F. Brady Parish – Vice President-Investor Relations G. Steven Farris – Chairman and Chief Executive Officer Rodney J. Eichler – President and Chief Operating Officer Thomas P. Chambers – Executive Vice President and Chief Financial Officer Roger B. Plank – President and Chief Corporate Officer

Arun Jayaram – Credit Suisse Securities LLC Pearce W. Hammond – Simmons & Co. International John P. Herrlin – Société Générale Americas Securities, LLC David R. Tameron – Wells Fargo Advisors LLC Bob A. Brackett – Sanford C. Bernstein & Co. LLC Joe Magner – Macquarie Research Doug Leggate – Bank of America Merrill Lynch Matthew Portillo – Tudor Pickering Holt & Co. Charles A. Meade – Johnson Rice & Co. LLC Leo Mariani – RBC Capital Markets Brian A. Singer – Goldman Sachs Kevin Cashman – Assurant Michael Howe – Robert W. Baird & Co., Inc. Joseph Magner – Macquarie Capital

Good afternoon my name is Ally and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation Fourth Quarter 2012 Earnings Release Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instruction) in order to make sure that everyone has a chance to ask a question, we ask that you limit yourself to one question and one follow-up question,(Operator Instruction). At this time I would like to introduce your presenter for today Mr. Brady Parish, Vice President of Investor Relation. Mr. Parish, you may begin your conference. F. Brady Parish: Thank you Ally, good morning everyone and thank you for joining us for Apache Corporation's full year and fourth quarter 2012 earning conference call. This morning we reported 2012 earnings of $1.9 billion or $4.92 per diluted share, adjusted earnings, which excludes certain items that impact the comparability of results totaled $3.8 billion or $9.48 per diluted share. Cash flow from operations totaled $10.2 million. On today’s call, we will have three speakers making prepared remarks prior to taking questions. First, we will hear from Steve Farris, our Chairman and Chief Executive Officer; followed by Rod Eichler, President and Chief Operating Officer; and finally, Tom Chambers, Executive Vice President and Chief Financial Officer. 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, new for this quarter, we have prepared an operations supplement to summarize our activities across the various Apache regions. These can both be found on our website at www apachecorp.com/financialdata. 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 differ materially from what we discuss today. A further disclaimer is located with the supplemental data package on our website. With that, I’ll turn the call over to Steve. G. Steven Farris: Thank you, Brady, and good afternoon, everyone, and thank all of you for joining us. Apache achieved some new milestones in 2012 and first of all, despite significant downtime we grew our average annual production to 779,000 barrels of oil equivalent a day, almost 5.5% above 2011 if you adjust for dispositions, which is a new record for Apache. And as a matter of information, and I assure you not an excuse, I would like to point out had we not experienced the unplanned downtime in the North Sea and Hurricane Isaac in the Gulf of Mexico during just the third quarter. Our production growth would have been 6.3%. More importantly, during the fourth quarter, we averaged 800,000 barrels of oil equivalent a day, the first time in our company's history which establishes a strong base as we enter 2013. And despite as Brady pointed out, despite much weaker North American natural gas prices, our balanced portfolio enabled us generate $10.2 billion of cash flow consistent with 2011. I'd also like to point out, driving this impressive cash flow were our liquids revenues which constituted 81% of our overall $17 billion in revenues for the year, and North American natural gas accounted for only 11%. By the end of the year, we had fully integrated our Midcontinent North Sea portfolio expansions and we really hit our stride in our large Permian position. As a result, we built operational momentum heading into 2013. We have become the most active Permian basin player with 38 operated rigs and we plan to increase our horizontal rig fleet to half of our total operated rigs during the year. We've also become a leader in the Midcontinent liquids and oil plays, increasing our horizontal drilling activity from six rigs at the beginning of 2012 to 25 today. At the end of the year, we advanced the Kitimat LNG project by increasing our interest to 50% and expanding our strategic relationship with Chevron, so we believe this is the financial and technical LNG wherewithal to complement on our upstream strength, and it should help us accelerate our plants to monetize the over 50 Tcf of natural gas that we have in Liard and Horn River, importantly at the oil-linked prices. I am sure all of you have noted in our earnings release this morning, during 2012 we replaced 156% of our production before revisions. Excluding property acquisitions this replacement ratio would be 131%. Low prices in Canada for natural gas during the year was a predominant driver of the negative revision of 299 million barrels of oil equivalent, in fact it’s over 90% of that number. With this transition behind us, we’re going to move into 2013 with our initial capital budget set at $10.5 billion which is essentially flat with a 2% year-over-year from 2012. Our capital allocation for 2013 really reflects our choice to deliver competitive near-term performance while building balanced long-term value for our shareholders. Approximately $4 billion of our capital would be invested in Onshore U.S., but we expect production to grow in excess of 20%, 2013 driven primarily by our Permian and Central Region drilling programs. We also project our North American oil productions to grow by 14% in 2013, which was up from 12% in 2012. Furthermore our 2013 planned costs for $2.2 billion investments in ten long year infrastructure projects which represents nearly 21% of our total 2013 capital. As a result of this capital allocation choice and taking into consideration production declines in certain of our regions we expect total production to grow by 3% to 5% in 2013. Just for comparison purposes, and using our budgeted economics, if we instead use this long-term capital investment to fund additional drilling in the Onshore U.S. our projected 2013 growth rate would be in excess of 6%. Based on our current ownership of these long-term projects, these projects are expected to contribute 150,000 barrels of oil equivalent a day over the next five years and over 200,000 barrels of oil equivalent by the end of the decade. As a result of our two major LNG projects, production for our development pipeline is expected to continue to increase over 200,000 of oil a day before settling into a zero decline multi-decade plateau. We have built this company by focusing on returns, balance and long-term value. Over the last three years, we have deepened and strengthened our portfolio. We now have over 9 billion barrels of oil equivalent unbooked resource in our Permian and Mid-Continent positions. That is second to none. We have a robust project pipeline in motion that will provide a stable base of free cash flow for decades and we have broad exposure to quality resource and exploration opportunities around the world. On a broader and deeper footprint, provides us the opportunity to optimize our portfolio. And as such, we are in the process of identifying approximately $2 billion of asset rationalizations to be completed during 2013. We're not in a position to get into specific details at this time, but having acquired $16 billion of assets over the past three years, and strengthening our asset base, we have been in the process of reviewing our overall portfolio. We are here for one purpose and that is to generate long-term profitable growth for our shareholders. And we truly believe we can continue on that mission. Finally, another important item of note is that last week our Board approved increasing our common dividend by 18% from 17% to $0.20 per share. This follows our increase from 2012 of 13%. We remain confident in Apache's ability to continue growing profitably and see dividend growth as an important component of shareholder returns. So with that, I’ll hand it over to Rod Eichler, our COO. Rodney J. Eichler: Thank you, Steve. Good afternoon. As Brady previously mentioned, we have compiled an operations supplement for your use which highlights our activities by region during the fourth quarter. We have put this together in an effort to be responsive to feedback we have received and hope you find it useful. In this supplement, we have provided detailed operational information for the fourth quarter. We also like to highlight some of our most notable achievements during 2012. Firstly, with our growth in the U.S. onshore sea drilling. Combined, our Permian and Central regions grew production nearly 24% year-over-year and represent 25% of Apache's total global production by the fourth quarter and 197,000 barrels of oil equivalent per day. As impressive as these results are the reality is we're just in the early stages of our growth as each region evolves in a full-scale development. In the Permian Central alone, we have identified over 9 billion barrels of oil equivalent of resource potential to further fuel our liquids-rich gas and oil production growth to unfold. In addition, we are in the process of completing our resource assessment in Canada for liquids-rich gas and oil opportunities with approximately 7 million gross acres in the Western Canadian Sedimentary Basin. We anticipate identifying thereby in several thousand economic wells in our various plays which should allow us to add another North American onshore growth region as we ramp up activity over the next couple of years. We also successfully integrated the barrel properties into our North Sea region. We have spent the last year preparing for drilling campaign that will test new opportunities based on the first 3D seismic acquired over these fields since 1998. Finally, we replaced over 130% of our production through drill bit and approximately 156% when you include the acquisitions; this obviously excludes the impact of later revisions, which primarily resulted from weak North American natural gas prices during 2012 versus 2011. Looking ahead, I want to focus the remainder of my remarks on our plans for this coming year. Our plans are based upon our initial $10.5 billion allocation of capital, which Steve has mentioned; includes $2.2 billion for the long-term projects, not expected to generate production till 2014 and beyond. In 2013, we expect our U.S. onshore regions to grow production in excess of 20%, predominantly consisting of liquids growth. We also expect our investment to increase production in North Sea and our drilling program in Egypt to increase our gross production in that region. However, we expect moderate production declines in Canada and Argentina, double-digit declines in Australia and deepwater due to the future timings of our next development projects coming on line and a double-digit decline in the Gulf of Mexico shale due to natural fuel declines. We're currently running 122 rigs worldwide and expect to average a similar amount over the course of the year. We plan to drill more wells in 2013 than 2012 in an estimated total of nearly 1,600 wells. Almost two-thirds of all planned wells will be drilled in the Permian and Anadarko basins of the U.S. and are expected to generate fully loaded after-tax rates of return in excess of 20% at planned commodity prices. Our financial supplement posted on our website out lines Apache's 2013 initial exploration and development capital allocation by region on Page 10. Now turning to our region highlights; the Permian region produced nearly 118,000 barrels of oil equivalent per day in the fourth quarter with 74% liquids constituting nearly 15% of our total production. In addition, we replaced over 260% of our production in the Permian through drilling activities during 2012, excluding price realizations and ended the year with 800 million barrels of proved reserves. In 2013, we'll further exploit our vast 3.8 billion barrels of oil equivalent net resource position with plans to drill over 700 wells running on average of 34 rigs and investing nearly $2.4 billion of capital. We will significantly ramp up our horizontally activity in the basin. We are currently running 13 horizontal rigs at a total of 38 rigs and anticipate increasing our horizontal rig count to 17 by the end of the first quarter. As such, nearly 180 of the 2013 wells will be horizontal versus 104 horizontal wells in 2012. We will build upon our successful horizontal program in 2012 by increasing our Wolfcamp shale and Cline shale developments, and will be focused on driving down drilling and completion costs as we move towards development mode to further optimize our returns. We have already successfully donated 10 horizontal plays across the region. This year we will target and test an additional 20 horizons. In the Midland basin, we will continue our successful vertical program in the Fusselman, Wolfwood, and Wolfberry plays within Deadwood and other areas. On the Central Basin platform, we plan to drill additional Grayburg, Clear Fork and Wichita-Albany, all those horizontal wells and to test Strawn and Mississippian zones. For the Yeso play in Southeast New Mexico, we will continue to drill vertical wells, once again our first horizontal program in the Cedar Lake area. And in the Delaware Basin while we already have successfully drilled the second Bone Spring horizontal, we plan to test in the first quarter and also drill a horizontal well in the Wolfcamp. We will be actively testing the vertical Wolfbone within this emerging area for us. Finally, since we see the number of questions regarding our Permian realizations, I wanted to mention that we successfully negotiated a five-year contract to sell crude that is then transported to the Gulf Coast via pipeline. Terms of this contract are confidential, that should allow us to receive favorable placing for this oil. These volumes will ramp up over the next several quarters and at a full capacity we will sell up to 20,000 barrels of oil per day into the Gulf Coast. Turning to the Central region, the region produced approximately 79,000 barrels of oil equivalent per day in the fourth quarter. This is a 9.6% increase over third quarter of 2012 production, over 38% on an annualized basis. Just as significantly, we increased our oil production by 24% in the fourth quarter versus third quarter to 21,000 barrels of oil per day, which represents 27% of total region production. Total liquids production increased by 24% to 31,000 barrels of oil per day or approximately 39% of total region production. Further, we replaced over 340% of our production in the Central region through drilling activities during 2012 excluding price revisions and nearly 645% when you include the acquisitions. For 2013, we will continue to accelerate activity as we plan to ramp up our drilling across our extensive acreage position in the Anadarko and Whittenburg Basins. We will further explore our vast 5.4 billion barrels of oil equivalent in that resource position with plans to drill nearly 300 wells, up from 192 wells in 2012, while running in average of 29 rigs of which 28 are horizontal and investing nearly $1.4 billion in capital. About a third of our program will target the prolific liquids-rich Granite Wash, with another quarter targeting the oilier Tonkawa, rigs will also work the Cleveland, Marmaton, Cottage Grove, and Canyon Wash. Apache has 11 lower Marmaton tests planned in 2013 with a total of 90 resource locations identified. 17 vertical Canyon Wash wells are currently planned for 2013, with expectations that we will commence water flooding in the Wash and begin a horizontal program in the Canyon line later in the year. After integrating our Cordillera acquisitions and further donating our acreage over the past year, we expect that it will drive down drilling and completion plans and costs as we optimize our development program. In our Gulf Coast onshore region, we intend to average three operated and one non-operated drilling rigs during 2013, anticipating we will drill 39 wells. At Atchafalaya Bay, we anticipate our drilling activity will increase gross production from the field to 155 million cubic feet of gas per day from 140. Phase II of this facility expansion from the Atchafalaya Bay Field to [Belvieu] will be completed during the first quarter and startup of Phase III will commence, which should be completed late in the second quarter, bringing the capacity of the Atchafalaya Bay system to 220 million cubic feet of gas per day from 155. In the Gulf of Mexico shale, we plan to drill over 30 wells as we exploit low-risk liquids-rich prospects. We will also work to expand our inventory at permanent drill prospects and acquire additional wide-azimuth 3D seismic as we apply deepwater technology to the shale to enhance subsalt imaging and identify previously overlooked prospects. In the deepwater Gulf of Mexico, we have drilled our position to 166 blocks and approximately 900,000 acres and have identified dozens of prospects to sustain an active exploration program for many years. In 2013, we plan to drill three operated exploration wells and four non-op development wells. We have two rigs under contract under drill prospects San Marcos and Mississippi Canyon 983, Starlight, Green Canyon 230, 274 and Guadeloupe in Mississippi Canyon 554, 555. We are moving forward with the partner-operated projects, Lucius and Heidelberg and expect to invest $200 million of our share of four wells in these two developments during 2013. In Canada, our 2013 program includes over 150 wells with a focus of oil and liquids-rich gas opportunities and horizontal exploitation of Sparky, Bluesky, Beaverhill Lake, Dunvegan and Viking oil plays. We also intend to test the Montney and Duvernay within our substantial acreage positions in these plays. Our 2013 plan in Australia totals nearly $1.9 billion, includes drilling 16 wells, six of which are for exploration. Mid-year the partner-operated Macedon gas project will be complete, and will add approximately 35 million cubic feet of gas per day of net production. But the real focus in Australia continues to be the long-term growth, we will realize from the pipeline of development projects we have lined up over the next several years. This includes the Julimar-Wheatstone LNG development project, the Coniston and Balnaves oil projects, the Moondyne and Upper Pyrenees projects and the Varanus Gas Compression project. Total capital allocated to these projects in 2013 exceeds $1.5 billion. With respect to the Coniston oil development, in order to repair the Ningaloo Vision FPSO for its increased throughput capacity, Apache has reviewed all requirements for planned maintenance and as scheduled, the vessel to go offline to the shipyard in the first quarter of 2014. This time we will take advantage of the 2014 cyclone season window should we normally see some weather-related downtime, thus optimizing production for 2013. Turn to Egypt, our operations continue uninterrupted. This asset remains a highly profitable piece of Apache portfolio and as such we plan to make a similar investment in 2013 as we did in 2012. This will allow us to drill over 270 wells including over 60 exploration wells. Our drilling program will focus on Bahariya, Abu Roash, Jurassic and AEB targets. So we are also looking to further test these horizontals in the region. These with our level of investment combined with the Heathrow field now online, we expect the gross production in Egypt to be slightly higher in 2014. In the North Sea, we plan to drill 27 wells of which 24 will be operated including 11 new wells at Forties and at least six at Beryl. We also plan to drill a third well at Bacchus field during the first quarter. In 2013, we will install a commission with pass top side and commits drilling operations. Two wells will be drilled and test in 2013. Apache will acquire a 307 square kilometer of 4D seismic survey of Forties and Bacchus fields commencing in July and complete the acquisition of the Beryl 3D seismic survey which we gave in the summer of 2012. In Argentina, our investment level will be consistent with recent years as we aim to invest within the region's cash flow. We plan to drill additional 20 wells during the year, 16 of which will be Apache operated focusing on gas plus wells as well as continued Vaca Muerta exploration activities. Finally, with respect to our venture activates, we continue to evaluate the well data we have collected from our Bakken and Mississippian Lime exploration wells, and we'll provide further detail in the future with respect to our path forward in these areas in including any development plans. In Alaska, we are in the final stages of drilling our first onshore well and expect to complete it in the second quarter. In Suriname, we have signed a 3D seismic acquisition contract for 2,100 square kilometer survey over our Block 53 and expect to commence seismic operations in the second quarter. One last item of note, before I turn the call over to Tom Chambers, due to Cyclone Narelle in offshore Australia and other weather events in Australia, unplanned facility downtime in the Gulf thus far this year, we expect first quarter 2013 production to be down versus fourth quarter 2012. However, we have already incorporated this downtime into our 2013 production guidance. That concludes the operational highlights, and I'll turn it over to Tom Chambers. Thomas P. Chambers: Thanks Rod, and good afternoon, everyone. While 2012 provided plenty of challenges, we finished the fourth quarter strong, averaging 800,000 barrels of oil equivalent a day, boosting us to record production for the year and fueling record oil and gas revenues in our second best cash flow year ever. Production which averaged 779,000 barrels of oil equivalent a day was up 4% from the prior year and up almost 5.5% adjusted for dispositions as Steve indicated. More importantly, record oil production of 352,000 barrels per day combined with record oil price realizations drove cash from operations before working capital items to $10.2 billion for the year and a record $2.8 billion for the quarter. Oil and gas revenues of $16.9 billion were slightly higher than 2011 and we achieved a new record in spite of average North American natural gas prices falling over 30%. We continue to benefit from our portfolio with WTI crude prices currently over 28 times the price of North American gas. Having 72% of our oil production priced at Brent or Brent-comparable indexes, which continues to realize substantial premiums to WTI, also enhances our results. Our international natural gas portfolio continues to have a positive revenue impact by providing increasing volumes to markets with gas prices significantly higher than North America particularly Argentina, Australia and the UK grid. For the fourth consecutive quarter international gas price realizations outpaced those of North America. In 2012 international gas price realizations increased 13% compared to the prior year and at $4.15 they were 47% higher than those realized in North America excluding hedging. Turning to earnings for 2012, as you heard we reported earnings of $1.9 billion or $4.92 per share, despite the impact of several key non-recurring items. Our results include prior quarter non-cash property write-downs in Canada totaling $1.4 billion aftertax directly related to collapsing Canadian natural gas prices. We had a number of other charges that impacted our results for the year including $226 million of deferred tax charges, $118 million tax adjustment in the UK related to decommissioning discussed in the third quarter, $51 million charge for derivative mark-to-market, and $19 million merger and acquisition charges. When we remove these items for comparability purposes, we earned $3.8 billion or $9.48 per share down from 2011’s $4.7 billion and $11.83 a share. The detailed breakout of all of our financials including adjusted earnings and cash flow from operations can be found in the financial supplement located on our website. The bottom line though is margins. We’ve been able to sustain strong cash margins at $42.86 per barrel of oil equivalent down just 6% from 2011. Margins were impacted by a 3% reduction in commodity price realization and a rise in our lease operating expenses. Current year repairs, maintenance and plant turnarounds directly impacted our LOE by almost $0.40 per BOE, predominantly related to the Grand Isle 43 corrosion repair and Canadian plant turnarounds. In addition, we have continued growth in our onshore North American operations, our labor costs have increased as well. Our operating costs generally trend with commodity prices and are also impacted by the location of our properties. Oil properties are inherently more expensive than natural gas properties to operate as our offshore properties. The 51% of our 2012 production oil and liquids and approximately one-third of our production located in offshore areas, our costs run higher than many of our competitors. Total cash costs during the year averaged $17.06 per barrel of oil equivalent, up $0.82 over last year. For 2013, cash costs absent price dependent production tax are projected in the $14 to $16 per barrel of oil equivalent range. We remain focused on cash margins and continue to monitor our cost trends in all areas, in addition to reviewing our capital spending to ensure we focus on the highest rate of return projects. Our ability to sustain margins allows us to generate a robust $10 billion of operating cash flow that’s funded our largest E&P capital budget ever. In addition to our organic cash flow generation, we were able to successfully issue $5 billion of new debt this year at all in cost of 3.6%. $3 billion in April of five, 10 and 30 year tranches used to fund the cash portion of the Cordillera purchase price and repay maturing debt and additional $2 billion in December of 10 and 31 year notes with record low coupons allowing us to take advantage of continuing low rates to term up floating rate debt and increase our overall liquidity. Our successful E&P capital program with its focus on U.S. drilling added 372 million barrels of oil equivalent to proved reserves during 2012, that’s over 130% of what we produced during the year at a finding cost of a little over $24 per barrel. At first blush, that might seem high, but I’d like to point out that our 2012 spending included over $500 million of facilities capital, plus nearly $1.5 billion for leasehold and seismic purchases that while in the cost side, do not immediately result in reserve additions. Excluding this spending, finding cost would have been very competitive. While the seismic and leasehold purchases were very large last year, we do not see that trend continuing in 2013. However, these expenditures while seemingly a drag on finding cost now will provide a large benefit in the future setting the foundation for future growth. Reserve ads through acquisition totaled 73 million barrels of oil equivalent, bringing total ads to 156% of 2012 production. Unfortunately, low North American gas prices were primarily responsible for negative price revisions totaling 299 million barrels of oil equivalent, a majority in Canada. I would point out that with gas prices rebounding somewhat in the second half of the year, the negative revisions were halted after the third quarter and virtually, all of those reserves remain in the ground available to be produced if and when prices and economic conditions warrant. Turning to income taxes for a moment; the adjusting items mentioned earlier also impacted our 2012 effective tax rate, moving it up to 59%. If you adjust for these one-time charges, our tax rate would have been a more typical 44%. As mentioned earlier, 2013 will be another active drilling year and balancing our capital allocation and ensuring capital availability are key, because our cash flows are heavily influenced by oil realizations, we have recently entered into financial derivative contracts on 125,000 barrels a day of oil for calendar year 2013, using a combination of WTI and Brent swaps, representing about one-third of our worldwide oil production based on our fourth quarter of 2012 volumes. Our average combined hedge price is approximately 98,000 per barrel. We’ve not entered into any new gas hedges and our international gas portfolio exposure helps mitigate our North American price risk. In closing, we had a solid year of production revenues, cash flows resulting from our active drilling program. We have built a very strong foundation for cash flow generation and support both for our ongoing drilling program and our inventory of longer-term development projects as we head into 2013. And with that, I’d like to turn the call back over to Brady. F. Brady Parish: Thank you, Tom. Allie, we are now ready to open the line for questions.

(Operator Instructions) Your first question comes from Arun Jayaram from Credit Suisse. Arun Jayaram – Credit Suisse Securities LLC: Can you hear me? G. Steven Farris: Fairly. Arun Jayaram – Credit Suisse Securities LLC: Fairly, okay. G. Steven Farris: That’s fair. Arun Jayaram – Credit Suisse Securities LLC: Steve, I wanted to talk to you a little bit about the overall production. I mean in October, you guys updated the market, and you’re about 800,000 barrels a day in overall production. So there, next quarter despite some pretty strong gains in the U.S. onshore and you’re guiding down now for Q1. So, the sense is you're losing a little bit of operating momentum outside of the U.S. So I was wondering if you could just comment on that and just the overall shift to a little bit of a lower growth rate in 2013, notwithstanding the changes in capital allocation. G. Steven Farris: To be real frank, holding 800,000 barrels a day for quarter, we were very proud of that frankly, because we’ve never hit that from where we were. In terms of going into 2013, the first quarter, we’re affected by Hurricane; I mean a cyclone in Australia. I will tell you though we put that downtime in our 3% to 5% growth projection. There is no doubt that we have some properties that are declining, but we’re going to more than make up for it in the Permian and the Anadarko Basin this year. And we’re pretty confident about the long-term value of our Canadian assets also. Arun Jayaram – Credit Suisse Securities LLC: Okay. And just I was wondering if you could comment. Has there been any change in the way you’re thinking about? I know guidance is relatively new to Apache thinking about the long-term. Are you all changing your approach, you may be trying to guide to like P90 type of case versus maybe P50 differently. So just trying to see if there has been any change in the way you’re thinking about guidance I guess? G. Steven Farris: We are new to this. I have to be real honest with you. One thing that we don’t want to do is, miss our guidance. We’re going to spend quite a bit of money intentionally in a few, remember what Rod said, $1.5 billion of that $2.2 billion is going to Australia. The biggest chunk of that is Julimar, Brunello and the Wheatstone LNG facility, which is now over 80% contracted. And those are tied to oil linked prices, so when that comes on, we’re going to see about over 25,000 barrels a day for the next 25 years.

Your next question comes from Pearce Hammond with Simmons & Co. Pearce W. Hammond – Simmons & Co. International: Good afternoon. G. Steven Farris: Good afternoon. Pearce W. Hammond – Simmons & Co. International: Steve, I just wanted to get a little color. You mentioned about the possibility of maybe divesting around $2 billion worth of assets for that 3% to 5% production growth guidance for 2013. Is that guidance already includes the potential sale of those assets, if there’s production or would the guidance potentially need to be adjusted after the sale? G. Steven Farris: The guidance would be adjusted after the sale. Pearce W. Hammond – Simmons & Co. International: Thank you. And my follow-up would be on service costs, specifically in the Permian and then in your Central region. Just curious as you look at 2013 and compare it to 2012, how do you see service costs trending? Do you think that prices are bottoming and are there any areas of services right now whether they’re a little bit tightening in one of those regions? G. Steven Farris: Rod you… Rodney J. Eichler: The service costs in both areas are flat and declining and we see that, specifically, we see that in the Permian, they have been very large increases in the frac stimulation companies. as a result, that’s provided simply downward pressure on the pricing of that. We’ve seen a 30% drop in frac spread costs compared to 2012 as well as we might expect to see even more decline in our side from using more self-sourcing of same in chemicals in 2013, which will allow us to further reduce those stimulation costs. Same thing on rig rates. Spud rates are much more favorable than they were. We’ve seen about a 5% to 7% decline in rig rates. For the mechanical rigs, 2,000 horsepower rigs we used to build the vertical wells at Deadwood, that’s an example and we expect to see continued downward pressure on those as well. Roger B. Plank: Pearce, it’s Roger. Just one a little bit of comment on the sales. We’re going to identify exactly what it is, we’re going to sell, but not everything necessarily would have current production for example, the assets that we sold to Chevron, I guess last week, we collected $400 million and there is no production associated with that. Pearce W. Hammond – Simmons & Co. International: Great, thank you for the color, Roger.

Your next question comes from John Herrlin with Société Générale. John P. Herrlin – Société Générale Americas Securities, LLC: Regarding the Permian, you said in your ops report that you spud 22 horizontal wells with 463 frac stages. Are you going to be increasing the frac densities at all because it averages about 20 wells. I was just curious. Rodney J. Eichler: It depends a lot on what's lower or unconventional target that we are after in terms of the optimal frac concentration and we have a lot of efforts underway right now. They are various areas specific to try to optimize the amount of frac stages. And large numbers, not necessarily the optimal number and we're trying to find out the certain areas. So we expect to see overall improvements in both the cost and efficiency of our frac treatment programs in both the Permian and Central as we go forward in 2013 based on a lot of the benchmarking we are doing to become a best-in-class operator in these areas, we're drilling horizontal completions. John P. Herrlin – Société Générale Americas Securities, LLC: Okay, thanks Rod. Next one from me is on the Central; are those lateral lengths listed really the lateral length of the horizontals or is that kind of a type of? Rodney J. Eichler: My guess is that we'll have that. G. Steven Farris: I will go with the numbers, John. John P. Herrlin – Société Générale Americas Securities, LLC: Or you're going from 12,000 to 16,000 feet, 18,000 feet, Steve. Is that lateral? Rodney J. Eichler: That's the full measured dip. G. Steven Farris: That's the vertical and horizontal. John P. Herrlin – Société Générale Americas Securities, LLC: Okay, thanks.

Your next question comes from David Tameron with Wells Fargo. David R. Tameron – Wells Fargo Advisors LLC: Good afternoon everybody. A couple of things, the PSC contracts, you said you just – and then you said, I guess bid round, you got a lease and you're going to have a revised PSC contract. Can you talk about that and should we read into that is that's where the government is headed going forward? Rodney J. Eichler: Could you repeat that question? It was very broken up. David R. Tameron – Wells Fargo Advisors LLC: This now better. Rodney J. Eichler: Little bit. David R. Tameron – Wells Fargo Advisors LLC: Okay, sorry I’ve trouble here with the phone. But In Egypt, if you talk about winning in the recent round of bidding, you won a couple of leases and there's going to be a new PSC contract. So I'm just wondering if we should read anything into that. Is that the direction that we should expect the contracts to go in Egypt? G. Steven Farris: Well, the one thing I would say is they have continual posting of leases in Egypt, concessions in Egypt that people bid on. The most significant thing about the latest bid round were they were very similar to all of the other concessions that we've got in the Western Desert. So, there weren't any term changes in terms of what they had asked for in the latest bid round. David R. Tameron – Wells Fargo Advisors LLC: Okay, so your expectation for this contract is that they're going to look just like the last year? G. Steven Farris: There's always a – the cost recovery goes from 35% to 40%, but in terms of directionally, it's pretty much the same as all our concessions across the Western Desert. David R. Tameron – Wells Fargo Advisors LLC: Okay. New Zealand, can you talk a little bit about what's happened there? G. Steven Farris: Did you say New Zealand? David R. Tameron – Wells Fargo Advisors LLC: New Zealand, yeah. G. Steven Farris: Well, I think what we – in terms of the long-term potential, there is definitely a tremendous amount of hydrocarbon service. Being able to do that and the magnitude that it takes over the timeframe that it takes, we've decided that that wasn't in our best interest, and you're going to see that when we talk about our asset sales. We now have some long-term projects that have some significant durability and significant potential and so we're going to have to balance off our long-term and our short-term in terms of being able to grow both long-term – but also be able to grow short-term.

Your next question comes from Bob Brackett with Sanford Bernstein. Bob A. Brackett – Sanford C. Bernstein & Co. LLC: Hi, good afternoon, I had a question. What do you expect to do with the proceeds from the divestments of $2 billion? G. Steven Farris: Well, originally we're going to pay down debt, but when we get there we'll have to make a decision as to what we do with the proceeds but the first call on it is going to be pay down debt. Bob A. Brackett – Sanford C. Bernstein & Co. LLC: And then a question, I thought I heard you say you're going to start water flooding in the Granite Wash. What's the concept there? Is it true the horizontals that have been fraced? Rodney J. Eichler: No, the reference to the water flooding was to the Canyon Wash which is in our Bivins Ranch field which is a vertical convention development (inaudible). Bob A. Brackett – Sanford C. Bernstein & Co. LLC: Thanks. Rodney J. Eichler: Yeah.

Your next question comes from Joe Magner with Macquarie. Joe Magner – Macquarie Research: Good afternoon. Just a few questions, on the divestitures, while some will not be productive anywhere to ballpark how much is associated, how much I guess current production is associated what is the? G. Steven Farris: I think when we get there we will announce what – we've got a number of different banks that we're looking at. Joe Magner – Macquarie Research: Okay. Then one of the comments you mentioned that 72% I believe of your oil is linked to Brent or Brent equivalents. Can you provide any perspective on how you see price differences playing out between Brent and WTI, Brent and LLS and then also Midland Cushing going forward? G. Steven Farris: Well, I think Brent if the world price. And when you look at 5% of the well is traded at WTI prices and so what you have is, that you have a bottleneck in certain areas, certainly West Texas is one of them, there is an awful lot of people trying to solve that problem. I think Tom or Rod pointed out that we have an equity interest or a throughput interest in the pipeline that we're going to start, and there are going to be more and more of those. My personal opinion is that I think those numbers will come and it's not going to be in the next 18 months but over time they're going to – that spread is going to shallow. I mean I just think that's not attainable forever. Joe Magner – Macquarie Research: By spread you mean Brent TI spread or…? G. Steven Farris: Yes. Joe Magner – Macquarie Research: Okay. Are there any, other than pipelines in the Permian, I guess as you think about just routing crude from and where you're producing onshore to where it needs to be. Any other significant plans or infrastructure projects that could create bottlenecks or constraints on being able to achieve your plan for this year? G. Steven Farris: Not really, not to achieve that plan. We certainly and the Permian basin as you know, and I'm sure you know that there is a number of areas that are getting built or projected to be built but it's not going to affect our 2013 plan.

Your next question comes from Doug Leggate with Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thank you. Good afternoon everybody. I hope you can hear me okay. I've got a couple of questions if I may. Steve, clearly, this is a bit of a change from what you told us at the Analyst Day last year. Can you help us understand is this move away from the growth target in 2013, a move away from the long-term growth target as well. In other words, are you abandoning now the 6% to 12% target you laid out and just, so if you could help us understand what's changed? G. Steven Farris: No, in fact, it's not. If you look at our asset base, it really is based on what our capital allocation is this year. If you look at the – if the amount of production that we are developing, it should help us in terms of obtaining that – actually we are at 6% to 9% if you don't include gas. We see gas go up, we can drill more gas wells, but right now 6% to 9%, we are still looking at that from a long-term basis. Doug Leggate – Bank of America Merrill Lynch: I think you had kind of signaled that you tempered gas, so that would be the number, so I appreciate that. My follow-up is really on the asset sales. Forgive me if I'm wrong here, but it sounds like you haven't quite identified what the assets are, or have you? Is it a bottom-up process, or are you seeing $2 billion as a number and then trying to make that fit? In my [meeting] going to this is, how big ultimately does that disposal process get as clearly they're extremely asset-rich and you're obviously not getting a lot of credit on the share price, and I'll leave it at that? Thanks. G. Steven Farris: Doug, I didn't. Well, in terms of – certainly we have considered assets that we may sell. In terms of specifics and our pricing, I mean we've also scoped the order of magnitude of the pricing. But we're really not in a position at the present time to talk about which one of those asset bases that be. All of them will not include current production. Thomas P. Chambers: I'd like to go back to your question about, are we abandoning in the long-term. Really, just think about what Rod said in these long-term projects we're spending over $2 billion on this year. They're going to add 150,000 barrels a day, and then later 200,000 barrels a day. So, those are big needle moving projects where we've got to put capital over a number of years. We don't get near-term production growth, but when they come on, you see a real stair step in our growth. And so, when Steve was talking about LNG projects, for example, those are very big stair steps that will bring our average rate over the long-term back to the kind of range that we were talking about earlier. But in the short-term, those are dollars that aren't adding production in 2013. The rate of return is great, but when you bring them online especially those LNG projects they don't deplete. So they are very enticing.

Your next question comes from Matthew Portillo with Tudor Pickering Holt & Co. Matthew Portillo – Tudor Pickering Holt & Co.: Good afternoon. Thomas P. Chambers: Good afternoon. Matthew Portillo – Tudor Pickering Holt & Co.: Just two quick questions for me, with limited capital investments in Canada around your gas assets, could you give us a little bit of color on how we should think about volume decline, and then a similar question for the U.S.? G. Steven Farris: Yeah, the capital allocation I think represents $600 million in Canada, which will be directed. Now what we have done just for information, we now have a Kitimat upstream business and we have our base Canadian operations business and we have two different organizations just recently set up; one to do nothing, but the Horn River and Liard. In terms of the base business in terms of our – we are really directing that more towards liquids-rich and in terms of what’s the decline curve is I don’t know. I don’t have it. We should see a slight decline, but it’s not real significant. Matt Portillo – Tudor Pickering Holt & Co.: Okay, great. And then just a second question for me. In terms of the Permian and the Midland Basin, could you provide a little color on how your Cline results have performed to-date? How those look against your type curves, and then how we should think about current well costs? Thank you. G. Steven Farris: Rod, you might. Rodney J. Eichler: Yeah. In the Cline, we’ve really had some good progress on the Cline and we’ve managed to cut six days of the amount of time, it takes to do a Cline horizontal from the Deadwood area. When that translates to an average split rate is about $60,000 a day savings, which translates into about $360,000 wells, that’s very significant. And then generally speaking, we gave you some information at the Analyst Day last June that it cost us about $7.6 million and as a result of some of these efficiency improvements and overall cost reductions that I mentioned that we should be under $7 million in total well cost in that particular formation, and I think the Cline, the well results have been posted in the supplement. Matt Portillo – Tudor Pickering Holt & Co.: Okay, thank you.

Your next question comes from Charles Meade with Johnson Rice and Company LLC. Charles A. Meade – Johnson Rice & Co. LLC: Hello, everyone. If you don't mind, too much, I'm going to take one more step at the guidance question, because I think the other question maybe got us a little bit, we have a – you've laid out the 3% to 5% overall BOE guidance, but it's maybe not that – it's not meaningful. It's not apples-to-apples to replace – when you're replacing oil volumes with gas volumes or vice versa as you guys are. So, if you have it in your mind and can share it, do you have an idea of the four pieces of your product mix that North American liquids, North American gas, international liquids, international gas, what the individual growth rates on those four would be? Or maybe you might not have it, but I just thought it. G. Steven Farris: Everybody is scrambling for information here, give us a second. Charles A. Meade – Johnson Rice & Co. LLC: Well, you can come back to that and another thing, I greatly appreciate all the data in the operations supplement you have. Just two of those – just two things on that if I could ask; one, I saw you guys drilled another really good horizontal on the Central Basin platform in the Permian, and I think you're really the only operator who's been doing that. So, I'm curious if you're planning on doing a lot of much more event and then, the last kind of obscure question that comes from the operations release is, I noticed in the Gulf Coast region, you said you're drilling in Lamar County, Mississippi, and I'm wondering if that's the smack-over target or if you're ready to talk about that? G. Steven Farris: Rod? Rodney J. Eichler: Well, the answer to your first question, I believe you might be referring to our drilling program in our Three Bar Shallow Unit, which is the Wichita Albany play. I think we mentioned that at our last quarter's call. We've continued to drill. We have five wells drilled and producing there. It’s one of our best plays and take in terms of the estimated ultimate recovery for horizontal wells and we have about a couple of wells that are waiting on completion and we have additional 12 wells yet to drill in that program, a lot of which would be drilled in 2013. Your second question dealt with what are we doing in Lamar County, Mississippi? Charles Meade – Johnson Rice: That’s right. Rodney J. Eichler: Well, we’re drilling an exploration test and that’s in progress. That’s all we want to say about it right now. Charles Meade – Johnson Rice: Got it, okay. Thank you very much, and if you have those other growth rates, I’m going to stay on the call and queue up whenever you guys are ready. G. Steven Farris: North American Oil is supposed to grow at 14% for 2013. That’s what we’re projecting.

Your next question comes from Leo Mariani with RBC Capital. Leo Mariani – RBC Capital Markets: Hi, guys. You talked about some exploration plans in 2013. I think you guys said three deepwater Gulf wells and then six wells in Australia. Could you give us some more information about what type of targets those are and what some of the associated growth potential maybe on some of those? Rodney J. Eichler: In Australia, the wells are mostly in the Olympus-Bianchi, the general quadrant going south, just north of Exmouth Basin area. They’re targeting the typical Mungaroo Triassic reservoir objectives, which we have in other producing areas out there. We have successful exploration tests at Zola back two years ago and we’re following up on that. In the Gulf of Mexico deepwater, as I recall that those specific targets or those prospects I mentioned will probably be [Midland Basin]. Leo Mariani – RBC Capital Markets: Okay, thanks. And I guess, additionally another question on the asset sales. Traditionally Apache has been obviously an acquirer of a lot of assets over the years. Is there any sort of shift in philosophy that you guys are seeing here, now that you have announced these asset sales, somewhat I guess prior to specifically identifying it. I mean, you guys trying to maybe strengthen the balance sheet in response to maybe some capital expenditures coming up on the LNG side in the next couple of years? How are you guys kind of thinking about it, if there is any just philosophical change, just curious on that? G. Steven Farris: Well, from a philosophical standpoint if you look at where we have come from over the last three years, and if you look at the assets that we’ve acquired, and it's not just here in the last week but over the last month or two, we’ve been looking at our asset base and saying, okay, now which one of these asset bases do we want to take forward into the future. And we have to make some tough choices – we can't be all things to all people. So we go to make some choices as to which one of these that we can actually exploit or could somebody else exploit them better. So we're still going to be a net buyer. If you think about $16 billion and $2 billion, but in terms of just transitioning our asset base that's what the effort's about.

Your next question comes from Brian Singer with Goldman Sachs. Brian A. Singer – Goldman Sachs: Thanks, good afternoon. Just picking up on the growth in the asset sales and the acquisitions together. It's interesting to know that the areas that you have that are growing rapidly, the Permian and the Midcontinent are where you have focused your acquisitions over the last couple of years. And then, so I guess in your interest in achieving your 6% to 9% guidance longer-term, there are various ways you could do, you could acquire more assets in growth areas, you could sell assets and producing areas that have little growth, or you could just wait it out as kind of Roger described, and wait till some of these long lead time projects come online. Is it fair to say, that it's more of the latter strategy there just kind of wait things out until the long lead projects come online that you've kind of decided on. And then, in that case, should 2014 be another year of relatively low growth? G. Steven Farris: Yeah. We haven't reported our 2014 plan. It really depends on how we allocate that capital, Brian, and also what our asset base looks like. We certainly want to further those long-term projects, but we also have to balance this. What I was suggesting is, we have to balance short-term growth with long-term growth. Brian A. Singer – Goldman Sachs: So I guess, would you consider acquiring any areas that have become more core to you or as for the rest, or are kind of acquisitions completely off the table here? G. Steven Farris: Well for the present time, we are going to drill wells. So that doesn't mean we won't pick up an acre or two around some place, but in terms of making major acquisitions in our existing core areas or new core areas, that's not something that's part of our strategy right now. Rodney J. Eichler: On a project side, we do have three or four projects, which will mature to first production in 2014. These are in Egypt and in Australia and that could add, approximately in the range of 25,000 barrels of oil equivalent per day. Brian A. Singer – Goldman Sachs: Great thanks. And then just to clarify on the asset sale decision, have you definitive call that you're going to sell the $2 billion of assets or are you considering asset sales up to $2 billion? G. Steven Farris: Obviously price has something to do with it, but we certainly are dedicated to selling $2 billion worth of assets.

Your next question comes from Kevin Cashman with Assurant. Kevin Cashman – Assurant: Hi, and thanks for taking the question. Just kind of following up on the asset sales in the – you mentioned some of your refinancing last year with the two 2013 maturities coming up. I'm just wondering, you mentioned debt reduction would that be a plan to reduce those ultimately with the debt proceeds or payment? Thomas P. Chambers: Yes, I mean that's a consideration. Once we get, depending on the timing of when we get these assets sold and what else is on our plate, that is definitely a consideration to pay down that debt. Kevin Cashman – Assurant: Have you guys had your annual meeting with the rating agencies for this point already? Thomas P. Chambers: No. Kevin Cashman – Assurant: When is that coming up? Thomas P. Chambers: Shortly. Kevin Cashman – Assurant: Okay, thank you very much.

Your next question comes from Michael Howe with Robert W. Baird. Michael Howe – Robert W. Baird & Co., Inc.: I guess, my point has been addressed but I'll jump back on the production outlook topic, commented through the question in another way. As you look at just your mix of natural gas oil liquids, do you see that shifting materially as we make our way through 2013, you've seen a nice... G. Steven Farris: You're going to see our oil production as a percentage continue to grow up. Michael Howe – Robert W. Baird & Co., Inc.: All right. G. Steven Farris: Because we are predominantly drilling oil wells or liquid rich gas wells. Michael Howe – Robert W. Baird & Co., Inc.: Can you quantify any of the changes, directionally? G. Steven Farris: What we have said and I don't have the numbers in front of me, Brady is looking at them. What we say is we're going to grow our North American oil by 14%, so.

And your final question comes from Joe Magner with Macquarie. Joseph Magner – Macquarie Capital: Yeah, just one quick follow-up, I wondered if you had any update on some of the new exploration ventures that were detailed fall of last year in the Cook Inlet, Montana, Mississippi in particular. G. Steven Farris: We are almost down on our Alaska well. We were 11,400 feet; we're going to 11,800 feet. Then obviously we'll have to test it and run pipe and all that stuff. And in the Bakken, in Montana, and in the Mississippi Lime, we've drilled few wells bulk of those we're really concentrating our efforts right now on the United States, on the Permian and the Anadarko Basin. And then we just picked up a block as Rod pointed out, we picked up a block in Suriname which is a very good block and we're getting ready to shoot 3D seismic on it.

There are no further questions at this time. I would now like to turn the conference back over to the hosts for any closing remarks. F. Brady Parish: Thank you very much for attending our conference today. We appreciate it, and if you have any additional questions, obviously, reach out to the IR team and we will get back to you as soon as we can. Have a great day.

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