our 2010 plans, up from seven net wells last year. With our success to date, we are already planning to increase activity to 25 net wells for 2010 and we’re targeting a year end net production rate of 75 million cubic feet of gas per day from the Granite Wash. And then finally our oil focused Permian development drilling program will involve an average of five rigs for the year and 171 net wells, almost double the 87 net wells we drilled in 2009. The remainder of our development activity in North America will involve an average of eight rigs for the year and 126 net wells across 12 programs ranging from East Texas [inaudible] plays to oil targeted plays in Canada, Oklahoma, and Kansas. Our activity levels in these 12 other programs will be somewhat reduced from the 133 net wells in 2009, these being primarily conventional plays as we concentrate this year on development of those top four programs I just outlined. To give you a sense of the materiality of the 2010 development program, we expect it to provide a net contribution of 52,000 barrels per day in 2011, the first full year of production, with 83% of that volume coming from the top four programs. On the exploration front, we will be significantly increasing our North American exploration activity in 2010. We plan to run an average of seven drilling rigs on this activity during the year and drill 32 net wells, up from 12 in 2009. We will pursue eight different exploration programs representing a balanced range of continuing trend exploration in the Gulf of Mexico to new plays involving horizontal drilling in a number of offshore locations across the continent. We are not in a position to talk about most of these for now due to commercial sensitivity. One development we can note is in Eastern Canada where we have completed a transaction with Corridor Resources under which Apache will fund the testing of potentially large unconventional resources in New Brunswick, close to the East Coast population centers in Canada and the US. We will drill and operate at least two wells in that play during 2010. We have good reason to believe that the exploration programs we are advancing in 2010 will have the resource scale equivalent to or greater than the plays we are now moving into development in the Horn River and Granite Wash. On an organizational front, as a final note in North America we have created a new regional unit for the Permian Basis. The Permian Basin has been part of our Tulsa based central region over the last number of years. We are one of the largest producers in the Permian Basis. The new regional organization will be based in Midland, Texas. We put these two regions together in 2002 but due to our growth over the years, that combined capital program has increased tenfold today. We think separating them will continue the growth in both regions. You will see the performance of these two regions reported separately starting in the first quarter of 2010. And with that I’d like to turn it over to Rod Eichler who will discuss our international activity. Rod Eichler : Thank you John, Apache’s international regions reported excellent results in 2009 highlighted by outstanding exploration and development activity and by seeking out and entering into new markets to sell future production of natural gas in Australia and Argentina at more attractive prices. Production in our international regions grew by 21% in 2009 to a yearly average 300,000 barrels of oil equivalent per day driven by drilling successes and significant increases in Egyptian oil and gas production, as well as significant increases in Australian gas production. Our Egypt region had another outstanding year. Net production averaged 152,600 barrels of oil equivalent per day, an increase of 38% over 2008. For the year Apache drilled 164 wells in the western desert including 23 wildcats. Once again making Apache the most active and successful operator. Fourth quarter drilling successes in the AEB at Phiops and [inaudible] 2-X in the Faghur Basin along with successful completions in the [inaudible] concession in the Jade Field and at Falcon helped drive gross production to record high 316,000 barrels of oil equivalent a day at year end. Apache’s Australia region production in 2009 increased 40% to 40,400 barrels of oil equivalent per day driven by the restoration of our Varanus Island facility. Apache took a large step forward in 2009 towards securing new markets for its Australian natural gas by agreeing to produce our estimated 2.1 TCF of natural gas reserves at our [Julemar] discovery through the Wheatstone LNG facility operated by Chevron. We expect to complete the feed study and make final investment decisions in 2011. First production is scheduled for 2015. North Sea production averaged 61,400 barrels of oil per day in 2009, an increase of 2.5% over 2008 levels due to increased production from several wells drilled in early 2009 and higher production efficiency for most of the year. During the fourth quarter we experienced reduced production at [Forties] Field due to pipeline riser repairs on Bravo platform which have since been completed. Our North Sea region actually had its second consecutive year of production growth. This is remarkable achievement in a 35 year old oil field, the largest in the North Sea, which had been in decline for many years before Apache took over operations in 2003. We drilled 17 wells and added 9,200 barrels a day over the year. The Forties [Starling] 6-3 well completed in June has already recovered 1.3 million barrels of oil and the Forties Alpha 4-5 well completed in January is still flowing water free at nearly 5,000 barrels of oil per day and has reached cumulative production of 1.7 million barrels of oil. In Argentina we drilled 32 wells with a 97% success rate. Net production for 2009 averaged 45,500 barrels of oil equivalent per day which was 5% below 2008 due to a reduction in capital spending in 2009 and lower seasonal takes by customers in the fourth quarter. However there were two important events for Apache that occurred in Argentina in 2009. First was successfully extending the life of all of our concessions and [inaudible] from 2017 to 2027. Second we received approval for four gas plus projects which will allow Apache to sell significant quantities of natural gas at higher prices in the future. Looking at 2010, we are forecasting a very active development and exploration program across our international regions. We expect to run an average of 28 drilling rigs in our core areas over the year. We plan to drill 299 gross or 249 net wells which is up from 248 gross or 213 net wells in 2009. Of these 299 gross wells in 2010, 223 or 188 net will be development and 76 gross wells or 61 net wells will be exploratory. In the development area I’d like to highlight four major programs driving our drilling activity in 2010. First we will continue the full field development water flood programs in Egypt at the [Hebba] and the [Sala] Ridge field and East NEAG which will involve six rigs and 111 wells of which 55 are producing wells. We presently produce about 70,000 barrels a day gross from our secondary recovery projects in Egypt. Secondly we’ll continue our Cretaceous and [inaudible] oil and rich gas development projects with our greater [Khalda] area in Egypt employing six rigs, drill 33 wells. Thirdly, our Forties oil field development program in the North Sea will employ two platform rigs and a jack up to drill 15 new wells. Among the new developments in our mall discovery from the fourth quarter of 2009 which we are progressing to achieve first production of 5,000 barrels of oil per day by mid year. Lastly our gas plus development programs in Argentina will average three rigs, drilling 21 wells in 2010. Gas plus developments will be our drilling focus in the [inaudible] basis as these will benefit from sales prices of $4.10 per million BTU on 10 million a day contracts for 2010 and $5.00 per million BTU on 50 million a day contracts beginning in 2011. Additionally we are presently progressing three new gas plus contracts for approval. I should note that the first three of these four largest development programs all target oil. The remaining 43 development wells are spread over six different programs across our core areas and are also focused primarily on oil. We expect this development drilling program for the year to grow to contribute around 50,000 barrels of oil per day of new net production by its first full year of contribution in 2011. During 2010 we’ll continue to progress other material projects in our longer term growth pipeline. Projects that have resulted from exploration discoveries in prior years. The first of these will be production from our Van Gogh and Pyrenees projects in Australia which are expected to contribute 40,000 barrels a day of net new oil production. As we reported earlier this week Van Gogh has already started production. These volumes are incremental to the contribution from our development drilling program that I just outlined. Ongoing projects in Australia include the Reindeer, [Haliard], [Masident], and [Julimar] gas developments and the [Coneston] oil development. In Egypt expansion of our oil gathering and transportation facilities as a result of our 2009 Faghur Basis discoveries at Phiops and [West Kalabsha] will be complete by the fourth quarter. The capacity of these new facilities will allow for ramp up of production from the current gross 9,000 barrels of oil per day to 40,000 barrels per day of gross production. Additionally construction of the fifth gas processing train in our Salam gas plant is expected to commence by year end. With this very active development and production infrastructure program we expect 2010 to be another year of robust production growth for Apache’s international regions. And the many ongoing projects represent significant sources of new production that will come on stream between 2011 and 2015. In international exploration we expect to run an average of 10 rigs during 2010 and expect to drill 76 gross and 61 net wells, 39 of these wells will be in Egypt where we will benefit from a decade long consistent new field discovery rate that allows us to bring on production very quickly due to our wide operational reach across the western desert. In 2010 we are focusing our exploration drilling on the oil and rich gas condensate prospects of the AEB and [Jurassic] formations in our concessions covering four western desert areas; the Faghur Basin including the Phiops [inaudible] areas, the [inaudible] structure trend, the Abu Gharadig basis and the [inaudible] basin. Additionally we are setting up future exploration drilling programs with the planned acquisition of 3000 square kilometers of new 3D seismic and five surveys covering 10 of our concessions, a 70% increase from our 3D acquisitions over 2009. Our proprietary 3D coverage of the western desert now exceeds 30,000 square kilometers. In Australia we expect to drill 19 exploration wells, focusing on our significant offshore acreage holdings in the [Kanarvin] basin of the northwest shelf. The program will be principally focused on new prospects in the [Julimar] field trend in support of our Wheatstone LNG project participation and the [inaudible] [Haliard], [Harriett] and [Masedon] areas in support of our domestic gas supply projects. Additionally we expect to acquire 1400 square kilometers of 3D seismic and five surveys including a benchmark 40 survey in the [Coneston] Van Gogh field areas. In Argentina where we did not drill any exploration wells last year as we focused on building was a very interesting portfolio of diverse plays across the country, our 10 well exploration drilling program this year will target impacted prospects or pre [Cujo], [Cujo], and Springhill reservoirs in each of the new [Concujo] and [Astrail] basins. In the North Sea we will resume exploration drilling near the Forties field complex with three wells after two years of primary focus on development drilling. To summarize our international exploration program for 2010 we will conducting an impactive exploration drilling program across our core areas that will target an aggregate of nearly 290,000 million barrels of oil equivalent of list mean net reserves. We will acquire 5500 square kilometer of proprietary 3D seismic in support of future exploration and development activities and we will progress key infrastructure projects in Egypt, Australia, and the North Sea to provide for continued production growth in 2010 and future years. And with that I’d like to pass it over to Roger. Roger Plank : Thank you Rod and good afternoon everyone. What a year, a tale of two cycles, financial armageddon followed by a recovery that’s surprised virtually everyone in the spring. What started out as a downright scary year ended with $1.9 billion of adjusted earnings or $5.59 a share for the year. Fourth quarter adjusted earnings more than doubled the $664 million or $1.96 per share from the fourth quarter of 2008. And they were the strongest earnings of the year. Who would have thought it. Cash from operations were just shy of $5 million for the year and over $1.4 billion for the quarter. Compared to our initial plan the cash flow was 36% or $1.3 billion higher enabling us to increase drilling capital by $350 million and acquire $300 million of properties while still living within cash flow. Our 9% production growth despite 40% less capital speaks to the benefit of our long-term approach. Clearly this growth could not have been achieved if not for first production from a number of significant long-term development projects. Exploration success continues to add to our pipeline of development projects providing growth visibility that can really move the needle once brought online. Despite higher production and substantially reduced capital Apache added 215 million barrels of oil equivalents through drilling and acquisitions outpacing production of 213 million barrels of oil equivalent at a cost of $3.5 billion. These additions were added at $16 per barrel of oil equivalent and were quite economic as some 40% of our additions were oil. At $70 a barrel oil sells at 14 times the price of gas leaving plenty of profit margin. This growing disparity between the value of oil and gas underscores Apache’s advantageous product mix. Oil and NGL comprised half of our production with 72% of our 2009 revenue. We talk a lot about our balanced production mix but I think its often lost just how valuable oil really is to us. Our 50/50 production mix generated last year $8.6 billion in revenue. To get the same revenue if we were all gas we would have had to produce 2.3 TCS or twice what we actually produced. The point is our oil production is incredibly valuable to us. Earn in natural gas also held up quite well because its not tied to volatile North American spot prices. In fact while North American realizations declined by half in 2009 our international gas price dropped less than 20% coupled with 25% production drills, our international gas revenue actually climbed 5% to $770 million. Prospects are excellent for our international gas revenue to continue to grow as once [trend] gas rises toward world prices. With international contributing 51% of our total productivity Apache is the leading independent international producer in our peer group and we think that gives us a competitive advantage both in terms of finding more oil in the future and benefiting from rising international gas prices. Finally in 2009 against our number one priority to live within cash flow Apache ended the year with just over $2 billion of cash on the books versus just under $2 billion in 2008. I would note that this was accomplished without having to issue equity at or near the bottom of the market. That having been said the real question is what’s next. Now that the world economy is no longer dangling so close to the precipice of financial ruin, we’re going to step it up a notch. We plan to increase the [inaudible] capital by about half to $6 or $6.5 billion which we figure roughly approximates 2010 cash flow assuming prices of around $70 a barrel and $5 per MCS. As usual Apache will reassess our capital budget on a quarterly basis and adapt accordingly. Capital spending including for GDP facilities and T&A is forecasted to be split evenly between North America and international with significant increases in 2010 are in drilling as activity ramps up to more typical levels and in facilities with our large projects progressing in Australia, Egypt, North Sea, and Canada. The largest increases will occur in the US after splitting our central region and in Canada and Australia. You can find capital spending details by country on our website under the supplemental financial data section that Tom mentioned. Given our increased budget for 2010 we currently have hedged approximately 40% of our year end North American gas production, 225,000 MMBTu per day is hedged with swaps averaging around $5.80, and 84,000 MMBTu per day is hedged using [collars] with average floors and ceilings of around $5.50 and $7.00. We’ve also hedged 150,000 gigajoules per day of our Canadian gas production with swaps at an average of around $5.35 in Canadian dollars at [payco]. On the oil side we haven’t been quite as aggressive. We’ve hedged just over 10% of our worldwide liquid for an average of 35,000 barrels per day for 2010, approximately 80% represents collars with average floors and ceilings approximating $55 and $81 a barrel. The balance is swapped at an average price of just under $69 a barrel. We’re also actively screening acquisition opportunities and while we are not in hot pursuit at the moment it is apparent that our industry’s acquisition pipeline is fine. In addition to our $2 billion of cash, $2.3 billion of undrawn credit lines, leave us a combined $4.3 billion of firepower. This an a low 24% debt to cap provides considerable flexibility to act on either incremental drilling or acquisitions should attractive opportunities materialize. With respect to costs we currently forecast slightly higher cash costs including taxes other than income but I will tell you our goal is to keep them flat with 2009 average of around $11.25 per BOE. With a strong financial position, solid oil prices, international gas prices trending higher and projected production growth of 5% to 10%, the current outlook for 2010 is quite favorable. Steven Farris : Thank you Roger, I’d like to close by summarizing what I think are the three main messages of all the information that all the gentlemen have shared today, the first is 2009 was a good year for Apache. We had strong growth in a challenging environment with restricted capital and well count. We really owe this to the performance and hard work of our team and their focusing on generating growth and value. The second message Roger just mentioned is that we expect to have 5% to 10% net production growth in 2010 and I might add in addition our development drilling program will deliver 100,000 barrels of oil equivalent per day by the first full year of its contribution in 2011. And third we built a well balanced global portfolio of growth areas for the long-term. The diversity of our 2010 operating plans outlined by John and Rod I think reflect that. So 2010 is going to be a very busy year for Apache. And with the organization and opportunity set there’s much more in front of us in the years ahead. So before we go back to work, we’d be ready to take your questions.

(Operator Instructions) Your first question comes from the line of Bob Morris – Citigroup Bob Morris – Citigroup: I have a question looking at your findings about cost and reserve replacement by region, Canada was by far the best region in terms of both reserve replacement and finding costs even after revisions, and that’s been a challenging region for other companies out there. Was the strong extension and discoveries that you booked in Canada, the result of a lot of floods being booked at Horn River or what drove that. Steven Farris : I might open it up, Horn River is our big play. We had some flood drilling locations that we drilled this year and basically we have one year of drilling, a pad drilling program for 2010 started up. But we really didn’t change the way we looked at our business. If you looked at our overall portfolio our [pads] are up 3% year over year. Bob Morris – Citigroup: So most of the extensions in discoveries you booked in Canada were [pads] at Horn River. John Crum : Yes that would be correct. But the real point we’re making there is that we haven’t really got ahead of this year. We really just pudding up the next year’s drilling program. Basically an extra pad alongside the pads we’ve already drilled. Bob Morris – Citigroup: And the revisions that you recorded in Egypt, were those all associated with the PSC contracts essentially. Rod Eichler : Yes, that was all price. Bob Morris – Citigroup: I know you had a great year in Egypt with all the exploratory and drilling success, the oil price that you did those adjustments on or the PSC contract was based, looks like about $63 a barrel, yet you’re finding development costs in Egypt was over $31 a barrel, and I just wanted to get you comments on the economics of that because I would have expected perhaps a lower finding and development cost, that oil price given the success that you had in Egypt. Steven Farris : I will tell you what happens, because of the oil price you get a real, when you say what we booked, what we booked is the same thing that’s happened to us on a revision side frankly because you have to run that through the PSC. If we had $40 a barrel your finding cost probably would have been a third of what they are today. And it really is a very economic place because what happens is is that you get all your costs back in four years. So you’ve got to be real careful whether we show really good finding costs or we show really high finding costs in Egypt that if you run it on one price or you look at it on a gross oil basis, it would be much better off if you understand what I’m saying. Bob Morris – Citigroup: Yes because I was looking at $63 per barrel was the price you had to base your bookings in the PSC on and the finding cost is running about a little over 50% of that oil price which is the basis for your bookings which I would have expected it, the finding costs to be maybe a third of what oil price basis was. Steven Farris : But you see the problem is your reserves and I’m sure Tom can answer this, you run your reserves through the total PSC to come up with what your extensions are. Just like the base, so it effects not only your reserve revision but it also effects the amount of reserves you book. It’s a timing difference. Rod Eichler : The only thing I would add to that is that you have to take into account that you have a cost recovery mechanism of the PCS in that you have a large balance of costs are constantly growing forward and that’s a big difference on one quarter to the next on one year to the next depending on how much money is in that pool from your prior year spending. And additionally the cost recovery Steve mentioned was prior to capital expenses over 16 financial quarters, you’re operating expenses were recovered were [inaudible] over four financial quarters or one year. So it’s a complex mechanism because of the PSC. Basically when prices are up we lose revenue interest on our share. When prices are down we benefit in the opposite direction.

Your next question comes from the line of Brian Singer - Goldman Sachs Brian Singer - Goldman Sachs: I wanted to get a little bit more color on the Permian basin especially since you’re now going to be designating it as a new unit, can you talk about the materiality of your program for this year and whether that’s an area that you expect to grow solely organically or whether that’s in your outlook for additional, maybe larger acquisitions. John Crum : I think that’s one of those places we’d like to do both in. We’ve got a number of interesting exploration ideas that we will be trying over the next year but its certainly an area we’d like to grow by acquisition as well. Its been good to us. We’ve got a good operating group responsible for it and we think we can grow that region for years to come. Brian Singer - Goldman Sachs: And what do you expect to be your contribution from this year’s program and then similar to how you were presenting the contribution to year end or 2011 barrels a day. John Crum : I’d probably have to get back with you on, I didn’t break that out here but you can imagine the primary program out there that we outlined for you was in full development program so I would expect any activity we get out of exploration won’t be showing up really until 2011. Brian Singer - Goldman Sachs: And then looking at your capital program which I think you mentioned was based on $70 oil and $5 gas, if oil prices do end up averaging $75, $80, $85, would you look to increase capital budget and where would be your priorities oil, gas regionally for incremental spending. Steven Farris : I think our mantra is we’d like to stay around our cash flow and if we see just like this year frankly, we spent more money that we started out. I think we started out at $3.5 billion and we ended up spending I think $4.1 billion or thereabouts. If we see higher oil prices and higher revenues, net cash flow we’ll spend more money. And that probably will come in several regions, Australia is pretty well set just because of the rig activity and but we certainly could spend more money in North America and in the central region. We could spend more money in the Gulf of Mexico. Actually we could spend more money in each one of those regions and then we could also spend more money in Egypt. Brian Singer - Goldman Sachs: When should we expect or what timing are you looking at for selling any off take for Wheatstone gas contracts. Steven Farris : 2015. Brian Singer - Goldman Sachs: In terms of when you would actually sign a contract— Steven Farris : That would likely take place prior to final investment decision before mid year 2011. We’ve got to be real careful were not [inaudible] that back, so we probably know some things that we’re just going to have to defer to the operator.

Your next question comes from the line of Joe Allman - JPMorgan Joe Allman - JPMorgan: Just a question on reserves again, in terms of your and again on revisions, on your total revision and I know its complicated somewhat by the Egypt production sharing contract but your total revisions, what was the percentage of prove developed revisions and the percentage of [pud] revisions. Steven Farris : Well we don’t have our Vice President, Executive Vice President of Corporate or Engineering here we’re going to have to get back to you on that. All of the revisions were priced and I would imagine a big chunk of them were proved developed. But I, that’s a guess. Joe Allman - JPMorgan: In terms of the reserves acquisitions, you made in 2009 you bought some reserves, I think it was mostly in the US, was it mostly prove developed or [puds]. Steven Farris : Well actually that’s the only one we really made of any size was Marathon and that’s probably 70% or 75% proved develop producing. Joe Allman - JPMorgan: And on New Brunswick, are there any results in New Brunswick to speak of either by you or any other operators. John Crum : Well the operator has come out with a little bit of information on a test they did last year, but we really feel like we need to get in there and they did a vertical test last year and we were pleased enough with the results there that it made us go ahead and take this opportunity. But we’re going to draw horizontal wells this year and actually test the concept. Joe Allman - JPMorgan: And then you made a comment about the acquisition environment and I missed what you said, what is the acquisition environment look like these days. Roger Plank : Well I basically said two things, we’re not in hot pursuit of anything in particular at the moment, we’re just hearing of more things and so its our sense that the pipeline of acquisitions is beginning to thaw now that the world isn’t coming to an end.

Your next question comes from the line of Doug Leggate – BofA Merrill Lynch Doug Leggate – BofA Merrill Lynch: I have a couple of things I wanted to go through, jumping right to Egypt your production obviously is bumping up pretty close to your target that you set a few years back, can you talk a little bit about was the ramp up in exploration drilling with the Salam 5 plant, just generally in terms of the overall prospectivity of the western desert particularly on the oil side, what exactly do you see the production potential moving over the next few years. Rod Eichler : As you know the numbers we put out for 2010 we’re looking at a program drilling wildcat drilling program that’s kind of back to our “normal” levels which runs around 30 wells a year. So its about 30% increase over, or 50% increase what we had in 2009. We have a even though we completed our Salam gas rigs 3 and 4, last summer, we have continued drilling successes through 2009, we still again find ourselves in a situation with the need to add more processing capacity to the western desert by building this fifth Salam gas train which we intend to initiate construction by year end as I indicated. We have a lot of gas behind pipe as well as oil and these are condensate rich gas zones that have yet to be produced so it’s a matter of when you want to get it out and if you could live with the current facilities and stretch it out over many many years but we have a lot of near-term opportunities to increase net present value of that gas by producing it sooner as opposed to later. Of course the government of Egypt is very interested in adding more processing capacity to accommodate the additional production because of the almost insatiable gas demand in the country of Egypt which continues to grow about 11% or 12% annually. So we have a very robust inventory of prospects, drilling about 175 to 200 wells a year and the exploration prospects continue to spawn additional development drilling year by year. There’s been kind of a consistent pattern for the last decade, we’ve been drilling now some 16 or 1700 wells in the country and are successful on exploration development is very consistent year on year. Doug Leggate – BofA Merrill Lynch: What I’m really kind of working out here is you’re going to drill 30 plus exploration wells this year what is the, if you could talk to the backlog of what have you actually got in Egypt in terms of longer term potential. There seems to be a lot more oil as you have talked about and I think has a lot of geological [inaudible] in the western side of the desert, so it looks like you’ve got a lot of oil prospectivity there and I guess if you could overlay on that, what is the horizontal potential in that region and also I guess you’re going to have to reset your target at some point because you’re getting pretty close. I’m really trying to get a feel for is that incremental production going to be oil and if so what are you really see as the potential of this area let’s say in another three to five year target. Rod Eichler : The first part of your question with regard to the oil prospectivity, what we’ve observed is our recent drilling programs moving westward toward Libyan border and the Faghur Basin area west of our main properties base, is that things appear to be more oily there. Perhaps because its cooler from a geological sense but clearly the wells we’re making there are oil wells. And they’re oil wells that are deeper than you’d normally see in that part of the desert. Our backlog of our inventory we are looking continually evaluating, assessing prospects are developed off of our very large seismic inventory. In fact we’ve been reshooting some of the areas, our main producing area that we’ve shot a decade ago and the data quality now has been amazing in turning up even more and more ideas. Whether its on exploration projects or production enhancement projects or work overs, we have the, every year we have this inventory of maybe like 300 production enhancement projects and then we do the jobs, the next year we still have 300 production enhancement projects to do. The work continues to spawn other ideas and other work whether its on the exploration side, the exploration drilling, or the development of production enhancement activity. Now as far as horizontal applications, activities for horizontal exploration in Egypt are really not even touched. And we are beginning to investigate through horizontal drilling certain formations, certain reservoir sequences that we think could be applicable to such and but many times these things have been done for years in North America and they just now arriving on shore in Egypt. There are no known horizontal plays operating in the country but we’re looking to see what we can do in that area from what we know from North America activity. We have four horizontal wells planned for 2010. Doug Leggate – BofA Merrill Lynch: I guess I’m not going to get the answer on the three to five year production targets, the only other one I have, moving to North America, I hope I’m not touching on any sensitivities here but the Horn River is obviously one thing but you have been pretty active right next door in the [inaudible], I’m just kind of wondering if you can give us any update on your activities or your plans on what you’ve seen so far and how that has played into you decision perhaps to get involved in Kitimat. Steven Farris : We’re buying a lot of acreage in a lot of different places in the world and Canada happens to be one of them. So that’s pretty much what our position is going to be there. Doug Leggate – BofA Merrill Lynch: The likely timing of when you start to see gas plus in Argentina start to [inaudible] those realizations and I’ll leave it there. Rod Eichler : The first contract which was for the 10 million a day, that actually started last month in January.

Your next question comes from the line of David Tameron - Wells Fargo David Tameron - Wells Fargo: A couple of questions, let me start with you mentioned a five and 70 that you’d be generating, did you say you’re going to generate 6 to 6.5. Roger Plank : Roughly. David Tameron - Wells Fargo: If I’m looking at forward guidance if I put, if I just look at margins, to generate $6 million at five and 70, [inaudible] is flat, are there any other changes as far as any other components that are moving significantly because it seems like that implies a higher margin for next year. Roger Plank : That flat that I mentioned excludes taxes other than income and so when oil goes up we get hit in the North Sea with [inaudible] CRT so that’s probably works a little bit against what you’re saying but in general you’re probably on track. David Tameron - Wells Fargo: It seems like a cost structure coming down a little more next year. You’re excluding the impact of taxes is that accurate. Roger Plank : Our cash cost per unit probably are going to be, we’ll, as I indicated we’re going to target having it flat excluding the CRT and other taxes other than income. So wouldn’t have more production, we’d probably see a little higher costs but when you spread it out over more production DOE will be up, if we hit our target it will be flat. David Tameron - Wells Fargo: You talked about the Permian basin have you started doing any horizontal work down there yet or anything on that front as far as activity to apply that technology down at the Permian. John Crum : Yes we have as Rod indicated on his work in Egypt, we’ve also doing the same thing in the Permian basin picking out targets and doing some of that drilling. We’ve actually have a horizontal well being completed as we speak in our [inaudible] Lake unit so, that will be a fairly active play for us down in the Permian this year because we really want to see what kind of potential we have in the large acreage base we have down there. David Tameron - Wells Fargo: And that’s just going to be an ongoing program throughout the year, we may hear something later in the year. John Crum : Absolutely and I hope you hear a lot about it later in the year. David Tameron - Wells Fargo: In Egypt, as you move west is there any I know you announced an agreement today but as I think about historical Apache to the kind of the western desert, and some of the oil exploration is there any difference in the cost recovery mechanisms or anything you can share. Rod Eichler : The cost recovery mechanisms of course can vary from concession to concession because each is an individual law. However for Apache’s concession, the 22 concessions we have the variance between the concessions is very, very small. Roger Plank : With the exception of one and that’s [Karoon] and the production is— Rod Eichler : We have no shared excess cost recovery in [Karoon] and at north [Eldiau] are very tiny concession. All the rest of them have shared excess and very favorable physical terms in terms of profit splits. Renewal terms, the two that we just renewed, very importantly the called offset that was a seven year extension, that we had approved by the government. East [Baharia] it was a three year extension. Called offset is very important to us because it’s the home of one of our bread and butter operations historically and this will be unlike a typical exploration concession that you’d be granted in the country, there are still relinquishment associated with the seven year, the block seven year term to do all that work. Roger Plank : And the splits don’t generally change. Rod Eichler : The splits stay the same, they’re the same base physical terms as we had from the original concessions.

Your next question comes from the line of Ben Dell – Bernstein Ben Dell – Bernstein : I just had one quick question, you’re obviously ramping up your capital program a lot and I was really wondering how much is your rig cost and service costs have you got locked in going into 2010 particularly I guess in the US on shore business given the horizontal rigs right now. Steven Farris : I think there’s very little right now, perhaps the only place that may not be that way is in the Gulf of Mexico where we usually take a longer view of our jack up rigs, but certainly the land rigs in the US we still believe they’re going to be flat because the vast majority of things that are drilled in the United States today are still gas. And I think gas was down [$0.03] today so I doubt if you see a real surge in rig rates here at $5.12 gas.

Your next question comes from the line of Brian Lively – Tudor Pickering Brian Lively – Tudor Pickering: Just a question on the Granite Wash, given your vertical well control can you give some color on variability in reservoir properties across the play both laterally and then within the major productive horizons. John Crum : I don't know how much color I can give you, but you’ve called on a key point there, clearly across the entire Granite Wash play there’s a variety of numbers of sands available for development and different yields we would expect out of those. So we obviously have a pretty good feel for what we’d see in some of the areas that we’ve drilling for years out there and so we’re concentrating on those areas that first of all would have the highest liquid yields, with that said we’re going to be a lot of work around really trying to set our entire position out there over this year. So you should expect us to be very active in that Granite Wash play across our entire acreage position this year. Brian Lively – Tudor Pickering: We talked, we’ve heard about the [Marmeton] and the [Etoka], but what are the other intervals that you will be pursuing in the coming year. John Crum : We’ll have [Marmeton], [Etoka], we’ll have, we talk a lot about the Granite Wash A, B, we talked about the Caldwell. We have a variety of them that we’ll be testing this year and really the interesting piece for going forward on this play in my opinion is getting to the point where we could actually get where we could do multi laterals and develop more than one of these intervals in the same well bore. But we’ll be trying that concept out too. But I think that’s where the future is. Brian Lively – Tudor Pickering: You are going to try multi lateral in 2010. John Crum : Absolutely. Brian Lively – Tudor Pickering: Switching over to the Horn River have you tested both the [Muskwa] and the [Clua] intervals. John Crum : Yes we have. On our present, we have one well completed in, well we actually have two wells completed at [Clua], the first one is a vertical well but we have one horizontal well completed in [Clua] from 2008, however we were somewhat compromised on the frac jobs we got on it and we only got four frac jobs out of it. It is about half as thick as the [Muskwa] so we won’t spend as much time on that because if you’ve got certain number of rigs running you’re going to go after your bigger targets first. But I will tell you we’ve got two wells on the 16 well 70-K pad that we are completing right now, two [Clua] wells are in that mix and so we’ll know a lot more about the [Clua] by the end of this year. Brian Lively – Tudor Pickering: And since you’ve had some run time on I know its just a select few wells but has your spacing assumptions changed any now that you have some production. John Crum : That’s what I was talking about experimenting some more out there, we’ve got a lot of activity going on, the pad we’re drilling presently are 52-L pad, we’ve actually spaced, we’ve brought the spacing between individual laterals out to two different widths. We’ve added about 80 meters to one side of the pad and about 50 meters to the other side of the pad. And that’s, the real key out here is we’ve got literally 200 pads worth of potential at 15, 16 wells per pad and so far we’ve got four of these developed so we’re trying to get the right answers on the big picture. We’ve got a lot of activity to go. In a perfect world you would get your spacing between horizontal well bores out further and put more fracs in the individual laterals and that’s what you’ll see us doing a lot more of this year, up to 20 fracs on an individual lateral. Brian Lively – Tudor Pickering: And how long of a lateral would that be for 20 fracs. John Crum : Well we’re out to 2200 meters.

Your next question comes from the line of [Marvin Hayes – CVP] [Marvin Hayes – CVP]: I was wondering obviously given cash on the balance sheet, liquidity, etc., we’ve been talking about expansion of CapEx and property acquisitions and things of that nature, with that said I’m wondering are there existing properties or plays at this point that from let’s say reach critical mass or would demonstrate superior economics compared to some of your other opportunities that may be potential candidates for divestitures as you optimize your portfolio. Steven Farris : We’re not a very good seller. Its hard enough to [find]. [Marvin Hayes – CVP]: Clearly they’re cheering I guess so I guess we should simply watch where the capital dollars go in order to assess that. Steven Farris : We certainly do, I’m always jaded by, we bought some things over from Exxon over a number of years and its always been a cat fight. The gentleman that used to be pretty influential in Exxon used to tell me, because we were arguing about 40 acres, and he said Steven, 40 acres was a lot its hard to come by so we have a little bit, not that we’re anywhere near the quality or size of Exxon but we have a little bit of the same and the reason is frankly if you look across our portfolio and I’ll give you for example, let’s take [Nebis]. It was a little shallow gas play and all of a sudden we drilled CPM wells on it and I think we probably are still producing 80 or 90 million a day out of the [inaudible] methane at [Sabah] that we really didn’t see. We’re talking an awful lot about Granite Wash, we probably got Granite Wash 500 wells. We drilled our first Granite Wash probably in the 50’s and we’re getting ready to come through there with a horizontal play that we have HBP of 200,000 acres. Or if you look at some of the things we’re doing in west Texas, horizontal wells and the water floods and all of a sudden you are able to increase production. Only acreage in real well known hydrocarbon areas really gives you an advantage especially if you’re large which is why you see us in large positions in most places that we’re in. John Crum : Even if you look at Horn River, that grew up under a marginal play for us. We added a lot of acreage but it really started with ratty old acreage that we hadn’t sold. There’s a lot of optionality in some of that old stuff that doesn’t look very attractive. It’s a hard thing to source through because it shows up in costs and you’ll wonder why you’re holding onto it and then every now and then you find something underneath it that makes it more than worthwhile. [Marvin Hayes – CVP]: In the past when we’ve looked at potential basis differentials and realization in North American natural gas the Rockies, in past historically was particularly good standing, obviously with pipeline takeaways and access to the eastern markets much of that has been alleviated. But as the [Marcelus] comes on to become a very significant material producer in the next three to four years, can you assess your North American natural gas portfolio, are there places where you’re concerned about basis differential or simply crowding out of perhaps supply that’s closer to market than you may be and how you might be thinking about potentially directing those concerns going forward. Steven Farris : I think honestly it’s a very good macro question, because as these shale plays have come through there’s absolutely no doubt that you’re going to change the dynamics in North American gas. Now what the end results of that is, I’m not real sure. Because it has a lot to do with pipelines etc. but there’s no doubt that [Marcelus] is in a favorable position. We’ve seen that frankly a little bit in the Gulf Coast with the Haynesville gas going across. Its fascinating to me that depending on the price you get basis differentials in Canada from $1.30 and its probably the lowest its been right now than it has been in a long time. And you ask yourself why. I’m not sure but I think it is generally and we don’t have an answer for it frankly right at the moment. But trust me we are very cognizant of that. But I don't know what the drivers are going to be other than closeness to the market. Roger Plank : And we’ve got to keep our costs down and that’s one advantage that Horn River play has ultimately it sets up very well geologically and that ought to be able to enable us to get our costs down and therefore suffer a bit more of the transportation and distance differential.

Your final question comes from the line of Ken Carroll – Johnson Rice Ken Carroll – Johnson Rice: Quick question back to the investor conference you talked quite a bit about your eagle your position, [inaudible] how you attempted some oil, is there any further testing in that. I think you mentioned looking to the gas window a bit. Steven Farris : We are going to be doing a little more testing this year. I will say and it’s a different area technically. Having said that so was the [Barnett] shale at one time, back when it was making 300 MCFs a day and frankly Devon had the foresight to go out there and buy it. But there will be a time and I really believe this and I don't know when that is from a technology standpoint the [Eagleford] the important thing about it is its got some of the highest per acre coal in place of any shale play in the United States. So and the important thing about that is we’ve got about 450,000 that sell by production. So we can like most of our acreage one of the reasons you don’t see us as trend setters a lot in North America is most of our acreage is held by production so we can let people do an awful lot of experimenting before we turn the technology. Same reason we’re starting to get in west Texas, there’s been a lot of horizontal wells. If you look on the map you can see that. But we have a tremendous acreage position out there that now allows us to go out there and really start exploiting our base property. Ken Carroll – Johnson Rice: But the early wells you have talked about have all been in the oil window, I thought you had mentioned at some point trying to go in the gas window, has that been done or is that part of the testing this year. Steven Farris : I’d hate to say it this way but I think we’ve got lots of gas.

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments. Tom Chambers : Thanks for joining us today and if anybody has any further questions, I’ll be in my office after the call.