Bob Dye - IR Steve Farris - CEO Roger Plank - CFO Analysts : Ben Dell – Bernstein Brian Singer - Goldman Sachs Tom Gardner - Simmons Jack Hayden – Pritchard Capital Leo Mariani - RBC Capital Markets David Hiberon - Wachovia James Pascelli – TMV Adam O'Laughlin - BMO Capital Markets

Good day everyone and welcome to the Apache Corporation thirdquarter earnings 2007 conference call. Today's presentation will be hosted by Mr. Bob Dye, Vice President ofInvestor Relations. Mr. Dye, please goahead.

Thanks for joining us today. This morning Apache Corporationreleased third quarter 2007 results which reported earnings per share of $1.83. I think most of you saw the $1.83 numberincluded a $0.34 non-cash charge, primarily related to the impact of foreigncurrency fluctuations on our deferred tax balances. Without that, our adjusted earnings were$2.17 per share. Cash flow reach an all-timerecord of $1.6 billion which is a non-GAAP number. Today’s discussion may contain forward-looking estimates andassumptions and no assurances can be given that those expectations will berealized. A full disclaimer is locatedon our website at www.apachecorp.com. In addition, any non-GAAP number that we discuss will beidentified as such with the reconciliation also located on our website. Steve Farris, our CEO and Roger Plank, ourCFO will now make prepared remarks prior to taking questions. With that, I will turn the call over to Steve.

Thank you, Bob. Good afternoon, everyone and thanks forjoining us today. Apache’s performancein the third quarter was outstanding. It was driven by our portfolio balance,quality and depth of our growth opportunities. Third quarter production, as I am sure you have read, was 516,000barrels of oil equivalent a day which was 9% year-on-year growth and just underour all-time record set in the previous quarter. Henry Hub spot gas prices were down 17% on an average in thethird quarter compared to the second quarter. Differentials meant that as an industry, many people saw $3 gas in the Rockies. On the flip side, the average WTI oil price increase 16%from the second quarter. The average oilprice I am quoting is about $75 and hence, doesn’t really reflect the morerecent strong rise in oil prices. In this volatile commodity setting, our average realizationswere stable for the quarter and cash flow of $1.6 billion set an all-timequarterly record, which was 25% year-over-year growth and 10% relative to thesecond quarter of 2007. That is largely on the strength of our commoditybalance. Liquids production accounts for47% of our production by volume, but accounted for 67% of our revenues duringthe quarter. As Bob pointed out, net income was again impacted by a weakeningU.S. dollar that requires us to mark-to-market our non-cash differed taxbalances denominated in foreign currencies. Without this charge, earnings wouldhave been $2.17 per share. Times like this underline the competitive advantage thatApache’s balanced portfolio represents. We have a one of the largest North American gas portfolios in theindustry with over 5 Tcf in proved gas reserves as well as in excess of 20 Tcfof unrisked resource potential. ButApache is really much more than that: a balanced upstream company with almosthalf of our production being oil. We are also balanced geographically. Within our gas portfoliowe do not rely solely on North America and have verymaterial and profitable growth areas in Australiaand Egypt plusan early stage position in Argentina. We remain very well-positioned to achieve thetop end of our 9% to 12% production growth target for 2007. During the first three quarters of 2007,production was up 13% over the comparable period in 2006 and so we are well onour way. If you look out little further, we have guided so far to a 6%to 10% production growth in 2008 with an additional 108,000 barrels of oil equivalentof production coming online in late 2008, 2009 and 2010 from six large projects.We are more confident than ever that our resource base can generatedouble-digit growth into the next decade. I would like to begin the regional comments with Australia,which is one of the three core growth areas for Apache. I want to focus primarily on our activitiesin the very prolific Carnarvon Basin, which is offshore Western Australia. Wehave an extensive acreage position of 5.4 million acres and control of Varanus Island, which is an importantinfrastructure hub. During the quarter, we announced two major gas discoveriesoffshore Western Australia. First in July, we found 224 feet of net gas pay in the JulimarEast prospect with 85 million a day of production flow. The net pay is nearly double what we found inour Julimar discovery in April and we are own 65% of this block. Second in August we found 121 feet of net pay in Brunello no.1 with production tests flowing about 72.5 million a day and 1,230 barrels ofcondensate, we own 65% and operate this also. With the three discoveries so far this year of Julimar,Julimar East and Brunello we have found a gas resource with ultimate potentialin excess of 1.3 Tcf of gas in Australia alone which is close to 1 Tcf net tous, and this is exiting considering this represents about 150% of ourproduction last year and coming from a single country in our portfolio. We will be limited this year on reservebookings to the wells that we have down but by themselves those wells will makethis project commercial. We drilled two additional prospects during the quarter atRosella and Maitland, one worth promising results. Maitland is a known gas accumulation. Wedrilled the first horizontal well there which started producing substantialsand as we increased the flow rate. Weneed to drill another horizontal well really with the right sand control, butwe remain optimistic that the field will be economic. Rosella was somewhat disappointing as our maximum flow ratewas less than 10 million a day. We arecurrently doing petrophysical analysis to better understand the reservoir. We have two additional appraisal wells leftto drill this year at Julimar and one more expiration target called Norville. We hope to drill this wells in the fourth quarter of 2007, however lastweekend the rig had an electrical fire in the engines and the early assessment isit will be offline for four to six weeks. We still should get some drilling in for the remainder of the year. In 2008, we will begin our exploration campaign in theGippsland basin. We have identified 12drillable prospects with reserve sizesranging from 50 million to 100 million barrels. I’d like to give you a little update on our developmentprojects in Western Australia. During the third quarter we sanctioned the Pyrenees oil projectwhich together with Van Gogh will give us 40,000 barrels a day net toApache. Van Gogh is scheduled to come onlinein early 2009 with Pyrenees coming on at the tail end ofthat year. This is the equivalent of 15%of our current worldwide oil production. In August, with our partner Santos,we initiated the engineering design phase of our Reindeer gas project which willmonetize between 416 bcf gas with an initial production target of 100 million aday which is expected to come on line in 2010. We own 55% of this project and operate it. In addition, we’ve begun the preliminary engineering phaseto develop Julimar [Permel] that is expected to have initial production ofapproximately 300 million a day starting at late 2010 of which 65% will be oursand we will operate it. I would like to talk briefly about the economics of our gasin Western Australia. We built our major acreage and productionposition in this area during the last ten years, when domestic gas prices havebeen in $1 to $2 range. Our returns havebeen very attractive at those levels with rates of return averaging about 25%over the last three years. We identified the resource potential early and the profitabilityof applying our operator skills, so we went in early and built theportfolio. We’ve been able to achievevery acceptable returns in a less than better market but the upside is now infront of us. Western Australia’s economy is growing led by large andlong-term mining project and needs natural gas. As a result, gas prices are converging with international levels. This summer, a large supply contract wasclosed at $7.50 per M, and that is 3 to 4 times our historic levels. We are currently in discussions with a large contract forReindeer development gas volumes and I’d like to say that the pricing levels weare seeing are consistent with these recent references. Obviously, this is very good news for ourshare holders. We’re becoming increasingly encouraged that our bet oninternational gas prices is paying off for our shareholders not only in Australiabut also in Egyptand Argentina. Each area was out of favor when we entered,and were able to generate acceptable returns in the face of depressed orregulated prices. Now we’re beginning to see signs that the gas prices in thosecountries will converge with international levels also. Other competitors are trying to build positions, obviouslyat higher costs, but we also already have a lot of depth in our portfolio. This is true organic value creation byApache. I’d like to turn now to Egypt.We took many important steps forward in Egyptin the third quarter across our primary growth drivers of exploration drilling,gas plant expansions and water flood developments. During the quarter, we madetwo discoveries, drilled one successful appraisal well and 26 developmentwells. Our successful wells are reallytoo numerous to mention individually but I do want to comment on this morning’srelease. North of Khalda we have made several Jurassic discoveries onour 250,000 acreMatruh concession including a field called Imhotep and also Jade. The Jade 2x appraisal well that we announcedthis morning was drilled on the Jade Ridge which is on the Western flank of theMatruh concession . It was drilled specifically to test the AB formation. We found a 148 feet of AEB pay inthe wells which flowed 27 million a day and about 1,325 barrels of condensateof test. The Jade 1x discovery well which is currently producing from theJurassic formation also logged 217 feet of pay in the AEB. The Jade 4X appraisal well,another well we just got down, an AEB test logged 234 feet of pay in the AEB and willcompleted as soon as the Jade 2x is finished. The Imhotep Field is 17 miles east of the Jade Ridge on theEastern flank of the Matruh concession, and we recently recompleted the Imhotep2 into the AEB and have tested 4,082 barrels a day of condensate and 3.3million cubic feet of gas. I might add that AEB formation has produced 40% of the 250million barrel liquid production in the greater Khalda area, which is directlysouth of our Matruh concession. We arevery encouraged by the results of the Jade Ridge and as many you may know, thisis one of our significant expiration targets that we put on the books tobeginning of the year. Our Salam gas plant expansion projects remains on schedulefor completion in the fourth quarter of 2008. This project is projected to add an additional 90 million a day and 4,500barrels of condensate net to Apache. At the end of the third quarter, Apache had gross productionof 33,000 barrels a day coming from its new waterflood projects which is ontrack with the estimates presented in our June analyst conference. We drilled 36 wells and six different waterflood projectsand increased water injection capacity 45% to 42,000 barrel a day. We will continue our aggressive developmentfor the next several years to realize our associated 200 million barrel lowrisk reserve potential. Our position in Egyptis one of the largest of any western companies in the Middle Eastwhich is central to the future of energy industry. Moreover our position has grown at double-digitrates for ten years and it has an extraordinary depth of growth opportunities. I’ll turn now to Canada. Our Canadian portfolio gives us a trulyoutstanding scale of resource potential in shale gas, coal bed methane and highimpact deep exploration drilling. The third quarter performance againunderlines the strength of this portfolio, with Apache Canada delivering steadyproduction in spite of a capital spending cut of 30% lower than last year. The proposed royalty increase in Albertais currently formulated. It would have a negative impact for 2008 developmentdrilling program in that province. Rates of return of some of our gas drillingprogram would decline below 10% and will definitely have an impact on our 2008spending levels in Alberta. I might point out that this is the type of development whichmakes Apache’s portfolio depth and balance invaluable. For example, in Northeast BCwhich is not affected by the proposed fiscal change in Alberta,we have an aggressive appraisal program planned this winter at our shale gasplay. Apache now controls, with ourpartner in Canada,400,000 gross, 200,000 net acres to us, enough to potentially drill 1,200 netwells at four wells per section. We plan to drill and complete nine horizontal wells thiswinter, which should allow us to develop a firm view of the play’s potential,using a variety of fracture stimulation programs along with micro seismic andlistening well data. We intend to construct an all-weather road and expandpipeline and compression facilities there. We are optimistic that this playwill be a significant contributor to the future growth of not only the region,but also Apache, with 3 to 6 Tcf of resource potential. Turning to the U.S.and our Central Region., our Central Region has twogrowth engines, the Anadarko Basintight gas and the Permian Basinoil and they both continue to power here. Production reached an all-time record of 304 million cubic feet of gas aday and 39,200 barrels of oil per day during the quarter. Production was up 21% year on year drivenlargely by our active drilling program there, which continues into the fourthquarter with 16 rigs. In the Gulf region, we continue to have a steady generationof cash from our Gulf Region from very strong production. Well production reached an all time high of 57,900barrels a day during the quarter, which was driven by restoration activitiesand a successful drilling program. Our gas volumes were below all-time records in secondquarter of 2007 due to really to two independent reasons. One was pipeline shut-ins,which was about half of it, and the other one had to do with depletion. I amhappy to report that we restored all production from the storms in 2005. Apache continues to benefit from falling rig rates in theregion. Jack-up rates have fallen roughly 50% this year for all sizes, andbarge rigs are down 15%. Our onshore Gulf Coast portfolio was bolsteredsignificantly during the quarter with a large farm-in arrangement from[Innervest], which allow us to explore nearly 400,000 acres in Central Texas. Now turning to our smallest and newest component of ourportfolio Argentina.Within a year it’s given us attractive returns and resource upside andsurprisingly price upside at this early stage. We have reduced our percentage of gas sold at subsidized prices as ofOctober 1st and this is a slight delay on the original time line ofimplementation which was supposed have been sometime during the thirdquarter. The delay was driven by one ofthe coldest winters on record in the country however. We ran seven rigs duringthe quarter and drilled 28 wells. I will turn now lastly to the North Sea. In the North Sea, wecompleted two excellent producing wells, the Bravo 63 is currently producing65,000 barrels a day and the Bravo 32 well is producing 34,000 barrels aday. As you reported and as you saw onour numbers in the second quarter conference call, we report that we were goingto take the Alpha and Echo platforms down for maintenance turnarounds duringthe third quarter which ended up costing us about 9,700 barrels a day for thethird quarter. The work accomplished during the turnarounds is reallybeyond the scope of the call, but I might say we replaced or inspected orinstalled over 200 vessels during a 30 day period that required 18,000 manhours of labor. As we near thecompletion of the topside refurbishment program and focus on productiondrilling we are setting ourselves up for an outstanding fourth quarter withproduction in the range of 60,000 barrels a day net to Apache. Remember the 40’s contains 450 millionbarrels of net resource and every additional percentage of reserve recoverygives us 50 million of light oil reserves. That concludes my operational update. Now I would like toturn it over to Roger Plank, Apache’s CFO and Executive Vice President for afinancial update.

Thank you, Steve. Good afternoon everyone. Themerits of Apache's balanced global strategy was evidenced in our strong thirdquarter results. Rising oil prices had an outsized impact on our bottom-lineresults given that oil figures so prominently in our production mix. As a result, while many North American gas orientedcompanies wrestled with nearly $1.50 sequential decline in NYMEX gas prices a$10 per barrel increase and the benchmark price of oil on strong productiondrilled Apache's oil revenue up $150 million sequentially during the quarter,enabling total revenue to reach the $2.5 billion mark for the first time in ourhistory. Earnings of $612 million or $1.83 a share where also quitestrong, especially when taking into consideration the $114 million non-cashcharge related to the impact of the deteriorating U.S. dollar on Canadian and foreigndeferred tax balances. Theoretically, when it comes time to pay our defer taxes in Canadait will take more US dollars to do so. So, we have to reflect that change in our income statement at the end ofeach quarter and frankly it’s kind of pain rear as it significantly distortsour true performance. The important thing to note is while this reportingconvention reflects the proper accounting treatment for movement in foreigncurrency, it is just a non-cash change and not a current period economic event.Therefore, setting aside the impact of the changes in foreign currency, Apacheearnings did total of $2.17 per share substantially Street expectations. It is also well ahead of both last quarterand third quarter of ’06 earnings which excluding the impact of foreigncurrency fluctuations and other non-recurring items totaled $2.09 and $1.70 pershare. If you are interested the [inaudible]lays out those adjustments so that you can see each of the components. The strength of our quarter is readily apparent in our cashflow from operations which being unaffected by this foreign exchange fluctuationreached a record $1.6 billion or $4.83 of share, up 25% from last year’s thirdquarter; 10% higher than the second quarter of this year and well ahead of consensusestimates as well. Again, the strong results speak to the benefit of a balancedportfolio approach. I can’t tell you hownice it is for our liquid hydrocarbons -- roughly half of our quarter’s production-- to generate just over two-thirds of our total revenue. Revenues are the beneficiary of higher oil prices of lateand while the weaker US dollar generates the deferred tax amount we projectthat we may pay someday there is little question that this currency weakness isalso benefiting Apache in the form of higher oil prices. From that standpoint, Apache has a naturaloffset which mitigates the income statement impact resulting from the weakerdollar. As Steve indicated, our third quarter production was up 9%year over year; it was down 2% quarter over quarter while the slight decline inthird quarter production may have surprised some of you, it was relativelyconsistent with our internal expectations due to the anticipation of thescheduled turnaround in the North Sea which is why we do continue to expectyear-over-year production growth at the upper end of our 9% to 12% growth range. If you do the math, to reach the upper end implies significantgrowth in the fourth quarter which we fully expect will enable us to close outthe year with our highest production level ever. We also anticipate continued strong returnsdriven by robust margins, the impacted strong global demand and limitedsupplies on oil prices fueled Apache’s highest cash and pre-tax marginsyear-to-date despite realizing the lowest gas prices of the year and fightingour industry’s ongoing battle with rising costs. For the quarter, overall cash costs dropped 1% to $13.55 perboe and combined with 3% higher realizations, propelled margins up 5% from lastquarter to $34.83 per boe, our highest year-to-date. Even including DD&A, our total pre-taxmargin increased to $22.72 per boe from $21.40 sequentially. Focusing on costs, our third quarter lifting costs increased2% or $0.17 of boe sequentially to $8.21 per boe. Roughly half of this increase was related to expandedworkover activity to increase production on the Anadarko acquired propertiesand the other half relates to the lower North Sea volumeswhich as you’ve heard, are forecasted to recover in the fourth quarter. I also note that the quarter included $0.09 related to theforeign exchange movement and absent fee impacts, LOE per boe would have beenaround $8 which is a level we consider achievable going forward, even withcontinuing higher work over activity. G&A costs dropped 13% sequentially to a $1.19 per boe,probably a good rate, achievable rate going forward. Full cost DD&A was up just 2%sequentially to $10.94 per boe as drilling costs continue above historicallevels. Severance and other taxes of$2.42 a boe decreased $0.10 quarter over quarter. This is primarily driven bylower North Sea PRT as lower volumes more than offset higher oil prices. Financing expense decreased $0.05 to a $1.17 per boe on $126million lower debt. Continued strong oil prices and rising production shouldresult in further debt as well as debt to cap reductions from the 25% rate thatwe ended third quarter at. Our effective tax rate was 48% for the third quarter, thelingering effect of exchange rate fluctuations and further currency weakeningso far this quarter should cause our fourth quarter effective rate to remain ataround the same level and portion that is deferred should move to around52%. Fortunately, the costs start over every January 1st, soabsent further FX changes next year’s rateshould be back below 40%. Before closing, I’d like to underscore that not only are wegratified with Apache’s third quarter results, but we also look forward to avery strong finish to our year for good reason. First, solid fourth quarter production will contribute to double-digitgrowth year-over-year and our 28th increase in the last 29 years. Second, despite concerns over the USeconomy, Apache is among those multinational companies benefiting from strongglobal demand for our product. While itis too early to know exactly where prices will shakeout for the quarter,current WTI oil prices are again over $10 higher than the third quarter NYMEXaverage of $75 per barrel. With 7,000 barrel per day of old hedges rolling off thismonth in October, where the prices was capped $39.25 or less than the half thecurrent price, approximately 85% of Apache’s oil production is now unhedged andenjoying the price run up toward $90 perbarrel. In addition, our lowest gas price hedges rolled off inOctober. Some 90 million cubic feet perday capped at $6.32 per MMBTU leaving only around 15% of our total gas hedgedas we head into the winter demand season. Finally, today’s cover article, some of you may have noticedin the Wall Street Journal mention price controls in Argentina.I would add and as Steve has indicated, Argentinahas begun to take steps towards that with respect to natural gas we’re startingto see the benefit of that. Thus far into fourth quarter Apache’s averagingjust over $1.40 per MCF on 200 million cubic feet of gas per day and that’s 40% or so higher than what weactually received in the third quarter. So in a nutshell, the combination of rising production andprospects for strong product prices should enable continued attractive -- oreven improving -- margins resulting in a very strong finish to 2007. Steve Farris : Thank you, Roger. I might just close with a fewcomments. The third quarter was outstandingfor Apache both financially and operationally. Cash flow set records, we had outstanding earnings. Operationally, our evolving high impactexploration portfolio in our core growth areas, resulted in two natural gasdiscoveries in Australiaand a gas condensate discovery in Egypt.In Canada we addedabout 104,000 gross 52,000 net acres to our British Columbian shale gasresource play, and now control over 400,000 gross, 200,000 net. We look forward to testing the viability ofthis play with the drill bit during the winter campaign. Our portfolio balance has shown through in our commodity mixas Roger pointed out, liquids which account for half of our production generatedtwo-thirds of our revenues, and that should continue into the fourth quarter. We should exit the year with a rising production profile andshould end the year on the high end of our range and with development projectsunderway scheduled to add 108,000 barrels of oil equivalent per day over thenext three years fueling our growth. Ourresource base is capable of delivering strong growth through the end of thedecade. With that we would love to take your questions.

Your first question comes from Ben Dell - Bernstein. Ben Dell - Bernstein: Myfirst question is really around reserve bookings. You outlined a number of your discoveries,there are obviously timing issues in terms of when you book those. Last year your F&D in the US was a particular drag. Do yousee that coming down this year or your overall F&D declining this yearversus last year?

Finding cost? Well, we still got a quarter to go and ourreservoir engineers haven’t told me what the numbers are yet. I will tell you this; the thing that is goingto affect our finding cost in the U.S. this year is same that’s affected themin last year, that is we still have an awful lot of the hurricane damage thatwe put in this year which was really as we pointed out last year, was reallythe impactful thing in the United States. Ben Dell - Bernstein: Maybe turning over to Argentina,can you give some color, and you obviously mentioned the collar on the gasmarket there. With the elections comingup, do you have a feel for what sort of escalation in gas prices you could seeover the next two, three years as the market tightens?

Well, everything I am going to tell you is obviously what --as I always mention we go into new country we are their guest, and they are thehost. There is a lot of anticipation that the new administration is going to atleast relook at that issue. I will giveyou some anecdotal comments about that though. We recently entered into athree-year contract with a major gas user there that’s in other parts of theworld. In the three years they are at 15million a day and they go from $3 to $3.50 to $3.90 over the next threeyears. So we are seeing, already we’re seeingactually more than I anticipated when we got in there at this point oftime. I don’t think that’s going to change as you I am sure youare aware. They need indigenous gas terribly. They import 250 million a day from Boliviaat over $6 now. I am hopeful that everybody is reasonable about the way youattract foreign investment and part ofthat is that you have to make a return and in order to do that, you have tohave acceptable prices. So I can’t forecast. I can tell you what we’ve been able to do lately, but in terms of ourexpectations I think our expectations are pretty optimistic, frankly.

The other thing I would add to that is, the article in thepaper implies everything is regulated and priced and gas is too, but it isreally the residential market and some of the small usage markets that areregulated, and it is certainly low price, but they also recognize that they arerunning out of gas. They have to import it, like Steve says, at $6 so they havelet incremental gas sell for whatever the market will bear. So once we have delivered into the lower priced, regulatedmarkets then we can go after these markets that Steve just indicated where weare seeing prices at $3 or triple what we got last quarter. So they have the right ingredients in place and they havethe right mindset; people who bring on new gas will get rewarded with higherprice. Ben Dell - Bernstein: Just one last quick one. On Enesco’s call today theysuggested the demand for jackups in the Gulf of Mexicois picking up and highlighted yourselves as one of the key players coming backto the market. Can you give us an indicationon what your rig demand in the Gulf will be next year versus this year?

I think they are hopeful. I will leave it at that.

Your next question comes from Brian Singer - Goldman Sachs. Brian Singer -Goldman Sachs : When you look at your Australiagas exploration program can you talk to where you stand on prospect inventoryand how aggressively should we expect gas exploration to be in ‘08, givenwhat’s going on?

We will have a very active program. We have a number ofother prospects on the block 356; we have a block that is north of our old EastBar which is a field that made about 750 Bcf of gas, it is west of Varanus Island that we are going todrill. We have Norbo which we are goingto drill. We have a number of additionalprospects in the Carnarvon Basinto drill next year. I guess you are asking the potential of the market or thepotential of our gas resource base? Brian Singer -Goldman Sachs : Really just the potential of the gas resource base and howaggressively you plan to drill that in ’08 versus your program in ’07?

Well I actually I think we have two rigs running next year.I will tell you it is difficult to get a rig into the Carnarvon Basin and I will give you the firewe just had. It will be December beforewe get another rig into the Carnarvon Basin because they have safetycases that a new rig has to go through. We think there is about 2.2 billion barrels of resourcepotential that we have in front of us of exploration stuff. The beauty of wherewe are right now is if you look at Julamar Brunello which we believe iscommercial as it sits; and our Reindeer, our only downside is not getting thatdone and executed. Because as you knowonce you get infrastructure and you can look for lesser and lesser sizedreserves or add-ons to the infrastructure. So we will have a very aggressive program in the Carnarvon Basin on thegas side next year as we will and in the [Gypsum] Basin starting about Februarywith one jackup coming in there. Brian Singer -Goldman Sachs : In the U.S.were there any intricacies of oil production being up relative to the secondquarter with the gas production being down a bit? Anything you need to sharethere?

You mean in the gas production in the Gulf of Mexico? Brian Singer -Goldman Sachs : Yes.

We were down about 40 million a day and about 20 million ofthat was strictly facility related or pipeline related; 20 million a day ofit. A little bit of it was weather and thepart was natural declines. Quite franklywe’re expecting a little uptick on our gas production for the fourth quarterand our oil production should be about flat to up a little bit.

We’ll go next to Tom Gardner - Simmons. Tom Gardner - Simmons: Good afternoon, guys. Given the continued success you are having in Egypt,particularly in the Khalda concession, at what point does it make sense to takeanother look at your gross gas processing plants and perhaps revising thoseupward?

Well we have two plants that are going to come on startingin the fourth quarter of 2008 which is about 200 million a day of processingcapacity. I will say that we had abigger appetite than that. We go throughthe operating companies, each company in Egypthas an operating company that is owned 50% by the foreign contractor and 50% bythe EGPC which is the government arm of the oil industry. It would not surprise me at all for us to bestarting discussions in earnest on drilling, at least filling one more 100 Mcf trainsometime in the next year. They aregoing to need the gas, and we have to take away capacity.

The other thing we have an arrangement where we move gasthrough another operator’s plant that supplied basically by one field that hasbeen depleting. To the extent that, thatgas isn’t replaced that frees up room for more Apache gas into the future.

To be a little more specific, we take about a 150 million aday of our gas out of Cosor, North to a field called Obiat that has a 380million a day gas plant. Obiat has beenonline for a number of years and continues to decline so to the extent they declineour gas rates will go up through there also. Tom Gardner - Simmons: To be clear, this 100 million a day that you speak of , isthat incremental to these 700 million gross?

That would be, yes sir. Tom Gardner - Simmons: Jump over to the North Sea, you continueto have success there as you mentioned in the Bravo well, I guess appropriately named. Some people arepulling out of the North Sea, I just want to get yourthoughts on the UKnatural gas market perhaps consolidation opportunities in your capital spendingplans there going forward?

We continue to put together exploration projects but our mainconcern frankly right now is to get 40’s up and running because if you look atthe fields in the North Sea I think the 40’s field is either the second orthird largest field still in the UKNorth Sea and if you consider that and we are seriously believe there isanother 450 million barrel resource potential there it would rival any field thathas been found. Our immediate goal is tomake sure we make that run everyday and I think we are later than what Ianticipated but I think we are pretty close to be in there. With respect to the gas markets, I mean with the UnitedStates Bank, they had a psychedelic ride, I mean they have gone through one ofthe most aggregated volatile markets. It went from sometimes over $20 to $4 to$3. Frankly I think that gas market willcontinue to be tremendously volatile in the UK for the very reason that I thinkit’s going to be somewhat volatile in United States and that is they have to importtheir commodity and that has to do, as gas becomes more and more worldwide thegas is going to find the place that is going to pay a nice price because oncethey get on the water in the LNG they are going to the highest priced gasmarket. So in terms of our future on the gas side, I think thatdepends on how other people look at it, because at $86 a barrel the things thatwe have seen that have come through have been pretty high priced. We certainly didn’t get into the North Seajust on 40’s however. So we are veryhigh on the potential of the North Sea and things thatwe know how to do very well. Tom Gardner - Simmons: one last question with respect to Australia. I just want to get an idea of to what degreeyou are able to manage those higher spot prices? How much of your gas is termedout and when does that come open for free negotiation? Then the growthcomponent on top of that, what does that look like relative to what you areproducing today?

We have about 40% of our gas that is going to come off, 40%to 50% of our gas is going to start coming off 2009 and 2010; our existinggas. Tom Gardner - Simmons: Meaning come out of contract?

Yes, come out of contracts. The real demand for gas today in Australiabesides the rollover contracts that we will obviously try to renew are the hard metals that you are seeing in the restof the world, if you look at the copper prices or anything, steel prices. Thereare a number of new mining plants going in on the western side of Australiato capture that price for minerals. If youlooked at a demand curved in Australiaover the next five to six years, it is not unlike the demand curve you see in Egyptwhich is about 12% per year. Our honest Achilles Heel is we have to get these projectsdone, and it is not an Achilles Heel, but our future is in front of us if wecan take advantage of it. We have the closest, we have the gas that can get tomarket in the near term. We had a tender, we had 23 expressions of interest forgas, so there is definitely a demand for gas, and there will be an advance forgas. I don’t know if you read some ofthe information that comes out of the Western Australian government, they areconcerned about natural gas starting in 2009, 2010. Tom Gardner - Simmons: Is Apache being aggressive in going after that market thengoing forward?

Yes sir. I might add to that again I want to make sure Imade my point as I made it. Our Reindeergas we are into the engineering design and it should come on in 2010. We justended a tender process where we were asking for interested parties to submitindications of interest by last week Friday. We got 23 indications of interest; now obviously we are going to picktwo or three and deal with them, but their appetite was overwhelming.

Your next question comes from Jack Hayden – PritchardCapital. Jack Hayden –Pritchard Capital : A couple of quick questions. First on the tax rate issue youtalked about Q4 tax rate being about the same as Q3 assuming you report it the same way,stripping out the forex impact, where would you expect the tax rate to shakeout? Can you give some additional detail on what you have goingon in the Canadian shale play? If possible, some results from these couple of wellsdrilled and a little color on the depths, targeted well costs, anything likethat?

Regarding the tax rate, I think I got the gist of what youare asking. There has been furtherdeterioration in the fourth quarter. Sothe number that I gave before or the comment I made before that the fourthquarter rate, although it would be comparable to the third quarter rate of 48%is taking into consideration that deterioration in the U.S. dollar that we’veseen so far in this quarter. So if thereis no further deterioration from here we still ought to have a rate of about48%. Does that answer your question? Jack Hayden –Pritchard Capital : No. You had 48% but you stripped out components as unusual dueto the forex change, which got the tax rate down to about 38% ex that. So assuming you considered the forex impact inQ4 again to be kind of unusual, should we expect a recurring tax rate of about38% again?

Our natural un-foreign currency changes, tax rate of 38%,39% something like that. Now, but to get there we have to go through year endbecause of the changes that have takenplace so far that the impact is blended throughout all the quarters ahead of you. So you won’t see that until next year. If you know what I am saying. We have acarryforward of that impact from the change in the foreign currency year todate.

The clock starts over January 1st and so it would takeanother currency move like the one we have seen to drive rates next year up tothat mid to high 40% range.

So far,I mean it’s been a $0.15 move from start of the year to the current timeframeso that would be another huge move. Well we’ll just see, but hopefully with theclock starting over we will be back below 40% next year.

The question on the shale, you're exactly correct. Actually,we have four wells in the shale, two vertical wells and two horizontal wells.One of the horizontal wells I would describe as actually legitimately testingin a play the way we will this winter. We put three fracs on a well; obviouslythe next well we'll probably put seven or eight fracs on it. We're very encouraged by the results of that well. The ratewas about commensurate with a three frac well. The decline curve has not beennearly as steep as we anticipated. It has been actually tremendous; it hasdeclined but it's been a tremendously shallow decline. We're designing fracs.We'll probably do two or three different kind of fracs in the wells that we'regoing to drill this year. But between us and EnCana, our partner, we'll end updrilling nine wells this year. We have 400,000 acres under lease of which we own 50% across-the-boardand EnCana owns 50%.

We'll go next to JohnHerrlin with Merrill Lynch. John Herrlin - Merrill Lynch: In Australia,Steve, you talked about Julimar and the associated discovery being commercial.How are you going to produce that, or where?

John, in terms of the development plans, we have about threedifferent scenarios that we're working on because we have obviously a lot ofpipe to lay. One version is to take it close to Varanus Island without taking it on Varanus Island so that we can move gas. Wehave a 450 million a day pipeline that goes to shore right now at Varanus Island. Reindeer will have apipeline to it because we're going directly to shore at Reindeer to the north. So the design plans would have either going over, throughReindeer, or coming down and making sure that we can get Julimar gas, Brunellogas, Maitland gas, whatever else gas we find not coming through Varanus, butcoming close to Varanus so we can continue to be able to take gas in from thatpipeline also. Actually, we haven't settled on a design currently, John. John Herrlin - Merrill Lynch: In Egypt,you spent a fair amount of time talking about your gas discoveries and the AEBand the condensate to the south. Do you think they're connected? How big do youthink the condensate field is?

The reason I bring up the two independently is -- and I'm sure you caught the gist of it –they are 17 milesapart and one is on a ridge that goes up on the eastern side of the MatruhRidge. We currently have two more exploration wells drilling in the MatruhConcession. One is called Amber which is along the Jade Ridge to the north, andthe other one is a big Jurassic structure which is more than a step out butit's east of Obiat Field. That's a Jurassic test. We have six exploration wellsthat we're going to drill either between now and the end of the first quarterof next year up there. The potential of the Ridge on the Jade side, I think wetalked about that in order to be one of our significant discovery or potentialprospects it has to have the potential of 50 million barrels of oil or 500 bcfof gas. John Herrlin - Merrill Lynch: Gulf of Mexico, you mentioned thatrig rates are coming down. It's a good free cash flow generator for you, eventhough it's not always a growth province. Would you consider more consolidationsthere since some of the small fries have had operational issues?

I would point out that we've never indicated that we aregoing to organically grow the Gulf of Mexico. Ourposition has always been that it is doing and has done a tremendous job for anumber of years and in generating a lot of cash. It has a good size to it rightnow. I can't see us getting significantly larger. From a smaller standpoint, there are still a lot of playersin the Gulf of Mexico. If the right opportunity came by,that would be something we would be interested in. But we are a portfolioplayer so in terms of its size, it fits very nicely in with longer life gas in Canadaand the U.S.and Central Region.

Your next question comes from Leo Mariani - RBC. Leo Mariani - RBC Capital Markets: I just wanted to clarify the growth in your Egyptian gasvolume. Correct me if I'm wrong, but do you feel that you expect some plantcapacity expansions in the first quarter of '08 as well as in the fourthquarter of '08? If that's the case, could you give us a sense of the magnitudeof those?

Well, if I said thefirst quarter, I misspoke. I meant to say the third quarter. We have two trainsthat are coming on, one will be right behind the other. Actually, it should beon a little bit before the end of the third quarter, and they're both 100million day trains. Both of those will come on first or the fourth quarter. Sowe have 200 million a day gross, which has the capacity of about 16,000 barrelsof liquids or a little less, of which we have between 45% and 50% depending onwhat the prices do, because price has something to do with the cost recoveryoil that we get. Leo Mariani - RBC Capital Markets: A question on Argentina.One of the things you referred to in your prepared comments was the fact thatyour price realizations weren't as strong third quarter but you would pick upin the fourth quarter. I was just trying to get a better handle of thedynamics. I noticed your volumes were down around 9% sequentially on the GAAPside. I'm just trying to understand that a little better. I guess you guys weretalking about a cold winter down there in Argentinaand I was a little surprised to see your volumes down if that's the case.

Well, the volumes are down specifically because the take isout of Tierra del Fuego. That's not a performance issue.That has to do with a Methanex contract that's going to Chilethat Argentinadoes not want us to export gas to Chileright now. So, the volume, we can produce what we produced every quarter beforethat, and hopefully, we'll continue to raise that. Our production from when we got in there, we're up about 19%on the gas side, and we can find gas. We can find hydrocarbons down there. Thisis going to be an issue of economics and what they allow us to do in thefuture.

It's a little bit upside down like a number of things downthere. They say you can't export because we need the gas in this country but inTierra Del Fuego, basically that time of the year thepipelines to the north where the population is are full. So the net result iswe've got to shut in the production rather than selling it to Methanex. Sothat's about 16 million to 20 million a day that was curtailed. Leo Mariani - RBC Capital Markets: Can you give us a sense of how oil drilling is going downthere in Argentina,what your plans are for the near future?

We have basically twodifferent areas as you might know. We have Tierra Del Fuegowhich is down at the south and then we have our Neuquen drilling and most ofthe Neuquen stuff that we're doing is extensional type work around fields thatwe acquired from Pioneer. In the Tierra Del Fuego area, we are shooting a 2,000 squarekilometer 3D seismic shoot there that should be done by the second quarter ofnext year, across not only the existing fields but also as part of a shootacross 680,000 acresdown there. This is a very, very under-drilled province in terms of explorationpotential. San Sebastianfield is a 65 million barrel oil field, so there is a lot of potential downthere to find additional oil. One is an exploration play and the other one isan exploitation play.

A couple ofspecifics, we drilled an oil well.

I'm sorry -- forthose of you who don't know, this is Floyd Price who runs our international Argentinaand Australia.

Just to give you a feel about Tierra Del Fuego,like Steve was talking about, we just fracced a well down there that came onfor 165 barrels of oil a day. We drilled another exploration well that came inon Don Piadra and it came on for 5 million a day but it was about 50 barrels amillion when you took into account the gasoline as well as the condensate wewere making with it. So very rich, and we think we can do pretty well with ourliquids.

: Sometimes the gas gets clogged up down there because oflimited pipeline capacity. They are expanding and looping that line to thenorth, aren't they, Floyd?

That will happentowards the end of 2008. Leo Mariani - RBC Capital Markets: Moving over to AustraliaI know it's a little early in the game and you had three very nice discoveriesthis year, you talked about potential around 1.3 Tcf and you're still workingon development plans. Do you have any estimate of the kind of potentialdevelopment cost there on a per Tcf basis or anything like that?

I mentioned to John Herrlin that we have three differentdesign schemes. It really depends on which one of those we pick. When we getcloser to a final design that we are going to go with, it's probably moreappropriate to talk about where we think the cost will be. I'd be estimating right now, and it could besignificantly off one way or the other.

Your next question comes from David Hiberon - Wachovia. David Hiberon –Wachovia: You mentioned in Alberta worst case scenario, if the taxpackage goes through or the interest goes through as planned, if you look at aCapEx budget call it $700 million to $800 million, you reduce that, where doesthat CapEx go?

In Canada? David Hiberon –Wachovia: Yes, if you were to take it out of Alberta,where would you deploy it elsewhere in the program in your portfolio?

Well, our winter drilling program in our shale gas in B.C.is about $100 million this year. We have the opportunity to spend it. What I'dhope and as many of you might know this evening they're supposed to detail theoutline of their new royalty scheme. I don't know who listened to the Premieryesterday, but it was a little more steady than at least what the rhetoric hasbeen around it. There's some hope that they will phase in any royaltyadjustments they may have, which would go a long way in trying to look atcapital budgets in Alberta nextyear. There's some talk that their deep drilling royalties may not be part of adeep gas drilling. It would probably cut at least a couple hundred milliondollars out of our budget in Albertanext year, but that's a supposition, honestly. David Hiberon –Wachovia: I know that's a supposition, though it sounds like you wouldallocate a little more to B.C., and then just elsewhere throughout the program.

Unless it just gets really chaotic up there in Alberta,I can't imagine us spending -- our budget will probably be somewhere aroundwhat it is this year and honestly it could be higher. David Hiberon –Wachovia: One more big picture question. There's been a lot ofspeculation and I think the general consensus was Canadawould come off a little quicker, not for you but for industry as a whole oncethe rig count plummeted last year. I think maybe some people were surprisedabout the level of exports into the U.S.,that it didn't fall off more. Do you have any feel for why that was? Was it afunction of CBM production or was it a function of the marginal wells gotknocked off first?

I don't know. The only thing I would say is if they use theproposal that they're talking about or the one that the panel came up with, andit may take six months to fall off but you are going to see a real reduction inAlberta drilling. That can't doanything but reduce the amount of gas that's going to come this way. Two orthree months are really hard to forecast. David Hiberon –Wachovia: Yes.

A year is much longerbut that's even pretty short. Some of these things have a long term effect. David Hiberon –Wachovia: We'll wait and see what happens tonight. Thanks.

Your next question comes from James Pascelli – TMV. James Pascelli – TMV: This is a follow-up on the last question. I know the trendsdon't look good for Canada but with Alberta gas recently around 5.95 or so, notterribly low, it's been lower, are you thinking that the industry is lookingfor something closer to $7 an Mcf to really get things going again or do youjust think that the latest announcement about the royalties et cetera is goingto put a big damper on any more interest in Canada? I'd like to add to that,that when everybody is getting discouraged with Canada,perhaps it's time to take a second look or we're getting close to a time totaking a second look.

I think the biggestconcern, frankly, is the uncertainty around what is going on. I heard thePremier last night say that they want to put some certainty in this and if theydon't, it will put a damper on it because in the world today, people have a lotof different places to put capital and I think that the most important thingthey could do would be to come up with something and stick to it. I think it has more to do with the places a lot of peopleare drilling than it does necessarily on price. Certainly costs have been highin Canada. Theyare coming down as they're coming down in the U.S.We're not totally oblivious to the large service companies earnings and wherethey're getting their earnings, but I think there is an awful lot more capacityout there. I happen to have agentleman from one of the very large service companies in this morning, and ifrig rates just stay the same there's probably 20% more capacity than there wasa year ago and there's going to be 20% more the following year. So I thinkthat's going to have an impact on the competition and what the cost side is goingto do. James Pascelli – TMV: Well, I think the negativity is extreme. The question is howmuch worse does it get? Obviously I've heard a lot of the calls on the servicecompanies. The tax proposal is somewhat self-defeating. I'm just wonderingwhere the turning point is.

We'll find out. It's going to be interesting, let me put itthat way. We're supposing about something we know nothing about yet because wehaven't seen the final proposal.

Your next question comes from Adam O'Laughlin - BMO CapitalMarkets. Adam O’Laughlin - BMOCapital Markets: Can you revisit quickly again what you're expecting inproduction in the North Sea again for the next quarter?

We're looking at about 60,000 barrels a day. Adam O’Laughlin - BMOCapital Markets: Next year, where is the growth in production really going tocome from? I assume it's really in Australiaand the oil. Can you elaborate a little bit? I know it's exploration success,but just a little bit of segmentedgrowth?

Well, I thinkcertainly you're going to see some growth in the United States, you're going to see growth in theCentral Region. I think given where we are in the North Sea,I think you could see some growth in the North Sea.We've had a bunch of ups and downs in the North Sea thisyear. Certainly, we're going to see some growth in Egyptas we have in the past and with two trains coming on that are going to come onat the end of the third quarter, you're going to see some significant growth inthe fourth quarter of next year coming out of Egypt.But we have an active drilling program there. Unless we get some surprises out of Argentina,you're going to see some growth in Argentina.I think the only area that we don't advertise growth in is the Gulf of Mexico, because that is a different part of our engine than therest of our regions, and it is wide open with respect to Canada.I mean, that's a function of how much capital and what kind of returns you canget in Canada,because many of you probably have heard me say, there's more gas in the WesternSedimentary Basin of Canada than any other place in North America.So it's just a question of economics.

Thank you. It appears we have no further questions. At thistime, I'd like to turn the conference back over to our presenters for anyadditional or closing remarks.

Thanks for joining us. If any of you have further questionsI'll be in my office. Thanks again.