Brady Parish - Vice President, Investor Relations Steve Farris - Chairman and Chief Executive Officer Rod Eichler - President and Chief Operating Officer

Arun Jayaram - Credit Suisse Pearce Hammond - Simmons & Co. Int'l Bob Morris - Citigroup John Herrlin - Societe Generale Bob Brackett - Sanford C. Bernstein John Freeman - Raymond James Doug Leggate - Bank of America/Merrill Lynch Joseph Allman - JPMorgan Charles Meade - Johnson Rice Leo Mariani - RBC Capital Markets Brian Singer - Goldman Sachs Michael Hall

Good afternoon. My name is Rachel, and I will be your conference operator today. At this time, I would like to welcome everyone to the 2Q Earnings 2013 Earnings Release Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. I would now like to turn the call over to Mr. Brady Parish, Vice President of Investor Relations. Sir, you may begin your conference.

Thank you, Rachel. Good afternoon everyone, and thank you for joining us for Apache Corporation’s second quarter 2013 earnings conference call. On today’s call, we will have three speakers making prepared remarks prior to taking questions. I will start by giving a brief summary of the second quarter results, and then we will hear from Steve Farris, our Chairman and Chief Executive Officer; followed by Rod Eichler, President and Chief Operating Officer; and finally, our CFO, Tom Chambers is out today so he has asked me to pinch it for him with respect to his remarks. We've prepared our quarterly financial supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or pre-tax margins. In addition, we have prepared an operations supplement to summarize our activities across the various Apache operating regions. These can both be found on our website at www apachecorp.com/financialinfo. Today's discussions will contain forward-looking estimates and assumptions based on our current views and most reasonable expectations. However, a number of factors could cause actual results to defer materially from what we discuss today. A full disclaimer is located with the supplemental data package on our website. This morning, we reported second quarter 2013 earnings of $1 billion or $2.54 per diluted share. Cash flow from operations before changes in working capital totaled $2.6 billion. Adjusted earnings which exclude certain items that impact the comparability of results totaled $801 million or $2.01 per diluted share. In the second quarter total net production averaged approximately 790,000 boe per day with liquids production constituting 54% of the total. This represents an increase from the 782,000 boe per day reported in the first quarter and the 774,000 boe per day reported in the second quarter of 2013 was negatively impacted by a decrease in North Sea production of 6000 boe per day from the first quarter partially due to deferred production as a result of unplanned facility maintenance at the Forties Field as well as natural fuel decline in some of our other international regions. One final item of note before I turn the call over to Steve. An effort to further provide transparency with respect to our disclosure of oil and gas production we’ve included within our quarterly financial and operation supplements say more detailed breakout of net production for our Egypt region. As you can see on the bottom of pages five through seven of the financial supplement. We have provided three separate line items for Egypt production. Gross production, net production with tax which is gap and net production without tax. For the terms of our production sharing contracts the state owned petroleum company EGPC pays our Egyptian income taxes on our behalf using the share of it's profit oil. As a result for accounting purposes we record income tax with an equal and offsetting increase in our oil and gas revenues. As you can see this accounting treatment is both earnings and cash flow neutral. However it does result in Apache recording additional production volumes what we call tax barrels, because the recording of the tax barrels is both earnings and cash flow neutral we’re disclosing Egypt net production with tax barrels which is GAAP and without tax barrels for completeness. If you were to exclude tax barrels from total reported production, our second quarter 2013 net production would have been 751,000 boe per day versus 727,000 boe per day excluding tax barrels in the second quarter of 2012 which is a 3.3% increase. This compares to the 2% increase based upon our reported net production which includes tax barrels. We have included an illustration of our Apache’s production breakdown on page four of the operational supplement for your review because Egypt tax barrels introduce additional variability in our reported net production. We have included this additional disclosure in an effort to assist you and estimating production on a quarter-to-quarter basis. We will be posting a presentation at a later date that includes a detailed illustrative example of the mechanisms and accounting for a typical EPSC to help further enhance transparency. With that I’ll turn the call over to Steve.

Thank you Brady and good afternoon everyone and thank you for joining us. As Brady said Apache reported a strong results for the quarter, we generated over a $1 billion of earnings and more importantly $2.6 billion of cash flow from operations. I think the most important thing about the last quarter is we are transitioned towards more North American onshore growth was evidenced again this quarter with each of our four onshore North American regions significantly increasing liquids production both year-over-year and quarter-over-quarter, which are at attractive rates of return. As a result, our onshore North American liquids production increased to 175,000 barrels of oil per day and that constitutes 41% of our total worldwide liquids production and over 22% of our total overall production. This represents an increase of over 6% quarter-to-quarter and nearly 42% from second quarter of 2012. In addition, our onshore North American crude oil production increased to nearly 120,000 barrels a day, an increase of 26% versus second quarter of 2012 and now it comprises over 15% of our total production. Digging more, our U.S. onshore resource base continues to deliver sector leading performance. Apache is the most active U.S. onshore driller with 81 rigs currently running. During the second quarter, we averaged to combine production of 214,000 barrels of oil equivalent a day from our Permian and Central regions alone, or 27% of our total production. This represents more than a 34% increase over second quarter of 2012 and a 28% increase after adjusting for the Cordillera acquisition which we closed on April 30, 2012. In the Permian, we are currently running 45 rigs. In the Anadarko Basin, we are running 35 rigs. And as a result of this drilling activity, we remain on track to achieve our guidance of greater than 25% North American onshore liquids growth during 2013. I would like to turn to Egypt right now. During the second quarter and throughout the recent political unrest, our operations have remained uninterrupted. In fact, I traveled to Cairo, last Thursday night I was in Cairo Friday through Tuesday of turning our quarterly operational review at an opportunity meet with the new minister of petroleum in a number of new administrations who have reiterated the importance of Apache’s investment in Egypt. Frankly, it was business as usual. We are currently running 26 rigs in Egypt. This morning we announced several impressive discoveries across our vast position in Western Desert. These discoveries continued to highlight the prospectivity of our $9.7 million gross acreage position. Now, moving from the second quarter results, I would like to provide a brief update with respect to our portfolio review process. I mentioned in our first quarter earnings call after significantly both during our onshore North American asset base over last 3.5 years. Last fall, we embarked on a strategic preview of our portfolio with the ultimate goal of keeping the right mix of assets that generates strong returns, drive a more predictable production growth and create shareholder value. Since the beginning of this year, we have begun executing on multiple processes with respect to a robust list of priority divestiture candidates. On July 18th, we announced our first divestiture when we sign an agreement to sell our Gulf of Mexico shelf operations to Fieldwood Energy for $3.75 billion on cash, net of $1.5 billion of P&A liability. We also retained 50% interest in deeper rights, including what we consider exciting subsalt plays. We are moving forward on our other processes and we will keep you at price of our progress. We hope to have additional transactions announced before year end. Given the highly confidential and sensitive nature of these potential transactions, we are not going to provide any further details at this time, but we will update you as progress unfolds. At the end, we intend to use the net proceeds to be received from the disposition of these priority assets to reduce depth and repurchase shares under our 30 million share authorization from our Board. And through the end of the second quarter, we have repurchased 2.9 million shares. The share repurchase program combined with our recent increase in our dividends I hope demonstrates our continued commitment to deliver value to our shareholders and reflects confidence in the underlying value of our business. Please keep in mind all of these potential transactions and the use of the proceeds received or subject to market conditions and I want to rest assure we’re dead eye serious about rebalancing our portfolio and emerging from this process is even stronger company than we’re today. We want to continue to do what we think we do best which is export our vast inventory of opportunities rigorously allocate capital to generate great attractive rates of return and profitably and more predictably grow our production and create long term value for our shareholders. I would now like to turn the call over to Rod Eichler.

Thank you Steve and good afternoon. We have once again compiled an operation supplement detailing our activities across all 10 of our regions. I would like to take a moment to highlight some of our activities in the Permian and Central region and in Egypt. As Steve mentioned we had an outstanding quarter drilling and completing wells across the globe and we continue to ratchet up production on our North America onshore liquid plays. During the second quarter we averaged a 116 rigs worldwide and completed 343 total gross wells with a 99% success rate, 248 of these wells or 72% were located onshore at North America. At our Permian and Central Regions alone we completed 215 gross wells or 63% of our total. Our production in North America onshore liquids grew 42% over the prior year to a 175,000 barrels per day and was predominantly by our Permian and Central regions. Combined these two regions grew liquids production approximately 8000 barrels per day quarter-over-quarter or 6% to a 136,000 barrels per day which represented nearly 32% of total worldwide liquids production. Combined production of these regions was 214,000 boe per day representing 27% of total company production for the quarter. In the Permian region we averaged a 123,000 boe per day 74% liquids constituting nearly 16% of our total production. This represents 18% production growth over the second quarter of 2012. We continue to be the most active driller in the basin holding a record 41 rigs for the quarter. We spot 214 gross wells of which 58 were horizontal and completed a 128 gross wells during the quarter. Along with Deadwood, drilling at Barnhart is down leading the region in production growth along with three bar (ph) and a Yeso Play in New Mexico. We continue to add strong results in our vertical drilling program and Deadwood and area acquired in the 2010 transaction we now have over 600 operating wells for this year in the field. Second quarter drilling activity at Deadwood focused on the vertical (inaudible) play maintain a six rig vertical Wolfwood (ph) campaign and our Lower Cline Shale Development Program. The region continued it's successful (inaudible) program on four recent vertical wells in the play averaging IPs of approximately 300 barrels of oil per day, 70% oil. The Lower Cline Shale program continues to increase inventory and results. Our 2013 11 wells have been drilled and there are 28 wells remaining for the year. Our 30 day average IP for 2013 Cline wells online through second quarter is 311 boe per day 81% oil. Currently our lower Cline inventory is spread over more than nine sections. Well spacing for (inaudible) and for 3D seismic conversion interpretations are all being evaluated to optimize the development program. Also during the quarter the Barnhart area was extremely active with key two production growing 32% on the second quarter of 2012 and averaging 4700 barrels oil per day and 13.5 million cubic feet of gas per day. We continue to run six horizontal rigs toward the upper and little Wolfcamp shale. By the end of the second quarter we had drilled 37 wells with a total 83 expected by year end. We now have a total of 26 Apache operated horizontal Wolfcamp wells producing in the field with average 30 day IP in excess of 600 boe per day. With respect to cost reductions one of our focus areas has been the conservation of water resources as frac operations have employed the use of 1.2 million barrels of recycled flow back water. After initial drill out of frac wells all flow back and produce water from the horizontal development is recycled for us in the future frac jobs thereby conserving the non-potable groundwater available in the area and reducing our overall water cost. During the second quarter we also added two rigs to our Three Bar Shallow Unit with selling and development of the Wichita Albany reservoir. A total of 7 wells spud another successful horizontal completion was added to that field. One well of note was the Three Bar Shallow Unit 113H drilled to a measured depth of 13,200 feet with a 6,000 foot lateral section. After a 16-stage frac, the well began production on May 9 and recently tested at rates of 795 barrels of oil per day and 1.3 million cubic feet of gas per day. Six additional wells are in various stages of completions, flow back and tie-in. Two vertical and one horizontal rig continue to develop the Yeso play of New Mexico. For the second quarter, 27 new Yeso wells all verticals were brought on production. Gross production for the 2013 Yeso drilling program doubled from 1,500 barrels of oil per day and 3.2 million cubic feet of gas per day to about 3,000 barrels of oil per day and 6.3 million cubic feet of gas per day during the second quarter. Completion activity on 8 horizontal wells drilled to-date should commence later in the third quarter. Looking ahead to the third quarter of 2013, Permian expects to maintain an active rig count of 45 drilling rigs of which 20 will be horizontal. Moving now to Anadarko Basin, we are in our central region we averaged 91,000 barrels of oil equivalent per day in the second quarter. This is approximately 4,700 barrel of oil equivalent per day, or 5% increase over first quarter 2013 production, and notably 100% of the quarterly growth came from oil and natural gas liquids. Our liquids production rose 12% quarter-over-quarter to 45,000 barrels per day. Liquids now represent nearly half of our total region production versus 29% in the second quarter of 2012. During the quarter, we accelerated activity in the Anadarko and Whittenburg basins. We further exploited our vast resource potential by running an average of 28 rigs of which 27 were horizontal and completed 87 gross wells. We are currently running 35 rigs in that region and remain on track to drill 300 wells during 2013. About a third of our program will target prolific liquids-rich Granite Wash with another third targeting the oilier Tonkawa. Rigs will also continue to work the Cleveland, Marmaton, Cottage Grove and Canyon Wash plays. In our liquids-rich Granite Wash play, our wells continue to come on strong. Two recent well result highlights include the Ramp 26 #7H with an IP of 199 barrels of oil per day and 7.5 million cubic feet of gas per day the Ramp 27 #7H with an IP of 139 barrels of oil per day and 7.4 million cubic feet of gas per day. We still have many years of well locations and our resource inventory awaiting exploitation. In the oily Tonkawa play we had strong results in Roger Mills County with our three largest completions averaging over 500 barrels of oil per day and approximately 600 Mcf per day. Again, Apache has identified years of viable well locations in our resource inventory. In Ochiltree County, Texas, we have a successful Cleveland program underway with our most recent four completions coming on with an average IP of 540 barrels of oil per day and 630 Mcf per day. The Marmaton formation is also showing strong results with recent completions averaging 400 barrels of oil per day and 4.9 million cubic feet of gas per day. We are also having tremendous success in our Cottage Grove play development and the Stiles #23-3H well came online at 790 barrels of oil equivalent per day, 82% oil. In our Canyon Wash play in the Texas Panhandle, we brought on several strong vertical wells including the (indiscernible) with an IP of 1,237 barrels of oil per day and 1 million cubic feet of gas per day and the Boys Ranch 116 #10 at 984 barrels a day and 101.3 million cubic feet of gas per day. In addition, our two most recent wells are flowing back after frac at a combined rate in excess of 3,000 barrels of oil per day. We are also continuing to drive down drilling and completion cost through detailed analysis of even smallest operations. In May, we reported $5 million of drilled and completed Tonkawa well. Thanks to the efforts of a number of Apache engineers, petrophysicists and geologists. We have lowered that number by nearly $1.5 million with production results equal to or better than before. During the second quarter, we also concentrated heavily in our Tonkawa bit, motor, torque, and drag combinations. Half of the 25 Tonkawa wells drilled in the quarter had significant rate of penetration increases with our last two wells drilled in under two weeks versus four weeks six months ago. We mentioned on our last earnings call that we have lowered our average Granite Wash completing well cost by $1.3 million to $2 million per well. The same team that reduced our Tonkawa cost by nearly half is now focused on the Granite Wash, so we anticipate additional future cost savings by continuing to apply best practices we expect to reduce cost further and apply these technicians to our other plays. As Steve mentioned our operations in Egypt remain uninterrupted and we continue to find new oil and gas discoveries in the prolific Western Desert. In fact this morning we reported seven oil and gas discoveries across four basins at six concessions. Our continued success highlights a geologic and geographic diversity across the company’s 9.7 million gross acres in Egypt’s Western Desert. The discoveries include the Riviera South West-1X on the Southern Plank of the Abu Gharadig Basin which test flowed 1500 barrels of oil per day and 2.8 million cubic feet gas per day for the Lower Bahariya sand. And the Faghur basin we had four new discoveries including the Narmer-1X which encountered 85 feet of net pay in the middle of Jurassic Safa sand. The wells have flowed 1166 barrels of oil per day and 400 mcf of gas per day. Despite downtime in the North Sea we did have some positive news recently at our Bacchus field. Last month we completed our third successful development well Bacchus B1 which mobbed 257 feet of net oil pay along our horizontal wellbore and high quality Jurassic Fulmar sandstone. Production commenced from the B1 during the fourth week of July adding 9400 barrels of oil per day of new rate taking the field to 17,600 barrels of oil per day with plants to further optimize the rates and operating conditions of the subsea infrastructure. During the third quarter we planned to acquire a new treaty seismic survey over Bacchus in order to identify further development opportunities. That concludes the operational highlights. I’ll now turn the call back over to Brady.

Thanks Rod. This morning we reported earnings of 1 billion or 254 per diluted share. Overall our bottomline results reflect an another solid quarter of financial performance driven by increased production. Our production this quarter averaged 790,000 barrels of oil equivalent per day. Oil and gas revenues totaled $4.1 billion for the quarter flat with the first quarter; oil revenue was lower as higher production volumes were offset somewhat by a drop in the oil prices. Gas revenue was slightly higher than the first quarter as higher prices offset a slight decline in production. Oil accounted for 78% of total revenue. Including the impact at hedging second quarter oil prices averaged $97 and $0.93 per barrel down $3.79 from the first quarter our gas prices averaged to $3.87 up $0.15 per mcf for the first quarter. As a result we generated 2.6 billion of cash from operations before working capital items. We were able to consistently generate these cash flow levels given the fact that over 45% of our total production on a boe basis is oil which continues to sell for well over 20 times the price of North American natural gas. In addition our international gas portfolio is continued to bolster our realizations as our international realizations exceeded those in North America for the sixth consecutive quarter. We head the portion of our 2014 production to secure prices in cash flows that will support our continued growth through our very active drilling program. We hedge 62,500 barrels per day at WTI crude oil at almost $91 per barrel and 62,500 at Brent crude at just over a $100 per barrel. When you look at our income statement this quarter you will notice a new line item titled derivative instrument gains, losses, net. This line item represents the mark to market impact of our oil and gas commodity price financial derivatives and was segregated due to the magnitude of the amount of $247 million gain in the quarter. This line item will continue to appear each quarter as long as we have financial derivatives and be one of the components utilized to calculate adjusted earnings. Our focused drilling program produced a 42% increase in liquids production in North America onshore properties from the prior quarter and 6% increase for the first quarter. This is primarily driven by continued strong results in the Permian and Anadarko Basins although as noted earlier each of our four North American onshore regions increased their liquids production from second quarter a year ago and sequentially versus the first quarter. Worldwide liquids production for the quarter averaged 426,000 boe per day an increase of 10% from the comparative 2012 quarter and 2% sequentially. For Apache our liquids growth and drilling opportunities are primarily focused on crude oil. Over 84% of our second quarter liquids production is crude oil. Our production efforts directly translated into a pretax margin that exceeded 35%. Our operating costs for the quarter were up 5% sequentially driven by increased repair and maintenance and power and fuel costs. Typically repair and maintenance cost run higher in the second and third quarters each year as we compress this work into the favorable weather window. I also wanted to note that second quarter earnings were impacted by $59 million deferred tax expense for foreign currency fluctuations in addition to the after-tax commodity derivative mark-to-market gain of $156 million both of which are non-cash adjustments. Adjusting for these non-cash items, we were near $801 million or $2.01 per share versus $2.07 a year ago and $2.02 in the first quarter of 2013. Turning to taxes, the second quarter effective tax rate of 37% primarily reflects the impact of foreign currency fluctuations on deferred taxes just mentioned. Absent this foreign exchange movement for the quarter, our effective tax rate would have been a more typical 40%. Similarly, this adjustment impact in our percentage of deferred taxes in the quarter. We would expect the deferred rate of approximately 25% for the year absent the adjustment. Detailed calculations for margins, adjusted earnings, adjusted tax rate, and cash from operations can be found in the financial supplement located on our website. Looking at the balance sheet, our ability to generate consistent operating cash flows continues to support our robust drilling program and other planned capital expenditures. This quarter, our total debt balance increased slightly, but at the end of the quarter our debt to capitalization ratio was 28% the same as last quarter. However, as Steve mentioned earlier, we are working to rebalance our portfolio by actively pursuing asset sales to be completed in 2013. Proceeds from the first of these, the Gulf shelf sale for $3.75 billion will be used to reduce our debt including commercial paper balances and $400 million of debt maturing in September, and we purchased Apache common shares under a 30 million share repurchase program authorized by the board earlier this year. At the end of the second quarter, we took the opportunity to initiate the share repurchase program and buyback 2.9 million shares. The results of our efforts to rebalance our portfolio will enhance our debt maturity profile, preserve our balance sheet flexibility to fund operations and growth and enhance shareholder value. This concludes our prepared remarks. Operator, we are now ready to open the line for questions.

(Operator Instructions) And your first question comes from the line of Arun Jayaram. Arun Jayaram - Credit Suisse: Good afternoon, gentlemen.

Good afternoon. Arun Jayaram - Credit Suisse: And Steve understanding that you are not probably going to provide a lot of details, but I do want to maybe see if you could give us maybe some broad thoughts as you look to rebalance the portfolio obviously you announced the Shell, but from here will the portfolio look pretty similar to what you have today? I mean, are you thinking of more smaller types of transactions down the road or could we see something pretty meaningful where you really reduced the size of the organization to increase your leverage to the U.S. onshore properties which are growing pretty sharply? So, just trying to get your thoughts on from here what the scale of the asset sales could look like?

Well, I – thank you for the question. I think we said during our first quarter earnings call, we had a robust list of assets that we were in the process of marketing, which we still do. We have multiple processes going on at the same time. The end results of this and I have said it before, but the end results of this is we want assets that can grow or we want assets that can generate cash to fund that growth. And if you think about where that portfolio would lead you, it would lead you more towards North American onshore. The other thing we have said and I made a comment about being in Egypt and it was business as usual, I drove around Cairo for three days and it was very quiet and business as usual but we also recognize that we need to find a way to validate the value of Egypt for our shareholders and we continue to work on that also. Arun Jayaram - Credit Suisse: And Steve just a follow-up maybe on the North Sea you commented about, you had a little of maintenance related downtime, can you give us maybe some thoughts on how the back half of the year could like in terms of production. I know that the third quarter you generally see some turnarounds and things like that but just maybe some comments on the North Sea.

The North Sea does go through, we had some unplanned downtime in the second quarter, we had some planned downtime in the third quarter. We have a turnaround schedule, our production will be down a little bit from the second quarter and then our expectation for the fourth quarter is to be considerably stronger than the rest of the quarters of the year.

And your next question comes from the line of Pearce Hammond. Pearce Hammond - Simmons & Co. Int'l: Steve how should we think about total company production growth for on the divestiture the Gulf of Mexico Shelf in the past, we’ve talked about kind of total company production growth of 3% to 5% then of course that included the shelf. So how should we think about that moving forward?

And that’s a very good question and it really, when we come out of the other side of this when depending on how much we get done this year we still have the a large portfolio or a pretty robust portfolio things we would like to divest up. When we get through with that what we will see is by it's nature that our North American onshore will become a bigger part of our portfolio so we would expect our future growth to be stronger than our 3% to 5%. Pearce Hammond - Simmons & Co. Int'l: And then my follow-up is just a little bit how do you feel like you’re progressing right now on the Wolfcamp currently and do you think there is an upward bias to the 350 million boe resource potential figure that you put out last year at the Analyst Day because it looks like you got some attractive acreage shelf over in Upton County and a little bit Midland County and Martin County as well where some other operators have had some good wells.

I’m going to let Rod talk about the detail. So one thing I would say and for the most part we had a presentation back in June of 2012 where we did some tight curve. For the most part we have exceeded those tight curves in the Wolfcamp, in the Deadwood area and the Cline et cetera. But as Rod pointed out we have six rigs running, we continue to be very active there.

We have 45 rigs currently operating as a Permian we have about 20 of those rigs were operating in the southern half of the Midland basin. Big concentration in Deadwood and Barnhart where we have a strong acreage concentration which I talked about but we have a lot of other blocks of acreage in Midland County area and I have some other operations I mentioned some results just in the last day or two, we have acreage in the cities, in fact we have two wells are currently drilling and testing offsetting some of those results that were just recently announced and we have great expectations, we continue to the success on the Wolfcamp. We’re targeting two different landing zones in the middle Wolfcamp across the area.

I think to answer your question in broad terms you will probably see our resource potential in the Wolfcamp from what we put on June of 2012 we’re going to have an analyst day later this year probably in the fourth quarter but I think you will see those resource potentials in the Wolfcamp go up from where it was.

And your next question comes from the line of Bob Morris. Bob Morris - Citigroup: Steve you last quarter mentioned a full year budget of $10.5 billion that you’ve increased activity in both the central region and the Permian. What has been the impact on the budget apples-to-apples. I know there was some associated with the couple of Mexico shale but on an apples-to-apples basis what is the impact on that $10.5 billion from the increased activity seen on sort of North America.

Well at the present time we’re running at a pace would outpace that a little bit but we intend to gauge our capital program with our sales proceeds and also our cash flow. We are also ahead a little bit on our cash flow. Bob Morris - Citigroup: So, that $10.5 billion apples-to-apples maybe goes up couple of hundred million or $500 million for the increased activity, source it elsewhere and (indiscernible).

Honestly, probably the higher number. Bob Morris - Citigroup: Okay, alright.

And I will tell you honestly, I mean, we are talking about we are at the end of July. So, we still got five months of activity level yet, so… Bob Morris - Citigroup: Alright, thank you.

Your next question comes from the line of John Herrlin. John Herrlin - Societe Generale: Yes, hi. Quick one for you, Steve, in terms of the reconstituted Apache, conceivably could you be more like 70% on conventional and the rest conventional given the added North American focus?

That’s a pretty strong number. I would say this Canada has to be a part of our portfolio going forward. We are in the Permian. We are in the Anadarko Basin. We are re-looking and doing a resource assessment in our Canadian region. We should start seeing some results of that in the next couple of weeks internally, and we’ll make that presentation in the fourth quarter or at the Analyst day, but what we would like to have is three areas in North America that is predominantly unconventional. I doubt if we ever get to the 70% range, but it certainly will be a bigger part of our portfolio. John Herrlin - Societe Generale: Okay, that’s fair. Next one from me and last one is your Permian well reserves you are giving 30 days what would the IPs be, because it looked like in the Central region you were giving shorter-term IPs and not 30 days. So, I was just wondering how these wells started?

I believe that we use 30 day IPs across the board unless we say otherwise. That goes in the Central region as well as the Permian.

Obviously, Rod, yes, the initial 24-hour test would be, I don’t want to say significant, it would be certainly quite a bit larger than what our 30-day IPs are. John Herrlin - Societe Generale: Okay, thanks.

Your next question comes from the line of Bob Brackett. Bob Brackett - Sanford C. Bernstein: Hi, good afternoon. Any update on Kitimat and we still in some of the LNG projects?

Wheatstone continues to move forward. We are finally getting in a range, where the end of 2016 isn’t that far off. So, one thing I would say is is that based on our models and our partner’s models, when that comes on, it will pay out in 4.5 years of all our costs and it will generate about over $1 billion a year net to Apache. So, as we get closer to that time it becomes more and more interesting. The Kitimat project frankly is we are going through a supplemental FEED with Chevron. Chevron has now taken over the operations of the downstream. We are operating the upstream. We had a meeting with our Chevron counterparts last week and went through a number of things. The predominant one was marketing, and although I can’t talk specifically about it, they are high and behind the marketing side. Obviously, marketing is going to drive this program. Bob Brackett - Sanford C. Bernstein: Great, thank you.

Your next question comes from the line of John Freeman. John Freeman - Raymond James: Good afternoon. On the Central region, you announced a group of pretty solid Canyon Wash wells and I know that Rod, you mentioned that you are still sticking with the same game plan of third-year rigs on the Granite Wash, a third at Tonkawa, and a third in these other areas, and I am just curious if maybe not this year, but next year if Canyon Wash just based on the fact it appears to be pretty strong results, a lot oiler than some of these other plays if that might start to get some incremental rigs as its in the least developed of your central region properties?

Of course, it’s a new property for us having just started this discovery about two years ago. We have about 35 rigs operating in that region by year end. Well, probably one or two rigs continue to operate in the Bivins Ranch area. It’s a vertical program. We drill the wells relatively quickly. We anticipate drilling into a water flood opportunity that exists in that (inaudible) field in the very near future. But we’re very pleased with the results we have seen to-date.

Yeah we have about 130,000 acres there and I think they are actually going to drill a horizontal well in there fourth quarter this year. Number of operators on either side that are experimenting with horizontal wells. John Freeman - Raymond James: And just one follow-up from me, in the Permian another pretty good Wichita Albany well, can you remind me I know you’re adding rigs there, what sort of the running room is there. Is that present across majority of your central basin platform acres, is it isolated into one area?

In the three bar unit area we have probably about two dozen locations that we’re currently exploring. It's been a very robust program to-date and we’re just now been able to step out in other blocks of acreage we have in the same county to see if that same kind of high potential exists on those other acreages we have.

I think the most interesting thing about a number of other operators and ourselves is that the future of the Permian is still an emphasize, because it is a tremendous amount of oil in place there and you see quarterly and including ourselves trying new ideas and going horizontal in new plays and you really have a real tremendous potential continuous to be in the Permian basin that is untouched. People haven't even thought about it yet.

Your next question comes from the line of Doug Leggate. Doug Leggate - Bank of America/Merrill Lynch : I’ve got two, one is on Egypt and the another one is maybe a little bit off the wall but the way things to Permian but. On Egypt, Rod there has obviously been another stream of tremendous success over there it's obviously not getting any purchase at the market currently given the situation but can you just tell us today as things stand how do you see the running room, the scope for additional growth and following your conversation Steve what is the risk that you see any changes, the tax regime or anything has really threatened your operation as thing stand today. And I’ve got a follow-up.

All that Rod talk about the what our running room is in terms of our operational position and then on my comment on our view of what’s happening in there from a political standpoint.

Yeah Dough we’re clearly running 26, 27 rigs in Western Desert. We anticipate drilling a similar program in 2013 probably about 2075 wells as we had 2012 so the program level of activity is continued to pace for the previous years, pre-revolution. Our gas production as an example is it's record levels. In fact we have some facility constraints our gross operating production is running about 920 million cubic feet of gas per day and in the second quarter we managed to finally put on the 24 inch pipeline from Abu Gharadig to Dashur which we have been working to restore to it's original operating parameters when it was held by BP and we now have half that line, half of the capacity being put into service. So we anticipate to continue the same kind of program with a good prospect inventory and the every year we show this at Analyst Day presentation as the inventory both drilling and then completion opportunities as well as work over opportunities it seems to be no change in the actual amount of the inventory grown going from year-to-year even though we continue to grow 300 wells and do well over 1,000 work overs and rig completion opportunities every year.

And I'm going to prep with this with the comments that, we've recognized the uncertainty and how our shareholders view Egypt and we're working on how to validate that. Having said that I will say this and I have said it many, many times. Egyptians are Egyptian first and Arab second and I think if you see what's going on currently you get a pretty good picture of that. I mean they want stability in terms of our position in Egypt we met with the Minister of Petroleum, we met with the Minister of Investment, we also met with the Minister of Industry and Trade and met with a number of business people over there that I have met over a period of years with the US-Egyptian Business Council. The importance to Egypt of Apache or the importance of Apache being in Egypt it is very big. We are the most active driller. We drill more wells than everybody else combined in the Western Desert. And I say this and it’s a factual statement and I understand the uncertainty, but from the way we see it, would it be very difficult for Egypt to change our tax regime or change our position, because we are their oil growth in Egypt going forward. Doug Leggate - Bank of America/Merrill Lynch: I appreciate the answers, frankly, my kind of off the wall follow-up, so today one of your competitors, I guess smaller competitor Pioneer announced another stream of strong well results in the Permian stocks up significantly. I am just curious as to whether you would ever consider separating your Permian business as part of your broader portfolio, if you are given the value that’s not been recognized in your portfolio that has been recognized elsewhere? And I’ll leave it that. Thanks. Like I say it’s a bit off the wall.

Yeah, truthfully, I think we are getting good value for our Permian assets. I think it needs the Permian and the Anadarko and some of the other things we are doing needs to be a bigger part of that portfolio, and that’s what we set out to do. And honestly, we are (indiscernible) serious of doing that. Doug Leggate - Bank of America/Merrill Lynch: Alright. Okay, fine. I will leave you there. Thanks.

Your next question comes from the line of Joseph Allman. Joseph Allman - JPMorgan: So, Steve your comment about validating the value of Egypt that seems to imply some kind of monetization, could you just give us some color on that?

Well, there – obviously I have said those words a number of times and I have answered that question a number of times. There is a number of ways I think to validate the value of Egypt. Obviously, one of which is monetization, one of which is, if you look at the gamut, you could spin it out, you could list part of it, you could sell part of it, you could sell all of it. The most important thing about Egypt is it generates a tremendous amount of cash flow. And we just need to figure out a way to validate that value without giving up that value. Joseph Allman - JPMorgan: Got you. Do you think if you sold a small slice of Egypt, would that cause investors to value the whole asset using the same metrics based on selling a small slice?

Well, I think that would be, beauty would be in the eyes of the beholder honestly. Joseph Allman - JPMorgan: And in terms of the option of selling the whole thing, I mean is that really an option? I mean could you sell it or do you think there would be buyers out there with the government budget?

Well, we are getting in an awful lot of detail, but one thing I would say is that in fact I went to Europe with Brady the first part of June. The rest of the world has a different view of the events in Egypt than folks in the United States. Europeans and other parts of the world have a different view of Egypt. They see truthfully a little less risk there than U.S. investors, but not saying the right or wrong or the U.S. investor is right or wrong, that’s just – that’s a perception. Joseph Allman - JPMorgan: Got you. And then on other area, so the media seem to get it right in terms of the shelf, I think the media reported that you are going to sell a minority interest in the shelf and you end up selling the whole thing. The media also reported that you are going to sell the deepwater Gulf of Mexico and those reports came out even earlier. So, how do you view that deepwater Gulf of Mexico, it’s a newer asset for you, how do you view that in the context of the overall portfolio in terms of returns and predictable growth and your ability to add shareholder value?

Well, we have said we have a robust list of assets that we might think are more valuable in somebody else’s hands than our own. And we also want to get more predictable and consistent growth. We also have a number of large capital items weed stone being one and kitimat being another. I mean obviously we need to look at that and see how it fits in our portfolio.

Your next question comes from the line of Charles Meade. Charles Meade - Johnson Rice: Going back to the Permian in Mid-Continental areas, do you have a sense of how much you might be able to ramp your activity there from current levels before you started to run into above ground issues or organizational issues?

Well it depends on which one you bid. Certainly the Central region, right now we're 10 rigs behind the Permian and we could continue to ramp up there. We can continue to ramp up in the Permian Basin. It's a little and I use the analogy it's like when you have to add a new foreman an appeal I mean you get 16 pumpers in a field and then you got to add a new foreman. So I am not sure where that line is in terms of what it takes from an organizational standpoint to make a step change to add another foreman if you understand my analog. Charles Meade - Johnson Rice: I think I do.

But certainly we could ramp up from here. Charles Meade - Johnson Rice: Got it. Okay, in both those areas in both the Permian and Mid-Continent?

Yes. Charles Meade - Johnson Rice: Okay, great. That's exactly what I was looking for. And then if I could also just try to follow-up a bit on the questions that Joe Allman was asking, do you have a preference on the assets sales that you are pursuing? Do you have a preference for a complete exit from an area or an asset versus a sell down of selling the percentage of what you hold?

No different assets in a different way. So, there may be some that we have partners and there may be some that we have a complete access. Charles Meade - Johnson Rice: Got it. So, not an across the board preference but it is asset-by-asset?

Right.

Your next question comes from the line of Leo Mariani. Leo Mariani - RBC Capital Markets: Just yet another follow-up on the asset sales. Obviously it looks like you're going to be able to pay down all of your short-term debt with the shelf sale and you're clearly buying back a lot of stock as well. If there are large incremental asset sales where should we expect the proceeds to be directed here? Would it be even more stock buyback or potentially accelerating drilling in the areas like Permian and Central area?

I think it's important to note that the more assets that we sell whatever in terms of that are cash flow generating assets. It requires us to pay down more debt in order to keep our A rated and we intend to keep our A rated. So you may see more debt, but you'll have more proceeds. And then that will either depending on our, as we look in the future, it will either buyback additional shares or reinvest it in the business. Leo Mariani - RBC Capital Markets: Okay. And I guess in terms of some of your other kind of more fledging areas exploration stuff. Any update on Inland or Alaska or shale’s in Argentina?

Yeah. The Cook Inlet in Alaska. In fact we’re getting ready to do some work 3D seismic. Frankly, we were disappointed in the well results that we have there. We drilled the well and actually got too close to a fault (ph) so we really didn't evaluate that well. I am personally still very positive about the Cook Inlet. Obviously we're directing cash to different things right now. So, we've slowed down that activity but in terms of its prospectivity, I still think it has good value. What was the other question? I am sorry. We have drilled or participated in four or five Bakken mode of (ph) wells. We drilled a couple of horizontal wells ourselves that were very short laterals. That area is politically challenged right now. What we have decided to do is spend our cash flow that we generate there. And so, we are pretty slow in actually continuing to evaluate the (indiscernible). Leo Mariani - RBC Capital Markets: Okay, thank you.

Your next question comes from the line of Brian Singer. Brian Singer - Goldman Sachs: Thank you. Good afternoon.

Hi Brian. Brian Singer - Goldman Sachs: I wanted to follow-up on the running room topics on Egypt and the North Sea, because I think one of the challenges unrelated to political risk is assessing the impact on production growth of the discoveries that you regularly announced. If you look at production in both areas itself sequentially and I think in the update you highlighted in part declines in Egypt from new and legacy wells. So, I think the question specifically on Egypt since you touched on the North Sea earlier is what should we expect for oil production trajectory over the next few quarters? And can the discoveries that you have announced here drive growth or just reverse the declines that we have seen on a gross basis in the last couple of quarters?

Yes, I think it’s – and Brady went through that the makeup of our production there. And it’s very important to start being able to articulate that because under GAAP what we have to do is report tax barrels, but tax barrels is just a gross up of the revenue line and a gross up of the expense line on the tax side. In order to really look at our growth, because what we do in our plan for the year is we just use last year’s percentages and try to roll them into this year’s plan, because you don’t have any other data to go by. And it plays havoc with really talking about what our percentage growth is, which is why we have worked hard over the last couple of quarters. And that leads into my next point. If you look at our gross operated production, which is where you start in Egypt, our gross operated operation is basically flat for the year. If you look at our net because of the differences in the tax barrels, our production has been down which is why we are trying to make sure we articulate what is happening in Egypt. Right now, we are spending enough money to grow slightly our gross operated production. And it truly is a function of how much capital you want to spend, because with the opportunity set is still very robust. And what we have done right now is we are spending capital enough that we think we can grow gross operated production slightly for the year. Brian Singer - Goldman Sachs: Got it. And is that going to be maintaining an equal mix of oil and natural gas or do you expect a further shift to more towards natural gas here?

Yes, we are about most of the things that we are drilling right now are oil. Brian Singer - Goldman Sachs: Great, thanks. And then on a follow-up on the Cline shale you talked about your 30-day IP rates, can you just put into context how the Cline competes in your portfolio relative to the Wolfcamp shale and the Mid-Continent?

In terms of rate of return, Brian? Brian Singer - Goldman Sachs: Exactly. And in terms of rate of return, how you think about where the next dollar of capital goes in the U.S. onshore?

Well, probably the Cline shale right now, because we are still – if you are talking about horizontal wells, vertical Clines are very economic. Horizontal wells are 20% – honestly, 20% rates of return. If you look at the things we are doing in the Anadarko Basin especially with any kind of oil at all, the rate of returns are in the 30%, because we are ahead of the game in terms of reducing our cost against our benchmarks in the Anadarko Basin than we are in the Permian Basin. We are still on the learning curve in the Permian Basin, Brian, but the Wolfcamp shale is its 30% rates of return.

Our Wolfcamp development is also 18 months further developed in the Cline. And just in terms of share numbers and the things that we are doing out there, we are still learning a lot in the Cline. Our results are very good, but we are not as mature there as we are of our knowledge or the understanding of Wolfcamp shale in the same area.

And In fact I said on the European Roadshow, I mean throw us in that broader patch, I mean I can't name another company that can get cost down and production up like this outfit can and this is perfectly example of doing that. If you look at our Tonkawa wells we were, last year we were making about an 18% rate of return and we were $1.5 million more. This year you take out a $1.5 out of that cost side it's over 40% rates of return in Tonkawa. So, it's purely a margin game and I think we can play that game very well.

Your next question comes from the line of Michael Hall.

I just want to make sure I’m thinking about the kind of go forward 2013 production outlook correctly, let’s get in the moving pieces. If I have to just hold the U.S. Gulf, the shelf assets let's say flat from the second quarter levels. Will that be with the 3% to 5% growth target that you spoke about previously this year, still be a fair target?

Well I think in the Gulf of Mexico flat it's probably not a good assumption frankly. If you look at on a pro forma basis, where you would to take the Gulf of Mexico shelf operations out of the forecast for '13 and then do the same thing for '12. We projected that we would have a double-digit decline in the Gulf of Mexico shelf so therefore the 3% to 5% would obviously have been a higher number if you did on a pro forma basis. I think that's probably the right way to think about it.

I guess I am trying to understand the go forward pieces and how those are progressing well for the prior plan which maybe you will be able to walk through maybe through the key areas. It sounds like North Sea is down third quarter coming back up until fourth, Egypt we just walked through maybe it's around through some of the other?

Yeah I think when you look at the third quarter we’re not going to give specific guidance, but if you look at the onshore North American plays that we’re doing, I would suspect that the third quarter growth would be fairly consistent with what we experienced in the second quarter with the goal obviously the guidance we've reiterated at 25% greater than 25% North American onshore liquids growth. When you look at the offshore Gulf of Mexico including the deep water and you also look at Australia, we had guided earlier in the year that they would be down roughly double-digits. So, I think that's the right way still to think about them, even though the shelf hopefully will close by September 30th we won’t have them in the fourth quarter. And then I think with the North Sea, Steve had already mentioned that we expected to be down in the third quarter a little bit because of the turnaround. You are going to have offsets because of wells coming on production, some of which we announced recently including the Bacchus well today. But you know that turnaround at the 40 field turnaround, on average for the quarter we expect it to be down 10,000 to 12,000 boe per day even though it will happen in the month of August; the average would be about 10,000 to 12,000 boe per day down. As a result of the turnaround but that's what we've already got built into our plan.

That’s helpful and then if I could just follow-up in terms of Canada what you're doing of those assets perhaps just a little additional color kind of maybe what the underlying decline of the legacy activity looks like and how quickly you think you could turn that into a growth program with any of these new targets you kind of alluded to?

Well I think we have two things going on in Canada. One is we have got our transition into more of an unconventional play up there. And then we got to look at our legacy assets and decide what to do with them. And we're in the process of doing that frankly. We would like that region to come out is in a position to be able for 2014, being in a able position to be able to grow and adding a meaningful growth area for us in North America onshore.

Your next question comes from the line of (inaudible).

Steve, just a couple of questions regarding the deep shale for the subsalt in the Gulf of Mexico, I note that you retained half your interest there, what are the near-term drilling plans related to the subsalt play?

Actually, we have two wells that we are drilling as we speak, and it will be a continuing part of our portfolio. If you think about it in terms of reserve size to cost, we also have an agreement that we have a facility right on the current HBP acreage that we sold to Fieldwood, so that we can take them through those platforms. The two prospects that we are drilling right now, I think the un-risk predicted or expected reserves on one is 104 million barrels and the other one is 136 million barrels. And we are not down on either one of them, but that’s – so when you think about what the infrastructure costs that you are foregoing and the reserve size that you are looking at, you have a real potential across that shelf to make that subsalt play.

Okay. And if I remember correctly, you are involved with a 3D shoot in the Central Gulf of Mexico, is that still ongoing?

It is. We have a wide seismic shoot going on and that we won’t have the results to the latter part of this year, actually the end of this year the actual process data, but we are continuing to shoot.

Alright, thanks very much.

Hey, Richard, we do provide a little bit of detail on Main Pass 295, which is one of the wells that Steve is alluding to within our ops report.

Okay.

As we go into the Gulf of Mexico shelf, there is a little paragraph on it.

I appreciate that. Thank you.

And I am showing that we have no further questions at this time.

Okay, excellent. Well, thank you very much for participating in the call, and again, if you have any additional questions, don’t be shy reach out to us, and we’ll be happy to help. Thank you.

Ladies and gentlemen, this does conclude today’s conference call. You may now disconnect.