Good day everyone and welcome to the Apache Corporation First Quarter 2009 Earning Conference Call. Today's call is being recorded at this time for opening remarks I would like to turn the call over to Tom Chambers Vice President of Corporate Planning and Investor Relations. Please go ahead sir.

Good afternoon everyone and thanks for joining us today for Apache Corporation's first quarter 2009 earnings conference call. As you have probably seen this morning we reported first quarter net loss of $1.76 billion or $5.25 per diluted share. Loss was the result of the continuing deterioration in north American gas prices at the end of 2008 which recorded 1.98 billion non-cash after tax reduction in the carrying value of oil and gas properties as required by the booker methodology of accounting. Just to reiterate low cost accounting rules require us to calculate the 10% discounted after tax value of our proved reserves using flat period and prices and cost for the entire life of the reserve base. As the calculated discounted value is less than our net carrying value the excess monthly written-off. The reported write down is a non-cash charge and in that way it impacts our ongoing financial flexibility. Roger Plank will provide more details in his comments. Today's discussion may contain forward-looking estimates and assumptions and no assurance can be given that those expectations will be realized. A full disclaimer is located on our website any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or costs incurred will be identified as such as the reconciliation located on our website at www.apachecorp.com. We routinely put up important information on our website and including today's additional detail on the Permian Basin acquisition from Marathon announced this morning. On today's call we will have four speakers making prepared remarks prior to taking questions. We will open up with Steve Farris, our Chairman and Chief Executive Officer followed Rod Eichler our Co-Chief Operating Officer and President International, John Crum our Co-Chief Operating Officer and President North America and concluding by Roger Plank our President and with that I’ll turn the call over to Steve.

Good afternoon everyone and thank you for joining our first quarter 2009 earnings call. Before I get into the first quarter remarks I would like to take moment and outline the format of today's call because we do have more speakers. Tom Chambers as you heard is our Vice President of Investor Relations. Rod Eichler and John Crum are our new Co-Chief Operating Officers and they will review the operating highlights and then Roger Plank who is Apache's new President will review the financial highlights for the quarter. One final side notes I would like to mention I would like to publicly thank Bob Dye who has done an outstanding job over a decade in directing Apache's Investor Relations. Tom Chambers is taking over and Bob is taking a broader administrative role within Apache. All of you saw today we announced the acquisition of the Permian oil portfolio in the Permian Basin from Marathon Oil in the Permian Basin. These long lived oil properties are a great fit for our large portfolio in the Permian and will provide us with drilling inventories for many years. I think we communicated over recent months that we are starting to see better value opportunities and this transaction is representative of that view. In the first quarter Apache's global production increased by 6% over the previous quarter which is in line with the expectations for the year. And as Rod and John will review in greater detail in a moment we had another quarter of important oil discoveries, a diverse range of basins in place. We discovered new fields in Egypt, five new fields in Egypt including three with a combined 9400 barrels of oil per day. In Australia we proved a new gas horizon in multi-Tcf (inaudible) complex. In Argentina we discovered a new field in Tierra del Fuego and we also made an important oil discovery in the Gulf of Mexico. As the entire world faces challenging times our focus is on long-term growth in our financial discipline remains unchanged. Over our 54 year history Apache's disciplined values and controlling spirit have enabled the company not only to live through down cycles but to emerge even stronger. And we are taking on that task once again. We are trying to take difficult steps as they are required. Last week we announced a painful but necessary 6% reduction on our worldwide headcount. Living within once cash flow has become a sacred mantra during the recent months. And Apache was ahead of this new conventional wisdom and continued to maintain our discipline. Importantly our portfolio allows to live within our annual cash flow at today's oil and gas prices. It is very different from living now from hedging programs and hoping for massive price rebounds over the coming months. Our view is that Apache should be able to create value consistently across price scenarios. And today is no exception. The oil and gas sector operated for many years at prices below those we experience now and have done so profitably. We believe that current downturn should serve as a reminder of the imperative need for portfolio balance and focus on efficiency in our sector. Apache has long stood out in both of these areas and often times been penalized in the market as a result. We are hopeful that the benefits of Apache's long-term strategy will be more widely recognized and more favorably accepted in the current environment. Although we are maintaining our 2009 production growth target of 6% to 14%. We expect to come in at the lower end of that range. You take into account our lower capital spending and recently the contractors delay at Van Gogh development an offshore Western Australia. If there is a silver lining in the Van Gogh delay is that we now expect those barrels to come on around the end of the year 2009 which should help our oil growth in 2010. For the second quarter of 2009 we are anticipating a 3% to 5% production increase from the first quarter volumes. And with that I think I will turn it over to Rod and John and Roger and then we will go to Q&A.

Thank you, Steve. I will provide a quick overview of main developments in international regions. Beginning in Egypt net production was 136,500 barrels of oil equivalent per day, a 10.9% increase from fourth quarter. The region achieved new daily production records for gross oil and condensate at 161,739 barrels of fluid per day and gross gas at 685 million cubic feet gas per day. On the exploration side we completed drilling and or testing operations on 9 new [wildcat] wells resulting in five new field discoveries during the first quarter. Apache has 100% contract of working interest in all of these wells. Some brief highlights on three of these new discoveries in the greater Khalda Concession area are as follows. The Phiops-1X well on Kalabsha Development Lease logged 173 feet of oil pay in the Cretaceous AEB sands and 103 feet pay in the Jurassic Safa sands. Safa sands tested at 2300 barrels of oil per day and 5.2 million cubic feet of gas per day and production commenced on April 16. Additionally two development wells are presently drilling to exploit the AEB and Safa pay season discovery well. The WKAL-C-1X was Kalabsha Concession logged 202 net feet of oil pay in the AEB sands and 17 feet of Jurassic Safa sand pay, test rates were 2900 barrels of condensate per day and 15.8 million cubic feet of gas per day in the AEB. And 770 barrels of oil per day and 3.9 million cubic feet of gas per day in the Safa. First production from the well should be in the third quarter. The WKAL-C-1X in the north concession logged 48 feet of AEB sand pay and tested 3500 barrels of oil per day and 4.5 million cubic feet gas per day. This is the first commercial oil discovery in this concession and first production is expected in the fourth quarter. The remaining two field discoveries will be tested over the next few weeks separately we are currently drilling two new Jurassic wildcat wells at Falcon and Chassis. On the development side I would like to note that commissioning and start up of this gas plant trains three and four and Northern Pipeline Compression projects is progressing. Upon completion around June 1 and for the balance of the year we expect gross gas production from the concessions to average 730 million cubic feet gas per day, a 34% increase from the 540 million cubic feet of gas per day at the beginning of the first quarter. I should note that just before this call we learned that the Northern Gas Compression project has been fully activated and is in operation. In Australia, net production was 31,500 barrels of oil equivalent per day, a 13.7% increase over fourth quarter. On the exploration side we drilled two wells in the multi-Tcf Julimar and Brunello complex. [Broken Wood] one was drilled to investigate two previously untested channel sands on the formation. The well encountered 21.8 meter of net gas pay in the. Broken Wood two found 11 meters of net gas pay in the G.30 sands. These two wells together confirmed the presence of a significant gas resource in this prolific area. In March, Apache together with impacts completed the purchase of BHP equity in two undeveloped oil fields in the sub basin. Apache's interest increased from 31.5% to 45.7% in the undeveloped [Kanister and Nuvara] fields. Apache will operate and subject to successful appraisal these fields may be developed utilizing nearby Van Gogh FPSO. Turning to development of facilities project we had a very busy quarter in Australia. The Devil Creek development project for the Reindeer fields launched with the signing of the CP mining gas sales agreement in January. Work has commenced on the onshore gas plant under contract issue to do inclusive projects Australia. Offshore construction contracts will be issued by the third quarter and we anticipate first production in 2011. The Marina's Islands repair program is nearing completion. We have consistently produced 273 million cubic feet gas per day off the island since the beginning of March and we expect to raise the overall deliverability to 382 million cubic feet gas per day by the first week of June, significantly exceeding the pre-incident rate of 390 million cubic feet gas per day. As we announced April 14, Prosafe, the developer of the FPSO we have leased to service our Van Gogh oil project informed us they have had a fire incident in the control rooms on the vessel. The investigation teams have completed their on board inspections and site clean up has commenced. The cause of the fire is yet unknown. Prosafe is pushing vendors for accelerated delivery times on replacement equipment. Based on information available to date we estimate first production at Van Gogh around year end. In the North Sea net production averaged 60,900 barrels of oil per day a decrease of 2% from the fourth quarter, due to vessel overhauls and unplanned pipeline repairs. Before repair downtime however production was up a net 1800 barrels of oil per day. On the drilling side we completed four successful oil development wells during the quarter which are currently producing 8500 barrels of oil per day, of note is the 4-5 well which accounted 26-meters of pay and is producing 5,000 barrels of oil per day water free. We are currently completed additional two successful development wells and will be on production in May. Production efficiency of the Fortis field was 90% during the quarter a 31% field wide gain since our acquisition in 2003. As of today the field is operated a record 224 days without a seas export interruption in production. Starting May 2 Delta platform which makes 16,000 barrels of oil per day shut down for a planned 16 day plant turn around. Turning to Argentina, net product was 47,600 barrels of oil equivalent per day, 4% down from fourth quarter. But without any decline in hydrocarbon liquids product. In the Neuquén province Apache finalized extension of eight federal development blocks representing 590,000 acres for ten additional years. These leases presently produce 7,000 barrels of liquids per day and 100 million cubic feet of gas per day. With this move we extend the producing acreage base from 2,016 to 2,027. Apache paid a bonus of $23 million, increased the provincial loyalty rate from 12% to 15% and committed to do a $320 million work program over the next 19 years. Also in the Neuquén province there was continued success in the drilling of nine wells in the deep gas fields at Ranquil Co and Guanaco. These fields these wells tested between 3 million and 7 million cubic feet of gas per day. Apache also had a new oil base in position to its portfolio with awarding of the crucial CCyB 17 B block in the Mendoza province. New block consists of just over 1 million sparsely drilled non-producing net acres which surround 22 of the largest oil fields in Argentina. Apache's acreage is immediately adjacent to and on trend with several fields but has never been explored with 3-D seismic. Apache plans two significant 3D surveys once permitting is completed in mid 2010. Lastly in Tierra del Fuego Austral basin Apache made a new field discovery with the (inaudible) 2001 which tested at 2.4 million cubic feet of gas per day and 300 barrels of oil per day. We structured approximately 2 kilometers in size and two development tests are plan. This discovery is significant because the structure is a look alike to several others in the immediate area which were identified using Apache's 2500 square kilometer 3D seismic survey acquired in 2008. That wraps up the international. I'd like to now turn over the presentation of John Crum who will discuss our activities in North American operations.

Thank you, Rod. In Canada net production was 78,000 barrels equivalent, an increase of 2% from the fourth quarter 2008, primarily on successful winter drilling program adds. As an update on the Ootla river basin which many of you heard about? You are aware that both Apache and our partner in Canada are drilling in the two like area with pad style development programs. This minimizes our infrastructure costs and reduces our footprint while testing the full development model pad operation. The partners have almost completed a shared dehydration compression facility for the area and a 41-mile, 24-inch export line to the spectra tie in point at Cabin Lake is being commissioned as we speak. EnCana has already drilled and cased eight horizontal wells and will drill three additional wells this year. Two of the EnCana operated wells are already completed with remainder expected by late summer. We expect to see first sales from the EnCana wells by July. On the Apache operated D70-K pad we have two rigs in place both the moving systems drilling on the same pad. We've patched that surface casing on all 16 wells planned for the pad. The first two horizontal wells have been drilled and cased with approximately 5,000 foot laterals. We will drill all 16 wells before mobilizing the frac spread to control our costs. We presently expect to start frac operations by September and have this pad producing the sales by the ends of the year. We will be increasing the number of fracs per well in the program this year based on the success of last year's program where our 10 frac well, the most we did in any of those wells last year is still producing over 4 million a day after seven months on production. In the central region net production was 89,600 barrels equivalent per day. That's down 3% from the last quarter of 2008 as we severely curtailed drilling due to the price realizations. This morning though we announced that Apache is acquiring Permian Basin properties from Marathon as Steve discussed for $190 million. These properties are located in nine fields in West Texas and eastern New Mexico and currently produce 1850 barrels of oil and NGLs and 10 million feet of gas. The properties are a great fit for our large Permian position as most of significant part directly offsets our units operations where we have a substantial operating base. That area has been the foundation for our Permian drilling programs for over a decade. Needless to say we know this area very well. We've already identified 200 possible drilling locations. For example, as a general rule throughout the area we have drilled these properties down to 20 acres profitably. The properties we are acquiring are remaining at 40-acre spacing. So we expect some good infill programs out of this. Elsewhere in the central region we drilled and completed our moody's seven H, and Bossier horizontal well in Freestone County, Texas, It tested at 15 million feet a day in February and is still, and is now producing the sales of over 7 million feet a day as of last week. The well is 100 percent working interest and they have a number of other prospects in the area. We were also quite pleased to announce that Apache has begun operating its first compressed natural gas refueling station at Elk City, Oklahoma; enabling the Company to fuel 40 field vehicles with cleaner-burning natural gas produced from the company's wells in the Anadarko basin. We had to install conversion kits in these trucks since domestic pick up manufacturers do not presently produced CNG vehicles. We are hopeful that the success of this project will encourage production of such vehicles in the future leading to both cleaner air and lower costs. In the Gulf Coast region net production was 104,100 barrels equivalent per day. That's an increase of 20% from the fourth quarter of last year as we continued to recover from our hurricane outages. A significant exploration success this last quarter was Ewing Banks 998, number one, discovery which tested at 4254 barrels of oil a day with 5.4 million feet of gas. The well will be connected to existing facilities using a subsea tie-back with first production expected during the first quarter of 2010. On the development side we've been telling you about [gopher] that discovery is expected to come on during May and we would expect to ramp up production to a net roughly 45 million feet per day by July. To update you little more on the hurricane recovery at the end of the quarter we were still down 63 million cubic feet per day on our gas production and some 4250 barrels per day on our oil production. All of that primarily due to third party pipeline outages, that has just taken longer to recover from. By the ends of the second quarter we would expect those figures to be down to 35 million cubic feet of gas per day and 3,000 barrels of oil. And we expect to have all of this essential back on by September. Across North America we've been working within our capital discipline for the year and our teams have been focused on building their prospects inventory on our large acreage position. In the current market we enjoy the benefit that our acreage position is mostly held by production. We will have a substantial ready to drill inventory as soon as we see some product price help. Finally I know there's a lot of interest on costs so I'd like to give you a little color on cost levels. We are starting to see strong cost reduction movement. Here are some examples. In Canada, we've recently gone to bid for the fracs for our (inaudible) program. It looks like it will be down 40% for an equal size job from last year. Some of this reduction I will say has to do with the way we are doing the job with the efficiency gains on multi-well pad operations but the rest will be service and commodity pricing reductions. Rig rates are down as well in Canada but we have got most of our drilling program done for the year. In the Gulf of Mexico published rates are down 50% from their peak last fall. A 350-foot IC is not, probably just 70,000 a day down from 150,000 per day last October. Net rigs are down to 45,000 per day from 85,000 per day last year. Boats are running 30% down from last year. In the Anadarko basin rigs are being quoted at 12,500 per day down from 20,000 last year. In the Permian Basin we are seeing 8600 versus 13.6 last year, net in costs are down 30% and stimulation is 35 to 40%. Overall we can now drill and complete a well in western Oklahoma for at least 30% less than last year. With that I will turnover this discussion to Roger.

Okay. Thank you, John. And good afternoon everyone. In Cairo we drink a beer called Stella its not Stella Artois, but Stella local. It's rather murky in appearance, perhaps to hide the occasional chunk, that are found floating in it. But Stella has a great motto on their T-shirts "That which does not kill us makes us stronger". That's not a bad statement about Apache and what's happening in our industry today. Collapsing prices, particularly for North American natural gas are straining producers some to the snapping point. And while Apache with our $2 billion write-down it's hardly un-staged this is not our first downturn by any means. And our finance wherewithal remains intact. We intend to be among the few that come out, the other ends of this downturn stronger for it. As Steve mentioned we are taking the tough steps as we endeavor to lead today's change rather than fall victim to it. We are raining in capital spending to preserve our financial flexibility and A rating. This gives us a tremendous competitive advantage in today's world of limited access to capital. Five-year money for Apache today costs under 5%. In the first quarter we reduced capital over half a billion dollars from the prior quarter alone and kept exploration and development spending in line with our plan. Our investment in cash flow have different profiles through the year but all in 2009 projected E&D capital of $3.5 billion to $4 billion is anticipated to fall well within cash flow. We are also battling costs that are returned, both cash and non-cash which I will go into shortly. Our personnel reductions have been painful but they've also been necessary to write size the organization for today's much lower commodity price environment. The annualized savings of $21 million gross will become more apparent after getting beyond the one time, $10 million severance charge that we expect in the second quarter. As an aside I'd noted that the four members of the office of the CEO have also cut their salaries by 10%. DD&A costs are also coming down aside benefit of write downs that lessens our future amortization rate. And finally because we have over $1 billion in cash and short term investments and a manageable debt to cap rate, in the mid 20% range, we are one of few positioned to take advantage of today's adversity. The Marathon deal that John mentioned is good example. At prices that we hedged averaging $57 a barrel and $5.70 per MMBtu, our acquisition economics indicate we are buying these long lived legacy properties for just under 4.5 times cash flow. Using last year's 2008 average prices these same properties would easily have fetched in purchase price around a half a billion dollars. While at $187 million this is a relatively smaller deal, these properties are modestly accretive to earnings and cash flow immediately. And they add 26 million barrels of equivalent reserves at just $7.21 per BOE. We plan to remain very discriminating as we assist through additional purchase opportunities but clearly the flood gate has opened. Now to specifics on the quarter. In comparing the first to the fourth quarter we've removed write-downs, foreign exchange impacts on deferred tax and other tax adjustments in an effort to capture the normalized, quote normalized earnings of the company. Accordingly, we earned an adjusted $218 million or $0.65 per share in the first quarter versus $276 million or $0.82 per share in the fourth quarter. Despite oil and gas realization is dropping 16% and 19% respectively. Cash flow from operations declined 10% to $983 million driven by a 17% decline in realization but countered by a 6% increase in production and significant cost reductions. Lease operating expenses for example totaled $8.06 per BOE and that was down 26% from the $10.91 reported in the fourth quarter. The decrease includes lower hurricane repairs and insurance costs and lower power fuel and other costs. Absent one off effects the LOE rate per BOE should fall in a range of around $8 in quarter still well below the 10.91 reported in the fourth quarter. Whole cost DD&A of $10.86 per BOE was down 17% from the fourth quarter and should drop another 5% or so following the first quarter write-down. The write-down by the way only affected North American properties and was driven by lower natural gas prices. General and administrative costs per BOE of $1.72 were up 17% on several one time items. [Absent] non-recurring item the unit costs would have dropped to around $1.35 per BOE which is an achievable run rate going forward. Our effective income tax rate was temporarily reduced to 28% by the write downs from our normalized run rate of 38% to 40%. Clearly the first quarter was a tough one. The decline in our average realized price totaled $6.87 per BOE. On the bright side however we are able extract $3.60 per BOE out of cash costs in order to preserve at $19.70 per BOE cash margin and while this stay off next to last year's average margin it's still very robust relative to most of our 50 plus years. Given our progress in reducing costs and increasing production and with $4 billion of financial capacity this downturn will almost certainly make us stronger. With that I think this five man parade is over and we would be happy to address any questions.

Thank you. [Operator Instruction]. We will go first to Tom Gardner with Simmons & Company. Tom Gardner - Simmons & Company : Good afternoon, gentlemen. I just wanted to do ask a question concerning your each Egyptian discoveries. Specifically can you give us a ballpark estimate of the added resource potential associated with the three oil discoveries?

Its, if you look at the first couple of wells we have, some of these are early stage development. The fee option is perhaps our one of our most exciting projects that we have in 2009, exploration side we made this discovery early in the quarter. We anticipate drilling at least five wells in the future in 2009 and our expectation is to be able to exploit that AEB very large oil of the AEB oil column to achieve perhaps a field wide rate production rate of 10,000 barrels per day. Exact reserve size it remains to be determined based on the success of the appraisal and exploration drilling towards this process of doing right now. Let's go to off shore this is the third such well in an area in our Faghur Basin play which we had discovered last year 2008. We are very excited about the rates we established in the first well. This structure is typically, support sizes up to about 2 million barrels to 3 million barrels. However once again as development drilling needs to be done on this prospect as well. And North Sea is the first discovery in the concession to great attractive structural accumulation. We also review the development drilling there. And we won't be able to test a well in full production until we have a development lease from a government which will come some time in the next 45 to 90 days. Tom Gardner - Simmons & Company : Thanks for that. And jumping over to Argentina, I just wanted to know how much the concession extension may have impacted your plans in the region and to what degree capital is still restricted and are you expecting gas prices to go up in the region going forward?

The concession extension is very important to our program because it has specially, doubled the existing life of the concession area. It protected our production and allowed us to add that the tale of the reserves otherwise it would have been granted back to the province beginning in 2016. That is essentially having 9 million barrels net to us by the fact of signing the extensions. It's a significant area. It's our bread and butter area in Argentina at the present time. And so the extension gives us a lot of life and running room for our program in the future. With regard to the drilling program our drilling program in Argentina is pretty heavily loaded on the front end of the year. And I don't see much activity because we have curtailed Capex in Argentina accordingly associated with the cost primarily correct market prices as well as costs of doing business at the correct time.

On the gas price side you might have noticed that year-over-year we were up $0.14 to $1.98. I think that's the highest price we've had since we've been there. And they still have severe shortages there and basically when we, we can propose drilling new areas and get an exemption if you will from delivering that gas into low priced markets and selling it into free markets. And so the more that, more new gas we bring on the higher we hope to see our average price go. Tom Gardner - Simmons & Company: Thank you, gentlemen, that's helpful.

: We will go next, David Heikkinen with Tudor Pickering Holt. David Heikkinen- Tudor Pickering Holt: Good afternoon guys. A question about your thoughts around the E&D market now with your first acquisition announced, how many do you think are out there similar size kind of your target range, or what will be the maximum and just trying to get a feel for what you are thinking now that, now that you started maybe buying some things.

Well, I don't think it's any secret that we are for the first time in two or three years actively looking for good things to buy. I think Roger pointed out that difference in price scenarios from last year to this year and putting reserves on your book at $7.21 rather than close to $20 per barrel is much more palatable to us. I think in terms of number one, we don't have anything in front of us. But we constantly are looking and I would tell you I think the bid and the ask between the buyer and the seller is getting a lot closer. I truly anticipate by this summer a lot of thing will start turning over. Obviously we are looking for thing to fit us like this Permian so we don't chase every pretty girl but I'm very confident that this year it's going to be a good year. David Heikkinen- Tudor Pickering Holt: Do you have any thoughts about volumes that you would buy or any ranges or is that just, that you talked in the past, acquisitions come and sometimes you get them and when they happen they happen?

Well, I think if you think about the time frame it's probably a pretty good time to grow. And you can either grow drilling wells or you can grow buying things and now as costs starts coming down it gets a little more economic to drill but in terms of the economics of acquisitions right now it's probably a better time to acquire. So I'm not going to put a size on it but, and we are a, we like to grow incrementally. So I doubt very seriously if you could see us go up and buy something gigantic but in terms of buying something little bigger than what you saw there we would probably do that also. David Heikkinen- Tudor Pickering Holt: Okay thanks. That's helpful.

We will go next, Brian Singer - Goldman Sachs. Brian Singer - Goldman Sachs: Thank you very much. Good afternoon. Following up on the last question but more towards your comments on drilling, with costs having come down I mean I appreciate the color on that, what gas price do you think it would make sense to begin drilling again in the US onshore and the US offshore and how does that I guess, how does that work in with your acquisition capital or planned acquisition capital as well. Does that further then need to get higher gas price to say it's not necessarily worth doing acquisitions, let's start drilling again?

I think that the first point here is that we don't think cost have come down as far as they are going to come down yet. So it's a question of when do, you want a dollar cash cost average down or you want to wait until they get down there. And I think to the extent that we can we are going to push the service companies as far down as we can get them. And in terms of what price you needed it really depends on where it is. I mean it's very hard to make a blanket statement that you need $5 gas or you need $4 gas because every prospect honestly has a different profile and a different cost. So that's a, if anybody gives you a number unless they are just drilling a lot of wells in one area it's pretty hard to come up with that number. Brian Singer - Goldman Sachs: What about the Western Oklahoma specifically or Oklahoma specifically which I know is an area it's been very active I mean it's an area where we've seen the rig count come down significantly?

John you want to? John Crum : No I think a lot of what you saw happening in Oklahoma is not only cost getting out of line but our basis differential got completely screwy there for a while. Those are starting to level out. And so we weren't even seeing, what would be anywhere close to an acceptable price in Western Oklahoma in the first quarter. Obviously these costs coming down will help but I just talked to our drilling manager up there a few hours before this call and he is seeing even more reductions coming. So for Steve's points I think we will just kind of watch this little bit longer and see where it's going. Brian Singer - Goldman Sachs: Great, thanks. Can I ask one more, can you give us an update on the Western Australia gas market both on how your main industrial customers are the main industrial consumers are fairing in the current environment and where you see pricing on the margin?

: Well, I think that there is no doubt that you would be; the supply of gas is just not in the United States. There was a demand weakens in the United States, demand has weakened around the world. We were able to sign a very good contract with CP mining. That's going to underpin the development of the Reindeer field. But in terms of our current outlook it's probably more in the $4 to $6 range rather than $6 to $8 range. Brian Singer - Goldman Sachs: Great. Thank you.

We will go next to Gil Yang with Citigroup. Gil Yang - Citigroup: Good afternoon. Going back to the M&A market, just for a second, Steve, you mentioned that you would like to grow incrementally. Would that seem to, just that you would not use the current low price environment to step into new areas that you would like to be in that you are not currently in?

You know, the problem, never say never. It's probably a much better time to know what you are doing and do it in areas that you have people that know what they are doing. Gil Yang - Citigroup: Okay.

: But with the right opportunity came along in an area that we wanted to be in that wouldn't be out of the question. Gil Yang – Citigroup: Right. That's helpful. Second question I have got just about the acquisition. Could you just comment on what, how big you expect the well to be on a 20 acres versus the 40 acres spacing that they are currently on in terms of EUR?

Those wells will probably make 150,000 barrels a piece. So, you are looking at [me do] for example that this right offset our northeast record unit that we picked up many years ago and we had a tremendous program there, and we ramped production up significantly and still are doing parts of that extension water flooding around that field. In round numbers I think they were about 150,000.

While importantly too in that area these are multi-pay areas, so we have other than the drinker available to us there. A lot of different sands and carbonates produce in that area. That's why we like it so well. Gil Yang – Citigroup: Okay, that's helpful. I was just trying to get a sense for how these wells, the 20 acre wells would perform versus the 40 acre wells. Would the 40 acre wells be closer to 200,000 barrels or?

In fact we haven't seen an awful lot of interference between our 40 acre spacing. If you saw a lot of interference you wouldn't down space. It's not acceleration drilling that you are doing to down space to 20. What you are really trying to do is get oil is not going to be produced from a 40 acre spacing. Gil Yang – Citigroup: Okay. All right. Fine. Thank you.

We will go next to Joe Allman with J.P. Morgan. Joe Allman - J.P. Morgan: Thank you, everybody. In terms of the Capex budget could you clarify what the Capex budget is for '09 and what the commodity prices you are now basing that on?

Well, our Capex budget is around $3.5 billion right now, maybe a little bit higher than that, $3.6, $3.65. And that's based on $40, and $4 gas.

$4.50.

$4.50 gas, I'm sorry. Joe Allman - J.P. Morgan: Okay, that’s helpful. You mentioned Ootla I think composure shale, I think you said Freestone County. What kind of scale do you have in that area?

We have got quite a bit of acreage in the area so the guys are working pretty hard on seeing where else this might apply but if you know something about chasing the Bossier it's not a blanket operation. You've got to pick the right places when you go up. Joe Allman - J.P. Morgan: Okay and then just a question on difference for acquisitions, is it important for Apache to be an operator in any acquisitions you do and I'm think about maybe a JV opportunity? Are you looking at some potential JV opportunities that are out there?

In terms of a drilling JV? Joe Allman - J.P. Morgan: Yeah, some of these JVs that are out there for the unconventional plays.

Now, again, I never say never but we are not a very cogent non operator. If we are not able to control it, it's probably not of a big interest to us. Joe Allman - J.P. Morgan: Got you. Thank you, very helpful.

We will go next to Larry Benedetto with Howard Weil. Larry Benedetto - Howard Weil: Thanks. Good afternoon, everybody. A couple of things on Julimar you mentioned that you had some further exploration success there, is there any update on your expectations, your plans as to how you might look to monetize the asset in terms of which LNG you go down?

We are currently looking at a couple of different LNG options for the development of that project and it's a little bit too early in our decision making process to land on one versus another. But we are actively pursuing that. Larry Benedetto - Howard Weil: I guess what's behind my question at some point would Apache consider taking an equity steak in one or other of the opportunities and if so any update as to how those discussions might be going?

Certainly a lot of different options are on the table. There was time that we’re evaluating. It's probably a little early for us to commit one way or the other or to say the direct we are looking to go at this time. Larry Benedetto - Howard Weil: Okay. I will leave that one. Jumping to Egypt. Again it seems that every time we turn around there's substantial exploration success there but you haven't really given any update on the production outlook since your two X target set a few years ago. 11 is the original target what are your thoughts now in terms of what the potential is in Egypt and when might we get an update in terms of the longer term opportunity? What needs to happen to fit the pieces in place or for you to give us an update?

Well give you an idea on the two X which benefits everybody listening the two X program was the two times projection project which we launched with the government back in 2005. The objective was to be able to double our net production which was 163,000 barrels per day to double that by year end of 2010, which can take up to 326,000 barrels per day that was our target oil equivalent. Presently, at least as of last week our forecast based on our original projections was to be 260,443 barrels of oil equivalent per day as of the 19th of April. I'm pleased to report that as of 19th of April our actual production was 273,701 barrels of oil equivalent per day. So we are well ahead of the forecast with just about 18 months left to go on the program. So we are, and a big part of it of course the gas components that we have which is growing significantly as I mentioned in my remarks beginning in June of this year with the completion of the two new gas trains in Salam and northern compression project which will boost our net gas production mainly by 100 million per day and about 500,000 barrels of condensate per day. Larry Benedetto - Howard Weil: Not ready to give us an update yet?

The other thing you have to recognize is we are just finishing putting three and four there and we will have been, again be captive until such time as we build another train out there and we have shelved the train because of cost in 2008 and we are looking to pick that up again probably in 2010, which would be another 100 million per day train. Larry Benedetto - Howard Weil: Okay. I will wait on the updates. Just one thing I want from the, I'm sorry if I missed this earlier in the prepared remarks but cash operating cost, what kind of guidance can you give us in terms of how sustainable or where we see the cash kept the LOE in particular go from here, I think you are (inaudible) need dollars which is a fairly healthy decline from Q4 in particular, but how much lower do you think that can go given your current new cost cutting initiatives, what is your kind of target there if you want to lay one out there for us?

So, I think I’ve mentioned the quarter we were at 806 from 1091 or something. 1091 and we had some non-recurring things in it. But we still foresee a rate somewhere around eight in a quarter on a go forward basis. The longer prices stay down the more those costs have come down but at least at this point in time we see that low $8 number sustainable.

I talked a little bit about the being able to do business in any price environment. I'm going to give you some examples of some numbers because we are going to have to see service companies get down to these levels. 2006 we averaged about $60 per barrel and about $5.60 on gas. Our operating costs were $5.40 per barrel. If you look at $8 per barrel, we've got a lot of services that still have to come out of this business to get down to those kind of numbers and do I think we will get that far down? The mix has changed but the fact of the matter that costs have got to continue to come down and they will. As long as if we continue to see these kind of prices costs will continue to come down. Larry Benedetto - Howard Weil: Appreciate the clarity, Steve, thanks.

We will go next to Leo Mariani with RBC. Leo Mariani - RBC Capital Markets: Good afternoon you guys. Do you have any update in your activity in the Eagle Ford Shale play?

We are presently evaluating that. I guess we did have some drilling problems on several wells there and we’re kind of working through that to make sure we understood what the issues are. I will say we will be trending toward looking at the gas windows a little more than the oil window there, and I guess that's as much as I can tell you about it. Leo Mariani - RBC Capital Markets: Okay. Just curious about what your other high impact exploration activity looks like in 2009, kind of outside of Egypt? I know you guys had a program out there in Australia. Just curious to see what's going on these days?

The primary exploration area is for internationally are Egypt and Australia. For 2009 and we have a 15 well program in Australia for 2009 that includes 12 exploration appraisal wells and three development wells which are three development wells are Van Gogh and John Brookes field. We trailed five exploration wells so far, one development well with four successes. And so we have a floated just moved into the location just this past month and we have a continual drilling campaign will take us through into the early part of the third quarter. As far as the projects go of course these key appraisal wells that I mentioned in my remarks with regard to the in the June March about Mellow complex are important expanding our confidence in the size of that resource as well as we anticipate beginning a appraisal and development program at the acquisition later this year which also has a significant reserve upside for us in 2009. Leo Mariani - RBC Capital Markets: Okay. You flocks talked quite a bit about reducing your onshore natural gas activity given the low price environment. Can you talk about little bit your onshore oil activity and whether or not you've seen a big reduction there and kind of what your thoughts are about drilling in a $50 type of price here?

Well, one of the examples I gave you is on Permian Basin rigs and they would primarily be working on oil prospects of indeed we are seeing costs come down there as well. Obviously we would like to get back to oil drilling as early as possible but really was around getting costs completely out of line over the last year. Leo Mariani - RBC Capital Markets: Okay. So I guess it, are you trying to saying that you don't really have many rigs running on the oil side at all in the US it gaining for cost consumption?

Just to give you an example in the central region right now we have one rig running, that's running in Western Oklahoma. So, we would typically have, I don't know, maybe 35, 40 rigs running at this time of the year. Leo Mariani - RBC Capital Markets: Okay. Thanks a lot, guys.

[Operator Instruction]. We will go next to David Tameron with Wachovia. David Tameron - Wachovia Securities: Hi, thanks, good afternoon, everybody. Nice quarter. A couple questions getting back to economic, when do these projects become, when do service costs drop enough to get making the projects working? If you did have to put, can you talk about just if you look at your natural gas plays what today given current service costs and current health prices has the best economics, not to say you would go out and drill today but of the once you look at in your portfolio on the natural gas which ones have the best economics?

Frankly it's the Gulf of Mexico and the reason is you don't see the declines, and we drill off the more existing platforms and so what happens there is that you get a rate for a period of time. It doesn't have the, whether it's Apache's shale play or anybody else shale play it doesn't have the hyperbolic curve to it. So, what happens is if you don't get the upfront price out of those non conventional place you have a heck of a time ever making the economic. But if I make 20 million per day for three year lap get have the same reserves out of those two. I will make much better economics drilling Gulf of Mexico well. David Tameron - Wachovia Securities: Okay. What's the number two right now, Steve, do you have a feel for that?

Oil. David Tameron - Wachovia Securities: Alright, put it up. One bigger picture question on gas side. Obviously on this side of the phone everybody always tries to figure out what the right long-term natural gas price is. From your perspective, one, do you have an opinion on what that number is it, two, can service costs drop enough or is it likely that service costs drop enough that maybe the number is four or five versus a six or seven number? Can you talk a little bit about that?

This is, I've been in this business 37 years, so I will tell you that if you have $4, $5 gas price for most of my career four, $4, $5 was mechanicka. And we drilled a lot of wells. And if you have $4, $5 gas price you will have cost or conventional we have to make the right return because and I love them all, good friends of mine but drilling companies are par sites. You don't have a producer that spend money, you don't have somebody to drills the well. I'm not so concerned about is there a margin. What I'm concerned about is that the current price fit the current cost and in my knowledge still don't. David Tameron - Wachovia Securities: They don't, but one thing I wanted to mention because this question has come up a couple of times, it's not that we have projects, we do have these two but it's not just that we have projects that aren't economic at today's price, because really our capital has been curtailed in order to preserve our financial flexibility. It's written, from my perspective the question is what do prices have to rise to before we have the cash flow to put more at it into the ground. So, if you were to ask our regions I think they would tell you, we have a lot more inventory that makes economics than the amount of capital that we are allocating to.

The one thing I would say about that and hopefully it's coming across because Roger makes a very good point and I've been trying to make, the reason that we are not drilling right now is not because you can't make economics. It is because why would I drill a well if I know, and I'm certain costs are going to keep coming down. Why would I drill a well and spend more money than I have to spend to drill the well. And we have, if you looked at our original budget coming into the year it is significantly what the regions had spots on the map for at $4.50 and $40 oil. It is significantly higher than the amount of money we are spending. What we are hoping is that those same $3.5 billion, $3.6 billion is going to drill a lot more wells because costs are going to keep coming down. David Tameron - Wachovia Securities: Okay. Now, that's great color. Thanks.

And there are no other questions at this time. I would like to turn things back to our speakers for any closing remarks.

Thank you for joining us today. I will be in my office if anyone has any further questions. Thanks.

That concludes our questions. That concludes our conference. Thank you for your participation.