Bob Dye - IR Steve Farris - CEO Roger Plank - CFO

Tom Convington – AG Edwards Brian Singer – Goldman Sachs Bob Morris – Banc of America Jules Yang – Citi Leo Mariani – RBC Capital Markets Tom Gardner - Simmons & Company John Herrlin - Merrill Lynch

Good day, everyone and welcome to the Apache Corporation second quarter earnings 2007 conference call. This call is being recorded. Today's presentation will be hosted by Mr. Bob Dye, Vice President of Investor Relations. Mr. Dye, please go ahead.

Thanks for joining us today. This morning Apache Corporation released second quarter 2007 results, which totaled earnings per share of $1.89 and cash flow of $1.47 billion, which is a non-GAAP number. Today’s discussion may contain forward-looking estimates and assumptions and no assurance can be given that these expectations will be realized. A full disclaimer is located on our web site. In addition, any non-GAAP numbers that we discuss will be identified as such with a reconciliation also located on our web site at www.apachecorp.com. Steve Farris, our CEO, and Roger Plank, our CFO, will now make prepared remarks prior to taking questions. With that, I'll turn the call over to Steve.

Thank you, Bob and good afternoon everyone. Thanks for joining us today. Apache second quarter results were outstanding. Second quarter production set an all time record yield by production growth in nearly every region. Our worldwide equivalent production was up 14% year over year and 7% relative to the first quarter of 2007. Our cash flow set an all-time quarterly record up 16%, relative to the same time last year, and 23% relative to the first quarter. Absent our non-cash impact of exchange fluctuations on our deferred tax liability and other revenues that were in the second quarter, earnings would have been $3.01 per share which would rank at one of the best quarters Apache has had also. Before going into our activity I'd like to thank many of you for attending our investment conference in Houston last month. The majority of my comments today will be on updating our view on Apache's portfolio and the continued progress we are making in key areas across the company. With strong first half of 2007 production, we are well on our way to achieving growth at the top end of our 9% to 12% production growth guidance that we gave earlier in the conference. We are also comfortable with our projection for 2008 of 6% to 10% and have 108,000 barrels of oil per day of production coming on line for 2009 and 2010 from six development projects in the pipeline. Our resource base can support double-digit growth through the remainder of the decade. Our specific year-over-year growth rates will be dictated by our commitments to deliver sector-leading shareholder returns. I'd like now to just give you an update of our overall portfolio. In the central region of the US, I'd like to really focus on two main resource positions. First we have a very material and attractive position in tight gas in Anadarko Basin which makes us the third largest gas producer in Oklahoma. We benefit from a low risk multiple drilling inventory and a low risk capture gas resource potential of 2.3 TCF. We have 20 rigs running in the Basin this quarter and production was up 20% in the second quarter of 2006. Next I'd like to turn to the Permian Basin, which is one of the most material long life light oil plays in the United States, and Apache is one of the leading players there. We produced 52,000 barrels of oil equivalent a day and we have about 1.3 billion barrels of captured resource potential. During the second quarter we completed the acquisition of the Anadarko Permian position which provides us incremental organic growth opportunities of nearly 200,000 acres that came with the acquisitions. At the end of the quarter we had five rigs running in the Basin and production was up 25% from the second quarter of 2006. In our Gulf Coast area which is a very steady generator of excess cash, we had record production also. Second quarter of 2007 is the highest point our production has been in our history and it surpasses what we were producing there prior to the Hurricanes Rita and Katrina. It also keeps us on track to realize nearly a $1 billion in excess cash for the year and underlying the steady contribution of this region, this is the fourth out of five years which we have achieved excess cash of between $800 million and $1 billion. The region had an outstanding quarter, all time record production was 35% up from a year ago and 9% from the first quarter of 2007. I would like to now turn to our international areas. I will first speak to Argentina and then go to the North Sea. Argentina is already proving to an excellent contributor to our portfolio. Over the last two years it has generated after tax returns of 19% and that is with an average gas realization hovering around a dollar. It has also generated organic production growth in the 10% to 20% range per annum. We have great running room and have over 1 billion barrel equivalent capture opportunity. During the second quarter of 2007, we saw further progress in the region as the Secretary of Energy enacted a large gas sales redistribution agreement that will effectively increase Apache’s realized price in the country by one-third. That agreement is expected to be implemented in the third quarter. With superior growth opportunities and attractive returns, we believe Argentina has outstanding potential. Turning to the Forties Field in the North Sea, the Forties Field is a multi-billion barrel resource and we are applying our material asset expertise with great results. We have nearly completed the top side refurbishment program that will extend the life of the field, and increase the recoverable reserves. We have now recovered all our invested capital and have an increased our remaining reserves by 35%. We have 450 million barrels of net resource potential in the field, and every one percentage point of additional recovery over the coming years gives us 50 million barrels of light oil. I should mention that the third quarter of 2007, our production will be impacted by our Alpha platform turnaround which will also be a time when we’ll be installing our back up total field compression. Echo and Alpha are linked, so we’ll be down about 20,000 barrels a day for 18 days and if you amortize that over the quarter, that’s about 3,900 barrels a day. The North Sea is a very attractive and material opportunity for us, as majors continued to shift their focus to other regions. We are well positioned as being a leading player to realize the value of the 6 billion barrels of commercial oil estimated to remain in the basin. I would like to now to spend the remainder of the time discussing what we call our edge regions, our three core international growth areas of Australia, Canada and Egypt. First in Australia -- and Australia is an outstanding resource growth potential for Apache. We now have four development projects in Australia alone that will deliver nearly 70,000 barrels of oil equivalent a day for Apache in 2011. Apache currently represents about 8.5% of our worldwide production. But with just these projects that we have in hand, it we will bring our production equal to 12%of our current worldwide volumes over the next few years. We have 12 million acres of leasehold, we have access to 2.1 billion barrels of resource potential. At the investment conference we highlighted our ongoing development projects, two exploration areas that we are focusing on over the next couple of years and the significant improving natural gas prices. At Van Gogh and Pyrenees developments, both of them are on schedule to add 20,000 barrels a day and both are proceeding on schedule. Last month we announced the results of our first quarter Donald development well at Van Gogh, the Theo 3-H well, and it tested at a rate of 9,694 barrels a day from the top of the main Barrow field play. We intend to drill 17 lateral holes in our development plan. The FPSO is under construction, first production is scheduled to come online in 2009 at a growth rate of 63,000 barrels a day and Apache is the operator and owns 52.5%. On July 3rd, BHP and Apache both sanctioned the Pyrenees development plan that includes 13 subsidy development wells which will be tied back to an FPSO also. First production is expected in late 2009 at a rate of about 90,000 barrels a day. BHP is our operator here and we have 28.57% working interest in the projects. In the first quarter of this year we announced the Julimar discovery that encountered 132 feet of net pay in three different sands. Two of those were tested at the combined rate of 85 million cubic feet of gas a day. Last week we announced a successful Julimar well that encountered 224 feet of net pay in six different zones which strongly solidifies our belief that we have a discovery in excess of a TCF of gas. Apache operates that with 65%. Currently underway, we are studying the development of Julimar and Reindeer, a discovery we made a couple of years ago, to bring on those platforms with first production expected to be in 2010. Combined, these developments should add about 28,000 barrels of oil equivalent a day in the latter part of 2010. Two expiration areas that we are pursuing in Australia, one is primary oil and the other is primary gas. In the Carnarvon Basin, we have several large gas prospects that are targeting cretaceous, Jurassic and Triassic reservoirs. With the John Brooks field and the Julimar discoveries as go bys, we are currently drill the Rosella prospect southwest of our 1 TCF Brooks field which is currently making 250 million a day from three wells; and later this year we will drill the Brunello prospect north of Julimar. Each of these prospects has the potential to find a TCF of gas. I might point out that actually drilling Rosella we have had a peak at the pay sand, and we have run a resistivity log and a gamma log. We have yet to run the porosity log; but so far we at least have the sands we were looking for. The gas markets in Australia turned sharply higher 18 to 24 months ago, really due to increasing demand from the mining industry, as well as a lack of uncontracted supplies from Apache and other producers in the basin. This situation is expected to last for a number of years and really should continue to sustain higher gas prices. Short-term contracts have gone for as high as $6.50 per MCF, over three times the $1.75 average price that we've received over the past ten years. We're also pursuing an exciting oil exploration program in the Gippsland Basin. And the Gippsland Basin has 23 known fields that have produced 4 billion barrels of oil and 5.5 TCF. We've been able to obtain a significant acreage position, directly adjacent to two 1 billion barrel fields that have never had 3-D seismic shot on it. We have contracted the Ocean Patriot rig for 18 months and have identified a number of prospects in the 50 to 100 million barrel range and we should have that rig available to us in the second quarter of 2008. Clearly, Australia will be one of Apache's key growth areas over the next several years. Turning to Canada, our Canadian portfolio gives us a very large resource potential in shale gas, coal bed methane and high impact deep gas exploration. Our Canadian shale gas resource potential alone is 6 TCF, and you'll be hearing more and more about our shale gas position in the coming quarters. After having worked the last three years on earning acreage on a massive farm-out from ExxonMobil, this year we are engineering our portfolio to a more balanced program of exploration and exploitation. As many of you are aware, we reduced our capital spending at the beginning of the year, but really have been able to keep our production steady which tells you something about the quality and depth of our portfolio. We have started to see meaningful reductions in cost in our shallow drilling areas during the course of the year, and we expect to increase our activity level during the second half of 2007. Finally, in Canada we've now drilled a 22-well pilot program in a coal bed methane play, if successful Apache has over 500 sections with resource potential in excess of a TCF of gas. Turning to Egypt, to give you a sense of the materiality of our position there, we're the second-largest independent E&P company across the Middle East. Based on reserve multiples of recent transactions, Apache Egypt would be worth in excess of $10 billion. Our current net production is 60,000 barrels a day and 235 million cubic feet of natural gas and we control over 19 million acres in the western desert of Egypt. At the end of the quarter, we were running 36 rigs which was up from 28 rigs this time last year. Because of our scale and our credibility, we've been able to work with our Egyptian partners in some creative ways. One of the ways is with our 2X project, an agreement we signed in the summer of 2005, to work together with EGPC to double Apache's production on our existing concessions by 2010. With 17% of our worldwide production volumes, doubling production in over five years at an equivalent compounded growth rate of 15% per year, will drive meaningful growth across the entire organization. This is visible growth from existing resources, which includes the production growth from water floods and further development of our Kauster field which totals about 40,000 barrels of oil per day. Our total Egyptian resource potential is 1.6 billion barrels. We're currently pursuing three exploration plays in the western desert, that combined have about 200 million barrels of oil equivalent discovery potential. They include the Matruh Jurassic A&B plays north of Khalda, South Teric Jurassic play which is east of our big Khalda concession, and the Bahariya oil play in the northeast. We also have about 200 million barrels of low-risk potential in several water floods that we're developing. Current major project activities are focused in the Asala ridge in East Bahariya, and the Carmon and Khalda in [inaudible]. So it's easy to understand why we're enthusiastic about Egypt and when you couple the growth rate with the fact that Egypt generally yields the second highest returns in the company behind the Gulf of Mexico, we can continue to grow in Egypt for a number of years. Before making a few closing comments, I'd like to turn it over to Roger Plank, Apache's CFO for a financial overview of the quarter.

Thanks, Steve and good afternoon, everyone. We did indeed have an outstanding quarter. To underscore Apache's progress so far this year, my comments will contrast the financial performance between the first and the second quarters of the year. In addition to record production, Apache delivered an excellent quarter with record financial results in several categories. Revenues of $2.5 billion were a record, as higher production coupled with continued strength in prices to beat our previous record by 9%. Cash flow of $1.5 billion exceeded our former record by 9% and earnings at $632 million or $1.89 per share were among our best ever. As we'll cover in a minute, despite the industry's continued cost pressures, our margins remained stout. Apache's financial story for the quarter revolves around oil. With demand strong and access to oil opportunities increasingly off limits, prices have strengthened to more than 10 times the price of North American natural gas. Apache's shareholders have benefited from our ample oil production, which significantly impacted our quarter. Oil production was up 9.5% during the quarter to 253,000 barrels per day. It represented 44% of our production, but it generated 60% of our revenue. The quarter also benefited from premium prices for our international oil production, while North American oil realizations rose around $5 a barrel to $60.72, international realizations jumped $10 a barrel to $66.75 on strong Brent and Tapas realizations. In fact, our second quarter Australian realizations which are tied to Tapas were just shy of $75 a barrel, the highest quarterly price we've ever received for oil anywhere. While we don't have a crystal ball on prices, we do believe Apache's balanced product mix give us a significant competitive advantage. At times such as this the 6:1BTU equivalent just doesn't adequately portray the market value of our oil. If you like oil, you ought to like Apache, particularly given that we have an estimated 60,000 barrels a day slated to come online from just three international fields over the next several years. Before breaking out our operating margins and costs, I want to comment briefly on two items in our GAAP accounting results that should be removed to see Apache's true financial performance this quarter. On the one hand, exchange rate fluctuations resulted in a non-cash deferred tax charge to our GAAP reported earnings. With the with U.S. dollar lower relative to the Canadian the theory is it will take more U.S. dollars to eventually pay our Canadian tax liability. So that difference was mark-to-market through our income statement. On the other hand, we also had a $24 million gain or $0.04 a share in other revenue related to timing differences in our Australian oil inventories, and this will balance out through the year. In fact, year-to-date other revenue nets to just a negative $2 million. Removing these changes in other revenue on the non-cash deferred taxes, gives you an adjusted earnings of $2.01 per share. This business is all about returns and Apache returns are quite competitive. Based on our performance so far year-to-date, annualized return on equity should average in the high teens and return on capital employed should average in the mid teens. Returns are, of course, driven by margins and we continue to focus on our margins. For the quarter, overall cash costs were up 5% to $13.72 per barrel of oil equivalent, primarily driven by higher production taxes associated with higher prices. However, realizations were up 12% equivalent, fully absorbing this cost increase and propelling our margins up 15% from last quarter to over $33 a barrel of oil equivalent. Even including a 4% increase in DD&A, our total pre-tax margin increased to over $21 per barrel equivalent from $17.40 sequentially. Focusing in on costs. On the lifting cost side, our second quarter LOE rate decreased $0.09 to $8.04 per barrel equivalent, a step in the right direction. This rate included $0.36 per BOE of lingering hurricane repairs which should wrap up during the third quarter, and $0.15 per BOE for the impact of stock-based compensation expense. Absent these swings, our second quarter running rate was $7.53 of BOE which is consistent with the first quarter and the base rate that we'd hoped to continue. G&A expense decreased $0.05 per BOE from first quarter to $1.36 per barrel equivalent, also a step in the right direction. This includes a $0.13 charge for an overdue change to our directors' retirement plan and absent this one-time adjustment, G&A would have been comparable to our anticipated ongoing run rate of approximately $1.25 per barrel. Full cost DD&A of $10.22 per BOE was up $0.43 with a full quarter's impact from the Permian acquisition, which was added at above our historic rate, and drilling costs which are also above historic levels. Severance and other tax of $2.52 per BOE rose $0.50 sequentially on higher revenues, primarily in the U.S. and North Sea. Finance expense increased $0.35 to $1.22 per BOE, increased debt for our Permian purchase, even so our debt-to-cap rate dropped to 26% from 27% on gains in our equity base from continued strong earnings. I commented on the impact that foreign exchange had on deferred taxes. Given the magnitude of the change in the exchange rate year-to-date and the lingering effect over the balance of the year, our second half rate should match the 42% that we averaged in the first half. Fortunately, the clock starts over every January 1st, so absent any FX changes, next year's rate should fall back below 40%. 41% of our taxes were deferred in the second quarter, consistent with a 40% to 45% target range. With gas at $6 an MCF in the near month I wanted to take a moment to briefly comment on hedging. Historically, we have used the cost of collars to underpin our economics for acquisitions and more recently, for our 2006 and 2007 drilling programs as well. Of nearly 400 million cubic feet per day hedged at Apache, just under 300 million cubic feet per day have floors ranging from $6.06 to $8.41, with an average floor of $7.13. These should mitigate the risk of further possible gas price erosion in the near term. We've also expanded this approach of hedging major investments, given that we now have committed in excess of $2 billion to develop the numerous discoveries that Steve discussed earlier. With capital committed today, and first production two years out, we thought it only prudent to enter into costless collars with $65 floors and ceilings as high as $80 a barrel to hedge from anywhere from 4,000 barrels a day to 7,000 barrels per day between July of 2009 and June of 2012. With two years before these projects come online, we have the luxury of time to determine whether or when we might add to these hedge positions. In summary, Apache turned in a fine second quarter and first half fueled by record production and the outlook for the second half is excellent. Steve Farris: Thank you, Roger. I might make just a few closing comments before we turn it over to questions. Apache continues to deliver top tier performance and is doing so with increasing momentum, driven by the strength and balance of our portfolio. We're among the E&P leaders in each of our core areas, tight gas and light oil in the U.S., deep gas exploration and conventional shale plays and coal bed methane in Canada, Middle Eastern oil in Egypt, with material exploration and water flood growth potential; large development projects and TCF sized natural gas exploration in Australia. This is fundamentally a volatile industry as witnessed by the recent pullback in U.S. gas prices. Unlike many of our peers, Apache does not rely on any single resource play type or commodity price, which puts our shareholders in an advantaged position. With 8.9 billion barrels of identified resource potential across 46 million acres worldwide, we have significant exploration potential in our core areas of Australia, Canada and Egypt. We have six development projects scheduled to come online over the next three years which will add 108,000 barrels a day by 2011. Apache therefore is well-positioned to continue to deliver outstanding growth and profitability into the next decade. We're obviously excited about the opportunities in front of us and with that, we'd like to turn it over to your questions.

(Operator Instructions) Your first question comes from Tom Convington – AG Edwards. Tom Convington – AG Edwards: Good afternoon. A question here on the shale play up in Canada, Steve. Could you give us a little more color on the acreage that is being built up there, the timeframe for evaluating that? Whether you have drilled any vertical wells, what kind of rates you are seeing? Along those lines.

It is a very competitive play. We have drilled some wells, we have also drilled a couple horizontal wells. As I said during my comments, you will see more and more of this over the coming quarters. Right now, there are competitive reasons why I would rather not answer that question. Tom Convington – AG Edwards: Are there characteristics of the shale play that are particularly attractive relative to some of the U.S. ones, or can you give us a sense of the –

I am sorry, I didn’t understand the question. Tom Convington – AG Edwards: Are there characteristics of the shale play that are particularly attractive relative to some of the U.S. plays that people have been exploiting over the last few years?

Yes, obviously we compared it to a number of plays, the shale plays that are happening in the United States and elsewhere. The amount of gas per section compare very favorably to other plays in the United States. Tom Convington – AG Edwards: Also in Canada, can you give us an update on your deep gas drilling in some of the other areas?

We are obviously drilling deep gas wells in Canada, and we have a deep gas well that we are currently drilling right now, but we have no results on it yet. Certainly that will be coming out in the next month or so. Tom Convington – AG Edwards: Finally in Egypt, in the Western Desert, you’ve recently picked up 9 million or 10 million acres west of your current concessions. Could you characterize the acreage and what your commitment is to drill up there?

We picked up about 10 million acres there. We have to drill three wells; we have to drill a well on each concession. We are shooting a 3-D seismic. We have a commitment to shoot some 3-D seismic which we will shoot significantly more than the commitment we have under the concessions. In fact, that seismic is being shot as we speak. Hopefully we will have potential wells being drilled this year on it. In terms of the productivity of it, it is very lightly drilled. There are actually 11 wells across that entire acreage position, so it is certainly big.

Your next question comes from Brian Singer – Goldman Sachs. Brian Singer – Goldman Sachs: Thank you, good afternoon. On capital spending, how impactful is the acceleration of activity in Canada in the near term? Separately longer term, how do you think about the spending needed to bring on the core projects you referenced in Australia?

Can you repeat the question? Brian Singer – Goldman Sachs: Sure. With regards to capital spending, how impactful is the near-term acceleration of activity in Canada? Separately longer-term, what do you see as the impact of capital spending needed to bring on the core projects in Australia?

In terms of our Canadian activities, we are going back and starting to drill some of our normal shallow gas stuff. It wouldn’t be significant this year. Certainly, the shale play in Canada over the coming 18 months could be significant. In Australia, we have the Van Gogh development is net to Apache of about $300 million and the Pyrenees development is about $500 million. Current scoping on Julimar and Reindeer are significantly more than that, in the $700 million range. If we are fortunate enough to find something down at Rosella, that will probably come through the island so it won’t be nearly as significant. Brian Singer – Goldman Sachs: That’s helpful. Separately, the production was quite strong in the Gulf region. Can you talk to that and the sustainability of that over the next few quarters?

Our Gulf regions had an excellent first and second quarter with the drill bit, frankly. We continue to drill wells, we have about 11 rigs running in the Gulf of Mexico. It is amazing what they can do when they can get back to work and quite having to clean up from the hurricanes. We are expecting at least steady to upward growth for the second half of this year in the Gulf of Mexico.

Your next question comes from Bob Morris – Banc of America. Bob Morris – Banc of America: Going back to Canada, you said the acceleration wasn’t significant, but I know you have had an $800 million budget there this year, which is a 35% drop versus last year. Can you give some magnitude as to how much that bumps up for the full year? In other words, instead of spending $800 million in Canada now is it going to be $900 million, or what will that go to?

Bob, I wouldn’t expect it to be a lot more than that. Most of that will be summer drilling or fall drilling before the winter drilling program comes on. Bob Morris – Banc of America: So $900 million is what you are saying?

It wouldn’t be much more than that. Maybe 120. Bob Morris – Banc of America: You just mentioned the Manville coal, that you completed a 22 well pilot there. Can you tell us a little bit more about the results or when you expect results? Your impression on the potential there at this stage?

We have three monitor wells and we have got 16 take wells. We are starting to dewater it. We are actually seeing a little bit of gas, which is a little early. So far, so good. We will just have to see how it waters down. But we are excited about it.

Your next question comes from Jules Yang – Citi. Jules Yang – Citi: Steve, you mentioned you have 12 million acres in Australia. Can you talk about any well commitments and exploration thresholds on that acreage?

Most of the Carnarvon basin, in fact we are drilling our only commitment well on acreage to save acreage right now. It is called the Baggs, it is north of the Pyrenees Van Gogh stuff. For the most part, that acreage is held by production or held under a concession that has production on it. In the Gibson basin, the majority of that is acreage that we have about five-year terms on, seven-year terms on, and we have a seven well commitment across that acreage position. Jules Yang – Citi: In the North Sea, you commented the majors are focusing away from that area. What are you seeing in terms of their interest in divesting assets in that area?

I am sure you have seen Shell’s announcement on selling some properties in the North Sea. Frankly, that is not something we would be interested in. I think the North Sea, like a number of other places in the world, for majors at some point in time they are going to start moving toward less mature areas. I think we probably would have seen that when we bought Forties back in 2003 had prices not gone up so quickly. We have nothing on the horizon today, but I expect that to take place over the next three or four years. Jules Yang – Citi: Just a long-term trend in that direction? The last question I have is, you mentioned good growth in the Gulf of Mexico. Last year you spent a lot of time and effort replacing production with relatively little reserve bookings. Is that situation with the growth in production today changing? Are you moving away from drilling PUDs and actually discovering new reserves, or are you still in the PUD mode?

We drill a number of new reserve projects this year. The one thing I would say is that we still have a number of down platform expenses coming out of Grand Isle 40, so you are going to see some of those numbers in our capital budget for 2007.

Your next question comes from Leo Mariani – RBC Capital Markets. Leo Mariani – RBC Capital Markets: A quick question for you in Argentina. I noticed that your gas price realization for the second quarter was about $1.02 here. I was under the impression that prices were improving, and this was down a little bit from first quarter. Can you give us a little bit of color on what is going on there?

It is real simple. What has happened is they are going through an energy crisis, and in fact a member of our board, and chairman and myself and Roger were in Argentina to add a little bit of the timeframe there. We actually had office buildings downtown shut electricity off at 4:00 in the afternoon. So what happens is that you get your gas redirected from your higher priced markets because of the high usage of gas by residential. We got redirected on quite a bit of our gas to go to a much lower contract. Frankly, we are seeing on commercial contracts, we are currently discussing a contract in the $3.90 range over three years. So you are beginning to see the inevitable when you start controlling prices, is they start going the other way, they are going to go up very quickly.

The other thing you have to keep in mind is that it is upside down to what we think of up here, in more ways than one. It is winter down there now. So the peak demand for residential heating is in the second quarter and the first part of the third quarter. So you have more gas that has to go into that lowest, fixed-price market during the winter months. In fact, they are having one of the coldest winters they have ever had, and actually while we were there they had their first snow in 90 years. So part of what you are seeing is that cold weather filtering through and instead of prices going up, which happened in the United States, they go down because you have these fixed priced markets to serve. But nonetheless, as Steve indicated, the incremental gas that doesn’t get diverted to the fixed priced markets is now going for around 3X the average price that you quoted for the quarter. So over time, as we bring in incremental volumes as we get out of winter, you ought to see that filter into our average price. Leo Mariani – RBC Capital Markets: On some of these volumes that have been diverted to the residential market, is that something that Apache mandated or is this a government mandated thing that has happened to you down there?

It is a government mandated thing when they don’t have enough gas, under any commercial contract they take the gas for the residential market.

One thing that Steve alluded to, that if you weren’t at our conference, that is benefiting us down there or should benefit us going forward is it is mandated by the government. The proportions are mandated by the government and they have just gone back and recalculated how much each company has to direct towards the fixed priced markets on a go-forward basis. So that pick up that Steve mentioned of about one-third in our price is as a result of our, under the new formula, having to deliver less into the fixed price markets sometime here in the third quarter on a go-forward basis. So our price ought to go from, if it was $1 it ought to be up closer to $1.50 on a go-forward basis, once that goes into effect. Leo Mariani – RBC Capital Markets: Sticking with Argentina, it looks like you had a fair bit of a production bump on the gas side from first quarter to second quarter. Are you guys out there pretty aggressively drilling for gas?

Yes. We are drilling for gas and in Tierra del Fuego we now have two of our rigs running there and we are drilling primarily for oil down there. Certainly we have been pleasantly surprised by some of the deep gas wells that we have been able to drill. In fact, when we were down there again we were testing, what is considered deep down there is certainly not considered deep in the Anadarko basin. But it came on for 13 million a day and 650 barrels of condensate a day, so as Raymond likes to say, the rocks are good; the rocks are friendly. We think we can continue that, frankly.

Not to beat a dead horse, but it took me forever to fathom all of this and get used to how it works. But under this new arrangement, we have to deliver roughly 160 million cubic feet of gas per day into the fixed price market. So when we bring on another 10 million over and above that, we don’t get $1; we get this free market price, so that is high $2, low $3. The world has changed for the economics, as Steve indicated. Our rate of return with the low price has been 19%. So the rate of return at triple the price is going to be quite a bit better than what it has been historically. Leo Mariani – RBC Capital Markets: I may have missed some of the early part of the call here, I guess I caught some comments on good growth in the Gulf of Mexico in the second quarter. Can you touch on the activities there in the U.S.?

Let’s start with the Anadarko basin. We have a very active drilling program there. We will drill in the central region, over 350 wells. We have 20 rigs running right now, and I would expect our production increases to continue there. We have had a very good drilling program so far this year, and there is no reason to believe it won’t continue. In the Gulf Coast, we had a very good drilling quarter, many of those things were coming on starting in the second quarter. We continued to drill wells. We continue to be successful. We are having a good year in the U.S., frankly.

Your next question comes from Tom Gardner - Simmons & Company . Tom Gardner - Simmons & Company : Over the past few months there have been a number of large M&A transactions. Can you speak to the current M&A environment?

Well, if you are talking about the recent large service merger, that is an interesting merger and it is probably one that a lot of people have talked about for – and not necessarily those two specific companies, but certainly in that sector there would be some amalgamation. In our sector, in terms of the E&P sector, other than a couple that have been out there like at Pogo that everybody expected something to happen to, I don’t see an awful lot of whispers about what is going on out there. Maybe I am not in the loop, which may be so, but I don’t think it is any different in that arena than it has been in the past. Tom Gardner - Simmons & Company : Following up with that, do you see a bifurcation of the market split along conventional resources and resource plays and would you tend to be a buyer of one versus the other? The same question with regard to domestic versus international assets.

I think there are really two sets to that. First of all, we have been and continue to be an acquisitive company. The one thing I would say is we spent an awful lot of time to create the critical mass that we have right now. So in terms of our appetite going forward is more of what would make sense for us over the long term, rather than just making an acquisition. Because we now have 46 million acres across the globe, and we definitely have the resource base to continue to grow internally. In terms of whether it would be U.S. or international, certainly in terms of maturity of areas, the maturity of the United States is by far the most mature basin in the world. Because if you look out away from that, I think you would be much more inclined to make an acquisition of size outside of the United States than we would inside the United States. Tom Gardner - Simmons & Company : With regard to Canada, I know there have been a number of questions but backing up more to the macro level, I would be interested in getting your view on Canadian drilling activity fall off, specifically do you see the activity ramping back up and when do you see gas production accelerating again?

Well there were a number of reasons for why Canadian gas drilling started falling off. Obviously the first is that it is expensive to do business in Canada, but today it is expensive to do business anywhere. You have to be very cognizant of the fact that if something doesn’t make sense, you shouldn’t drill it. But you also had the law change with the royalty trust, so an awful lot of bloom came off the rose in Canada at the same time. I will say, and this is a personal belief, that I think the Western Canadian sedimentary basin has more gas than any place left in North America. If you look at just the drilling density and the amount of gas that you find, certainly still a very good area. I know that a number of large independents have cut back their capital, and we have also. But long term, Canada is still going to be a very strong player for U.S. gas markets.

Your next question comes from John Herrlin - Merrill Lynch. John Herrlin - Merrill Lynch : Two North American ones, Steve. Oil field services costs have been coming down, how much further do you think your dollars will go on an activity basis this year in terms of your drilling program versus last year?

That depends, regionally. I will tell you especially in the Gulf of Mexico they will go quite a bit further because rig costs are down $50,000 to $60,000 a day. When you move on land, we are seeing probably a 20% drop in the mid-continent. And in Canada and some areas in our shallow gas areas, we have seen honestly, as much as 40% difference in costs we spent last year and the cost for well support this year. John Herrlin - Merrill Lynch : Say we are at $6 or under for the second half. Would you slow down your activity in North America for gas drilling?

Well, I think that is a selective question. Again, I think certainly our rates of return in the Gulf of Mexico are such that in that place, it is all about rates. In terms of Canada, I would tell you because of the differentials up there, if you are seeing a NYMEX $6, you are probably seeing under $5 in Canada. You really have to ask yourself whether or not you are going to allocate capital up there or just discretionary capital, or not. So if we get to that place, we will have to make that decision, John.

One thing I tried to allude to in my comments is, we will have to look at that and who knows how far – it would depend on what the price was too, but I did mention, we have 300 million a day of hedges that kick into place below $6. So we do have a mitigating factor in terms of the risk of that happening on a go-forward basis. That should help prop up cash flows somewhat. Frankly, we did that in conjunction with our ’07 drilling program. That ought to help us in that regard should prices deteriorate from here.

John, in all honesty, I think the economics are really based on two sides of the equation. One is the price, the other is the cost. I think if you see $6 gas for any extended period of time, you are going to see continuing weakening in service costs. You are going to have to, I mean…

At this time we have no further questions. I will turn the conference back over to management for any closing remarks. Bob Dye: Thanks for joining us, and as always, if any of you have any questions I will be in my office after the call. Talk to you soon.