APA Corporation (APA) Q4 2010 Earnings Report, Transcript and Summary

Roger Plank - President and Member of Risk Management Committee Rodney Eichler - Co-Chief Operating Officer and President of International John Crum - Co-Chief Operating Officer and President of North America Matthew Dundrea - Senior Vice President of Treasury and Administration, Treasurer and Member of Risk Management Committee G. Farris - Chairman of the Board, Chief Executive Officer and Member of Executive Committee Alfonso Leon - Vice President of Planning Strategy and Investor Relations Thomas Chambers - Chief Financial Officer, Executive Vice President and Member of Risk Management Committee

Brian Singer - Goldman Sachs Group Inc. John Malone - Ticonderoga Securities LLC Leo Mariani - RBC Capital Markets, LLC Robert Christensen - Buckingham Research Group, Inc. Raymond Deacon - Pritchard Capital Partners, LLC Pearce Hammond - Simmons & Company International Douglas Leggate - BofA Merrill Lynch Joseph Allman - JP Morgan Chase & Co Rehan Rashid - FBR Capital Markets & Co. Robert Morris

Good afternoon, and welcome to the Apache Fourth Quarter Year End 2010 Earnings Release Conference Call. Today's presentation will be hosted by Mr. Alfonso Leon, Vice President of Planning, Strategy and Investor Relations. [Operator Instructions] Thank you. Mr. Leon, you may begin your conference.

Good afternoon, everyone, and thank you for joining us for Apache Corporation's Fourth Quarter 2010 Earnings Conference Call. This morning, we reported 2010 net income of $3 billion or $8.46 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results, totaled $3.2 billion or $8.94 per diluted share. Cash flow from operations totaled $7.4 billion. On today's call, we'll have five speakers making prepared remarks prior to taking questions. Steve Farris, our Chairman and Chief Executive Officer will lead off; followed by John Crum, Co-Chief Operating Officer and President of North America; Rod Eichler, Co-Chief Operating Officer and President of International; Roger Plank, our President; and Tom Chambers, Executive Vice President and Chief Financial Officer. We prepared our usual detailed 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 costs incurred. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussions may contain forward-looking estimates and assumptions, and no assurances can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thank you, Alfonso, and thank you, everybody for joining us this afternoon. All of you, I'm sure, have read this morning that Apache announced record production of 658,000 barrels of oil equivalent a day for 2010. That is a 13% growth from the previous year. As Alfonso pointed out, we had record annual earnings of $3 billion, and we also ended the year with record proved reserves of around 3 billion barrels of oil equivalent. So under any metrics, Apache had an outstanding 2010. We delivered major growth oil projects, including Van Gogh and Pyrenees in Australia and the Kalabsha oil facility in the Western Desert. We advanced our global gas resource monetization strategy through the agreement of an oil-linked OPEC agreement for our Julimar Field via Wheatstone LNG and are becoming majority-owned investors of Kitimat LNG project in Canada. And we took some opportunistic portfolio steps that made us even stronger than the portfolio we started off with at the beginning of the year. In the Permian, we more than doubled our footprint to over 3 million gross acres spanning every play in the basin. In Canada, we gained high-quality properties at an entry price based on low gas prices. In Egypt, we have secured a second major export route for natural gas out of the Western Desert, which should enhance our growth prospects there. And in the Gulf of Mexico shelf, we reloaded our inventory with a new underworked property set from Devon and Mariner. And last but not least, we gained a new long-term growth business in the Deepwater Gulf of Mexico. Now those are just some of the highlights. There's much more on a day-to-day basis going on that creates value for us, and John and Rob will walk through that in a moment. But the short answer is, we're looking at an opportunity set for many years to come like none we've ever had. We are organizing an Analyst Day for May 17 in which we will outline in more detail what this updated opportunity set looks like. Before I turn to 2011, I'd like to provide you a little color, update on our Egyptian operations. The most important item is that all Apache's staff and families are safe. I’d like everyone to understand that Apache has not experienced any production interruption as a result of the developments in Egypt during the recent weeks. And following the advice of U.S. State Department two weeks ago, we redeployed all nonessential expatriate personnel and all expatriate dependents from Egypt. We have created an Egypt floor in Houston and activity is going on as usual. I might add that the general situation in Egypt has improved markedly over the last week. About 1/3 of our expat personnel are already back in Egypt, including most of our field staff. We continue to monitor events closely, and we'll take additional steps if necessary to ensure the continued safety of our staff in operations. I'd like to turn now to our plans for 2011. For 2011, it's going to be a very strong growth year for Apache. We're going to consolidate around our larger opportunity set, and we're building a balance sheet strength as we go into the year. So presently, we've authorized $7.5 billion of capital expenditures for 2011, which is significantly less than our anticipated cash flow for the year based on strip prices. Apache's balance sheet strength and flexibility is an important strategic asset, and we want to ensure we continue to build them for 2011. And so we deliberately established an initial capital budget that will enable us to reduce debt even if prices decline from today's strip. And as been our custom over the years, we will review capital expenditures and should strip prices hold or rise, we'd expect the increased capital later this year. We intend to supplement our debt reduction efforts by pursuing approximately $1 billion of property sales in 2011. These are most likely going to come from our legacy conventional properties in Canada. With the BP transaction, we have an opportunity to high grade and right-size our portfolio up there. We're going to continue to invest in future growth projects. Nearly a third of our 2011 capital program is going to projects which contribute no production in 2011 but will result in later years’ production, which ensures our continued long-term profitable growth. With this capital program, we expect to deliver in 2011 strong double-digit production growth of between 13% and 17% over 2010. Now, I want to point out this excludes any impact from potential acquisitions or divestitures. Our acquisitions in 2010 will, obviously be an important growth driver in 2011. This is purely a function on our capital allocation. Over the last two years, we have invested $8 billion in addition to oil and gas properties, including future growth projects and over $12 billion in acquisitions. If we had allocated that $12 billion of spending capacity into drilling instead, our growth for 2011 would come from that drilling capital. As all of you, I know, are aware, we are a rate-of-return-driven company, and every year we channel our resources into the projects that provide the best returns and long-term growth for our shareholders. I might add that looking beyond 2011, what was a deep opportunity set has become significantly deeper. Our regions have looked beyond now in 2015, and they currently have identified inventory to grow production from 6% to 12% per year with a track to get economics that are [indiscernible] (0:19:38) best assumptions. And I want to make it clear that that's not necessarily what we are going to do. That means we have an opportunity set to do that. Every year, we adjust our plans to give our shareholders the most attractive returns on a long-term growth basis. And we'll outline some of this inventory in our May Analyst Day. The true picture is that our growth in 2011 and beyond is only limited by how much money we spend. We're only scratching the surface of our opportunity set. In the 1.7 million gross acres of BP Permian business, we're starting to get an update to build the real inventory. In other parts of the portfolio, such as the Gulf of Mexico, we don't have a clear picture of what our capital spending will be given the regulatory process uncertainty. I'm sure we will learn more as the year progresses, and we intend to put a new plan together halfway through the year to ensure we fund the best opportunities. We may also release additional drilling capital depending on commodity prices and our balance sheet risk. As most of you are aware, this really isn't unusual for us. Historically, we have allocated capital to our regions on a quarterly basis in any event. I'll finally note that we have always been and will remain opportunistic a company. We don't have any BP-sized transactions on the horizon, but we are seeing more of the quality assets we like. We never plan for acquisitions, and we will capture those opportunities if and when they make sense based on our experience. And with that, I'd like to turn it over to John Crum.

Thank you, Steve. North American production in the fourth quarter was up 26% sequentially. The main positive drivers were the consolidation of acquisitions in the Granite Wash development. The negatives were primarily associated with the ongoing permitting issues in the Gulf of Mexico. With that in mind, I will start with the Gulf of Mexico shelf. For perspective, in 2008, we drilled 62 gross wells in the Gulf of Mexico shelf. In 2009, we drilled 20 wells due to low product prices and the result in corporate capital curtailment. Consequently, we started 2010 with an especially strong 59-well inventory on Apache properties alone. That would be excluding the Devon and Mariner acquisition properties we got last year. Due to the moratorium and the permitting process delay, we were only able to drill 36, including the Devon properties. Similar restrictions affected the Mariner assets. With ongoing uncertainty around the permitting process, we cannot assume a normal year and as a result, we are planning 41 gross wells on the shelf, including Mariner and Devon properties. In spite of this, we anticipate region production to grow moderately in the 3% to 5% range in 2011 with a full year contribution of the 2010 acquisitions. The Gulf of Mexico shelf remains an attractive rate of return business and a big cash flow generator for Apache. The silver lining of two years of reduced activity is that when we get back to work at full pace, we will have a very robust pent-up inventory of drilling opportunities. With the Mariner acquisition we have formed a new deepwater region and are excited about its contribution potential to Apache's long-term growth. Mariner's deepwater team constitutes the core of the new regional organization, and we know Apache will benefit from their know-how and track record of project delivery. Our deepwater region brought on stream its first Apache project in late December. The Balboa field was developed through a 6-mile subsea tie back to the existing infrastructure with initial production of 6,500 barrels equivalent per day gross. Apache operates with a 50% working interest. During 2011, we expect four other tie back projects to come on stream at Bushwood, Wide Berth, Mandy and Ewing Bank 998. We expect 2011 deepwater production to average over 15,000 barrels per day subject to any regulatory delays. Looking beyond 2011, we have an attractive pipeline of deepwater development projects, including the world-class discoveries at Lucius and Heidelberg. We also have a broad exploration portfolio across 110 blocks. While we have moderate expectations until there is greater regulatory clarity, the potential for Apache to build a meaningful business in the deepwater is significant. We have also created a new region to focus on our Gulf Coast onshore assets where we control over 700,000 acres, including almost 300,000 acres in South Louisiana where we own the minerals. We believe the opportunities for growth onshore warrant having a dedicated organization and based on our recent experience in the Permian, since it was created as a focus region, we expect great things from our Gulf Coast onshore team. In 2011, we currently forecast strong single-digit growth for the Gulf Coast onshore region. Moving to the central region, we will keep about 12 rigs running all year long with more than 95% of those drilling horizontally. The Granite Wash play will remain a strong growth driver in 2011 where we will keep at least eight horizontal rigs busy during the year. We expect to drill 40 gross horizontal Granite Wash wells and achieve production growth of over 10% in 2011. During 2010, the central transition from vertical to horizontal well is almost completed. We control over 1 million acres primarily in Western Oklahoma and the Texas Panhandle, which means that as new horizontal drilling plays emerge, the central region has a footprint to make those new opportunities material to Apache's growth. Moving to the Permian. We now own over 3 million gross acres with exposure to every play in the Permian basin. The BP and Mariner transactions enabled us to more than double our footprint from last year, given the excitement about the potential of the base and frankly, [indiscernible] (0:25:58.3) releasing our asset options. We are currently running 23 rigs in the Permian and plan to remain above 20 all year long, while drilling 368 wells for the year. Mariner's Deadwood assets will be the largest component of this activity. Our acreage is subject to continuous drilling process, so we are now running 11 rigs and will average 10 for the remainder of the year drilling 130 wells. We are primarily drilling vertical wells for Wolfcamp, which can enhance when we find possible strong play in the same wellbore. We are developing the acreage with vertical wells costing around $1.8 million. The typical IP is 125 barrels equivalent per day and produce EURs in the 150,000 boe's ultimate recovery with over 75% of that being liquids. These wells deliver rates of return well above 20% at plant prices, which are currently significantly [indiscernible] (0:27:04.3). We have already identified 800 locations in this asset alone, and that is before we include any horizontal prospectivity, which we are just now starting to evaluate. We hold 85,000 gross acres or 63,000 net. It's a great asset. The second largest component is our joint venture with Concho and the Empire/Yeso, where we're now running two rigs and we'll drill 55 wells this year. We have identified over 600 locations already. We expect these wells to be lower cost and generate higher rates of return than Deadwood. In 2010, we also had good results drilling horizontals in four different old water plants and continue to learn more about the potential for horizontals in the Permian basin. In 2011, we will drill 41 horizontal wells across a number of our assets. The Empire/Yeso area is the first phase of BP's 1.7 million gross acres that we acquired, where we will have a new regional project. We are currently working through an integration plan which will be completed by midyear. We are confident that we will generate numerous other project opportunities on those BP properties. As Steve noted, we're only starting to scratch the surface on our Permian opportunity set. We're in the early steps of evaluating horizontal potential in the basin and still are getting our arms around the entire BP opportunity set. We've gone from five operated rigs at this time last year to over 20 today. Half of those are operating on the Deadwood asset, which represents less than 4% of our acreage. We believe the Permian results will purely be a function of how much money we want to spend and how we pace ourselves. Outside the Mariner Deadwood position, almost all of our acreage is held by production, so we can develop at whatever pace is appropriate. We have conservatively identified over 5,000 locations and are poised to double our activity level over the next several years. With over 3 million gross acre spending every [indiscernible] (0:29:13.2) it's easy to see why we're excited about our Permian position. All in, we're currently forecasting a moderate single-digit growth in the Permian from fourth quarter 2010 to the 2011 average. But again, that will be a function of how we decide to change the pace as we integrate the BP assets. I should note that during the first half of February, we have experienced significant freeze offs in the area due to the unusual weather conditions, it's going to have a significant impact on first quarter's production somewhere in the range of 4,000 barrels per day for the quarter. Finally, in Canada during 2011, we're going to take advantage of our broad opportunity set and we will run two to three rigs each in our oil, EOR and liquid-rich West 5 and Kaybob areas and in exploration. In addition, we will have two-plus rigs running in the Horn River and Noel areas for a total of 10 rigs running during the drilling months. We expect Canada production for 2011 to grow in the strong single-digit range from fourth quarter 2010 levels. Our Noel tight gas project in the Montney area ramped up to 100 million a day by the end of the fourth quarter. 14 wells are drilled in 2010 with continued development of locations in the Cadomin & Doig formations. This activity will continue in 2011 with 11 more wells. The team's ability to optimize cost by moving to multilateral and pad development will make Noel a profitable project even at current gas prices. We have 75 additional locations identified in the Cadomin & Doig. The Horn River development will continue as wells drilled in prior years are completed. In addition, our partner in Cadomin will drill 1/2 of the pad this next year or in 2011. Kitimat LNG continues to move forward. Front-end engineering and design is underway. Last week, we, and our partner EOG announced [indiscernible] (0:31:20.2) to gain full ownership and control of the 287-mile pipeline, which will link the Canadian grid to the export facility. We are currently in OPEC discussions with several Asia-Pacific LNG buyers. We are targeting an investment decision by the end of the year and would expect to commence exports of 700 million feet of gas per day in late 2015, with significant expansion potential. Apache owns 51% of this project. We continue to advance other material lead plays in Canada, and we will comment on them at the right time over the coming quarters. I will conclude North American highlights by noting, in Canada's joint venture with PetroChina this last week, which would imply a value for our Canadian portfolio of over $20 billion based on reserve ratios. Combining the value of our Permian basin based on the Permian company valuations, this would imply that these two North American regions [indiscernible] (0:32:24.5) over 80% of Apache's entire current enterprise value. Now I'll turn it over to Rod Eichler for international.

Thank you, John. International production volumes in the fourth quarter were down 5% sequentially driven by facility outages in Australia and the North Sea. In Australia, Van Gogh was impacted by essential maintenance activities on the FPSO turret swivels and turret mooring system. Net fourth quarter production of 6,100 barrels of oil per day was down 17,600 barrels a day from the third quarter. Production resumed on February 7 and was 21,000 net barrels of oil per day earlier this week. Production has been temporarily shut down since last night due to proximity of Cyclone Dianne. We expect production to decline naturally during 2011 as originally planned. Pyrenees project fourth quarter production was 27,000 net barrels of oil per day achieving project pay up in December. Some of the wells at Pyrenees have also been shut in due to the Cyclone Dianne. The project is expected to experience potential decline phase during 2011. With plant decline in these two projects and modest contribution from future development projects, we expect average Australia production to decline in the low-teens in 2011. However, we expect strong production growth to resume in Australia in 2012 as other development projects come on stream. To summarize their sequencing, Halyard and Reindeer are expected on stream within 2011 by achieving full contribution in 2012. Coniston and Macedon are expected on stream in 2013. Balnaves in 2014 and Julimar, Wheatstone LNG in 2016. This project pipeline represents incremental volumes net to Apache of 18,000 barrels of oil equivalent per day in 2012, 37,000 barrels of oil equivalent per day in 2013 and 54,000 barrels of oil equivalent per day in 2014. And that is before Wheatstone brings an additional 37,000 barrels of oil equivalent per day in 2016. All of these projects remain on track toward their first production [indiscernible]. Last week, our board sanctioned the development of the Coniston oil field, which will be tied back to Van Gogh FPSO and will expand the economic life of the Van Gogh production. First production at Coniston is expected in 2013 with an average 7,100 barrels of oil per day net to Apache. The Julimar and Wheatstone LNG project continues to advance toward final investment decision expected in second half 2011 as Apache or its partners have entered agreements with LNG buyers representing nearly 80% of the project's production. The Carnarvon Basin offshore in Western Australia is about the same size as the Gulf of Mexico [Audio Gap] but less than 10% of the wells in the Gulf of Mexico today. We have achieved continued exploration and discoveries in the Carnarvon for many years, which we have transformed into a pipeline of large development projects for Apache. During 2010, we expanded our exploration footprint there by 44% via farm-ins to seven permits, representing 2.7 million gross acres. Apache will operate all of these with a 30% to 75% working interest. In 2011, we will take the first step to unlocking the resource potentials in large portfolio to the acquisition of 1.3 million acres of 3D seismic and the drilling of Southern wildcat wells. Turning to Egypt. The region achieved a new production record of 374,000 gross barrels of oil equivalent per day in November. We currently have 23 drilling rigs running in Egypt, and assuming normal operating conditions, we expect to maintain this level of activity to deliver moderate single-digit production growth for the year, while we advance important growth projects, including the upgrading and looping of the Salam to Abu Gharadig to Dashour pipelines and sanctioning of the Salam gas plant 5. Asset integrity testing on existing southern pipelines and acquired BP processing facilities are underway, and upstream projects are nearing completion to deliver additional gas to Egyptian market via this new second export route for Apache the first gas during first quarter 2011. We plan an active exploration here in Egypt with 65 gross exploration wells, an increase of [indiscernible] from 2010. We will also drill our first horizontal wells in the Western Desert. In addition, during first quarter, we will complete processing of a new 3D over the Abu Gharadig concession we had acquired from BP, which had not a new 3D in over a decade, in spite of its location at the heart of one of the most prolific areas of the Western Desert. Moving to the North Sea. Fourth quarter production was affected by downtime related to well workovers. While this is behind us, first quarter production has been reduced by 11,600 barrels per day outage of the Forties Bravo to Charlie pipeline. About half this daily production will be restored in March via a temporary repair with full production restoration set for September upon installation of the replacement pipeline. Due to this downtime, we currently expect North Sea production for 2011 to be nearly 10% below 2010 levels. Nevertheless, Forties remains one of the best investments ever made by Apache, and holds large remaining opportunities for us. During 2011, we will advance our ability to realize these opportunities through the fabrication of the Forties Alpha satellite platform which will be installed in 2012 to give us additional drilling spots. We will also begin production from the Bacchus field during the fourth quarter 2011 as a tie back to the Forties alpha platform. We plan a 16-well Forties drilling campaign in 2011, which will benefit from the new Forties survey that has already improved our ability to identify and target pockets of unswept oil. This new Forties recently led us to redirect an Echo target and identify two Charlie drilling locations with very successful results. One of these Charlie wells has been tested at 3,300 barrels of oil per day. We expanded our footprint in the North Sea with successful bid for four exploration licenses in the highly competitive 26 licensing round, in addition to farming in to the Siegel [ph] and Siegel North [ph] licenses with a 50% working interest. The Siegel [ph] licenses operated by Talisman only estimated 44 million barrels on discovery. Finally in Argentina, as of April, we expect our gas plus sales to increase from 10 million cubic feet of gas per day [indiscernible] price of $4.10 per million BTU to 63 million cubic feet of gas per day or the equivalent nearly of 1/3 of our fourth quarter gas production in the country at a weighted average price of $4.84 per million BTU. This is an important step forward for us and supports our strategy of drilling for gas in places that are short of gas. We plan to run six drilling rigs in Argentina during in 2011. Three of the four development rigs will focus on gas test run drilling, and two rigs will drill exploration wells. We currently expect Argentina production to grow by more than 10% in 2011. During 2010, we grew via bid round licensing and farm-ins to 1.7 million gross acres on new condition shale gas fairway. This represents 944,000 net acres. A number of major international groups have recently stopped to enter this play and we were able to capitalize on our existing position in the basin and our partnership with YPF to secure an early shale acreage position, which we believe is second only to YPF's. We are currently drilling the [indiscernible] shale well in South America in the Neuquén Basin. We expect to reach target depth in March but we'll complete the well in April due to equipment availability limitations. We will be able to sell production from this well for $5 per million BTU under one of our existing gas plus contracts. That concludes the international highlights, and I'll now turn it over to Roger Plank.

Thanks, Rod, and good afternoon, everyone. We've got a long line of speakers today. So I'm just going to underscore a couple of quick points about Apache's competitive position before our new CFO, Tom Chambers, finishes up with the numbers. The first point is that we are in an ideal operating environment for Apache. Low North American gas prices and high oil prices mean many gas-weighted competitors are struggling to make ends meet, while Apache turns in record financial results. A related point is, that while we have dialed back our initial 2011 capital budget, we are doing it to ensure that we reload our firepower, not because we are pessimistic about the [indiscernible] purposes and specifically oil prices. Frankly, with less than 1/5 of our revenues emanating from North American natural gas, gas prices could literally fall in half and the impact would be relatively insignificant to our overall portfolio. So the real issue for Apache is oil. And there we think the fundamentals are very strong. You are, no doubt, aware that WTI presently trades around $85 per barrel or about $5 higher than last year's average. You may not be aware that Brent is trading at over $100 a barrel or $20 higher than last year's average. That is very good news for Apache as well over half our oil production is priced-off Brent. My point is that things are lining up for what could very well prove to be a banner year for Apache. With oil prices strong and double-digit production growth, we're well positioned, not only to bolster our balance sheet, but also to be in a position to release more capital should current conditions remain. Precisely at a time when opportunities are abundant and the competition is struggling. That's an ideal environment for Apache to continue to execute our profitable growth strategy. Tom?

Thanks, Roger. Good afternoon, everyone. One more time, I'd like to reiterate that we earned a record of $3 billion in earnings or $8.46 a share for 2010. It's a great number, and I'd like to reiterate it. When we adjust for the items that impact the comparability of those results, we earn $3.2 billion, $8.94 a share, which is up nearly 70% from the prior year's $1.9 billion. Record production combined with higher oil prices drove cash from operations up 48% over 2010 to $7.4 billion for the year and just shy of $2 billion for the quarter. This speaks volumes for our balanced portfolio, and we've been able to benefit substantially from higher oil realizations and the fact that oil currently sells for over 20x the price of North American gas. Oil and liquids accounted for 77% of our revenues in 2010 that represent just over half our production. Oil alone accounted for 49% of total 2010 production. Our oil portfolio offers another unique feature when it comes to price, as Roger just mentioned. Almost 60% of our total production, which encompasses all of our international oil production, with the exception of Argentina, is sold against the Brent index. Brent is currently running at a significant premium over $15 a barrel to WTI versus the traditional discount. Therefore, we are well positioned to benefit from this pricing situation. In addition to that, U.S., LLS and HLS crude rates are selling at double-digit premiums to WTI. Over 30% of our total U.S. volumes are sold against these indices giving us an additional revenue benefit from our U.S. oil volumes. Our higher oil exposure also impacts operating costs. Cash costs, excluding taxes other than income and merger and transition costs, averaged $11.73 per boe in 2010, up about $0.50 per barrel compared to 2009. Our goal was to keep 2010 cash costs flat with last year, but we ended up 4% higher influenced by the impact of rising oil prices on costs. Recurring DD&A was also up from the prior levels as you might expect, given the significant level of acquisitions in the year. Turning to reserves. We replaced current production through drilling by adding 245 million barrels of oil equivalent and proved reserves during 2010. Including acquisitions, sales and revisions we replaced 344% of production. I'm not going to spend a lot of time on the fourth quarter since it was pretty noisy due to acquisition timing, change in the mix of the properties due to the acquisitions and operational issues and as you've, no doubt, noted, the financial results bear that out. From a production perspective, the fourth quarter rate of 729,000 barrels equivalent a day was our best quarter ever. Unit costs were up for the quarter because of the combination of plan production downtime, onetime transaction costs and bringing in to our portfolio higher unit cost of properties from acquisitions. Now we'll get to work, and coupled with restoring production, we expect our capital cash cost to come back in line and dropping throughout the year to exit the year at around the average of 2010 or around $11.75 per boe, which excludes taxes other than income. We would be remiss if we didn't talk about our hedging program, including hedges assumed from Mariner. For 2011, we have approximately 120,000 barrels of oil per day hedged. Most of our positions were entered using collar arrangements with floors just above $69 and ceilings of around $97. In total, we've hedged around a third of our oil production. We've not entered into any new gas hedges over the last quarter but approximately 25% of our North American volumes are hedged for 2011, primarily with swaps at around $6.25 per MMbtu, which should give us the benefit given the current gas prices. And finally, we exit 2010 with 25% debt to cap, which is only slightly higher than the 24% we had entering the year, even though we completed over $11 billion in portfolio transactions. As Steve mentioned, during 2011, we'll maintain a strong focus on building our balance sheet strength further, which is our long-term strategic firepower asset by paying down additional debt. And with that, I'll turn the call back over to Steve.

Thank you, Tom. I'd like to summarize what I think the three main messages of the call are. Number one, 2011 is going to be a good year of strong production growth for Apache and a focus on consolidated our enlarged portfolio. We're going to continue to build our balance sheet strength, and we're going to continue to remain opportunistic in the strategic arena. Number two, we had a strong portfolio going into 2010, and after the project licensing and portfolio steps were [indiscernible] in 2010. We have a formidable inventory that can sustain Apache's growth for years to come. And number three, the reality is that we're only scratching the surface. The full opportunity is set and Apache's enlarged portfolio, and the challenge in front of our teams now is to scope and prioritize the best rate-of-return opportunities and for all of us to get after them while staying true to our principles of portfolio balance and financial conservatism. And with that, we're ready for your questions.

[Operator Instructions] Your first question comes from the line of [ph] Flynn Del Pozo with IHS.

Where did your U.S. oil reserve additions come from, the organic ones? And also, the -- I saw some revisions in there for the positive revisions for the U.S., whether those were price or performance-related.

Well, most of the oil from the revisions were priced in the U.S. And I will tell you, internationally, we get a negative because of the Egypt cost sharing. So price helps us in the U.S. and hurts us in Egypt. Certainly, Permian Basin was a big chunk of that, both on the organic side and the buy side with the Permian, and the Gulf of Mexico was a big chunk of that. We also got some liquids help in the Texas Panhandle with our Granite Wash stuff.

It sounded like you'll will be developing, most intensively, the properties acquired from Mariner. And since the BP properties you had mentioned in the past, that they had not had an operated well drilled on them by BP for four years, I was just kind of wondering whether -- what are the chances you're going to increase the rigs that you'll deploy on the BP's Permian properties?

Almost certainly, we'll be increasing the rig activity on the BP properties. I think we've indicated to you in the past, BP was running their Permian Basin from -- so consequently, just getting the records in the hands of the guys that are operating these properties out West has been a little bit of a challenge. We're getting there. The Mariner asset we have to get on with, because we had bought a lot of acreage out there in the last year with continuous drilling clauses. So it's critical that we go in and hold the leases, and then we'll move on to the BP properties.

Okay.

And then It's a matter of just how much capital you want allocated to it.

And that might change during the course of the year?

Absolutely. If there's one place you would expect to get a little extra allocation, it'd be Permian.

And then moving on to Australia, I see you've been doing a lot of farm-in deals in Australia. If you could just give me a top-down description of the reason for the farm-ins, and how I should look at it in terms of the geological prospectivity, the regions where you're doing the farm-ins? And what are some of the key companies that you might be partnering with, so I could monitor the results of those companies and see how they might affect Apache.

Well, the areas that we're looking at just continue to extend or expand our existing position on the North West Shelf. So it's all in The North West Shelf carrying a long trend of our existing Carnarvon Basin play areas. Predominantly, up to the northeast portion of the shelf, there are large blocks that we keep available, we pursue this year, to farm in with drilling commitments as well as seismic commitments. So we'll start a seismic survey on one of the blocks this year followed by drilling probably in the second quarter this year. A lot of small companies are involved as partners in the blocks. Just off the top of my head, I can't recall the specifics of the many Indian companies with their partners at some of these concessions.

But you guys will be reporting the successes, the discoveries. Not another company?

It's us. We're the operator. We'll be reporting you the activities that are significant.

I noticed a negative oil revision in Canada. What was the reason for that?

That's primarily associated with sliding scale royalties and GCA recoveries. As the price of oil goes up, then we get less.

And then just to address timing issues associated with your acquisitions in the fourth quarter and how that might move over into the first quarter, can you give me any guidance for how much of the production on average during the fourth quarter was from acquired assets and what might happen in the first quarter just to track that movement of the acquired properties?

This is Alfonso Leon. We're going to give others a chance to get in on the question queue. I'll be back in my office right after this. We can follow-up on this after the meeting.

And your next question comes from the line of Ray Deacon with Pritchard Capital Partners.

I just had a question about -- that you partly answered -- it sounds like the first use of incremental capital would be the Permian. Is that right?

Yes, I'd like to follow up a little bit on what John Crum said, because when we talk about increasing capital, we've gone from $400 million in 2010 to going around $1 billion this year. So we're doubling our capital in the Permian because of the acquisitions and because of the opportunities set. The other one is, is that I want to reiterate what John said. We’ve got 10 or 11 rigs running at Deadwood, and that is to save acreage. The fortunate thing is the great play, so we're making great economics at it. But if you have a fixed amount of capital, you want to spend it in an area, and you've got a commitment to make. That's where you're going to spend your money. So if things lighten up, the Permian will be the first place to get it.

You probably have a better view on this than anybody, but do you still feel pretty strongly about the economics of Kitimat and being able to maintain an oil price base currency of number there with all the growth in Australian volumes over the next few years?

Well, let me put it this way. First of all, we can't make Kitimat work unless it's got an oil-based contract with it. The second thing is, is that I think what we're seeing is a tremendous amount of interest now. And again, and I would preface that, we haven't signed anything yet, but there is some real benefit for anyone that has to import LNG to import it out of the North American market. Because the North American market, it has no limit. So it's not field generated. It's not an investment. So once they are into that market, they have gas inputs to it. So we're seeing a lot of interest.

Your next question comes from the line of Joe Allman with JPMorgan. Joseph Allman - JP Morgan Chase & Co: I think you mentioned about $1 billion of asset sales. Could you talk about -- are you looking to sell some assets kind of across the portfolio? Or is there really a focus in Canada? Because you mentioned specifically about high-grade in Canada.

Well, I think our first look is Canada, and the reason is that if you look at our Horn River position already, and then you look at what we picked up from BP and Noel with the Montney and the Cadomin there, we've got a tremendous asset base there. So it's the easiest place to tie to take the bottom layer of that outlet. Joseph Allman - JP Morgan Chase & Co: And then, I know you just commented on Kitimat, but could you give us some color on just the marketing that you had done for the off take of LNG, not just at Kitimat, but any intelligence you have on Wheatstone. You mentioned a tremendous amount of interest. Could you just give us some color on that? You think you'll have no trouble marketing Kitimat and Wheatstone? I know you said you have 80% of Wheatstone spoken for. And then also, you could talk about other issues you need to grapple with in terms of permits or anything else at Kitimat.

Well, right now, we just now started marketing Kitimat. And I think all I can say right at the present time is that we see an enthusiastic market that wants to talk about it. In terms of its position with respect to Wheatstone, of course, Chevron is running the Wheatstone sale. They've been very -- obviously, they've been in that market for a long time, and they've done a very good job. In terms of the viability of it in terms of permits, et cetera, it's really going to boil down to market. I mean, this project will go with the market. There's no huge impediment to this project going forward other than the market.

Your next question comes from the line of Gilbert [ph] Van Borden with Wells Fargo.

I have a question again on Egypt. How much of your reserve production -- I had heard 24%. Am I wrong? And do you have an escape hatch in case something stirs up there where your facilities are in trouble that you would disperse them over other areas?

The first question is I think reserves are about 13% because of the cost sharing mechanism, and production is about 24% of that, maybe 25%, but that's round numbers. In terms of, and I assume what you're asking is do we have a place to spend that money in other projects? Or is it how do we get our money out of there? I don't quite understand the second question.

Well, if something happens over there, can you shut down some of the facilities? Move money and stuff over? Or are you going to be in trouble? I'm worried always about expropriation, things like that happening after viewing what happened with the sugar and our friends, Cuba, and in Venezuela, with Chevron. I mean, some of these governments can be very unstable.

First of all, we've been in Egypt for 15 years, and we have a gentlemen on the board that was there. Chuck Pitman is our board member, used to be with Amoco and was in Egypt twice. And as he likes to say, they first discovered oil in Egypt in 1957, and they've never shut any production in based on the political situation there. Given what is going on right now, I tend to think that it better in terms of investment in Egypt. Certainly, the mood is one of much more market-driven and increasing the standard of living for the people. And I will tell you, we're a guest there, so they're the hosts, whoever the host would be. In terms of being able to take that cash somewhere else, we certainly can. I mean, I can't emphasize enough, and I welcome all of you to come to the May 17 conference, is going to show you the opportunity set that we've uncovered so far. And that was not a puffing or wares when we say we've got a current inventory to grow through 2015, 6% to 12%. And that's not necessarily again what we're going to do, but that's the opportunity set that we see at the present time.

I might comment on your point about taxation or confiscation. We do carry an insurance policy that gives us about $1 billion of coverage in the event that things were to get that extreme. But if you think about it, you mentioned a couple of countries like Venezuela. It's a little different in a country like Egypt where they really utilize their demand meets their supply, so they are the big exporter. Venezuela is a big exporter. So it has a very big cash flow stream. And if you nationalize it, you could argue that at least for the short term, that's in their national interest. In a place like Egypt, if you nationalize the production, what you're going to do? Just hand it off to the population? You don't get a cash flow stream that gives you the same economic inducement to take such drastic action. I think having operated there for 15 years, people recognize that production wouldn't be anywhere near where it is if not for Apache's investment over that period of time. So we think that, that helps us in the period ahead.

Your next question comes from the line of Brian Singer with Goldman Sachs.

When you look at the Gulf of Mexico deepwater, how quickly should we expect you to begin drilling exploration wells once permits are issued or permits are allowed? And how does the deepwater exploration compete for capital relative to the Permian Granite Wash, Montney and your other North American opportunities?

Well, John might comment a little bit on the timing. I'm going to comment a little bit on the competition. I would say, they're complementary, not competitive. We certainly -- a growing concern means you've got to have a lot -- in our opinion, have to have a lot of different ways to win. And we've seen that in every history of every play that's come down the pipe, whether it was Russia or the Austin Chalk in West Texas or East Texas. One play does not make a growing concern. And I think the important thing that you look at, the way we look at the deepwater, it is an exploration. A big reserve play in North America that we don't have anywhere else. And if it is successful on a risk basis, you get a lot of production and a lot of great return out of those projects. So we're going to try to balance that.

Yes, I think it really is the last place to find big oil. On the permitting side, I think we're starting to see a little bit of movement, but there's no question it's going to be slow and gradual as we get our regulator completely comfortable with activity out there. You are starting to see some movement, getting assets to the Helix and the MWCC containment vessels has been really important, and that's really what's held up over the last few months.

And then separately, you mentioned in your comments that you didn't expect 2011 to be as acquisitive a year as 2010, but that you did see some attractive opportunities. Can you add some more color as to whether those attractive opportunities are more offshore versus North American onshore versus international, and whether you're seeing better opportunities among corporate acquisitions versus asset acquisitions?

Well, I think we generally see better acquisitions in the asset side because number one, you only have to buy the assets that you're going after. So a unique thing about Mariner was -- and if you look at where we are active right now, we're active in every place that they were. So it was very easy. It was almost an asset acquisition in the guise of a merger because we really fit in each one of those asset areas. In terms of going forward, each one of the regions we're in, we'd like to get bigger. With the exception and not because -- I'm optimistic about Argentina, I just think even the circumstances in the world today, we might not spend the kind of money there that we've spent in other parts of the world. But we're an opportunistic company. Sometimes, you buy things better than you drill and vice versa.

Your next question comes from the line of Bob Morris with Citigroup.

Steve, you mentioned the capital budget is $7.5 billion and no matter how you slice, it looks like cash flow was going to be above that. And then you'll have another $1 billion probably come in from asset sales. I know you said you want to leave room for debt reduction, but do you have a goal in mind for the debt reduction so that once you hit that we can look at any excess then going back into drilling?

Well, I'm sitting here looking at our Treasurer, so I'm going to let Matt Dundrea, who's our Senior Vice President and Treasurer, answer that question.

We don't have a specific hard target debt level, but we're going to aim for something in between $7.5 billion and $8 billion. Beyond that, I think that might free up some funds for capital.

So your total debt is $7.5 billion to $8.5 billion.

I'm sorry, what was that?

It's $7.5 billion to $8.5 billion, what number is that?

$7.5 billion to $8 billion.

We're at $8.1 billion at the end of the year.

Exactly.

So you'll probably be at $1 billion from the asset disposition. So it’s likely -- some of that's going to go to drilling?

If current strip holds up, you're going to see an additional capital infusion.

Yes, we have a conservative plan at this point.

Your next question comes from the line of Robert Christensen with Buckingham Research.

Could you define the, I guess, gas shale play in Argentina unconventional a little bit more? Thickness and that kind of thing and the type of well you've drilled? And has there been any other company with a couple of well results that we could go look at?

To our knowledge, there are no horizontal wells to be drilled in the shales in Argentina. We're drilling the first one. That well is underway, and I really cannot release any information regarding the well at this time as we're not completely to our total depth. [indiscernible] is a very active player and our partner in many of these blocks. They have drilled some vertical wells as have we, to test the concept of shale richness. It's really a test of proof of concept stage. All the ingredients that are there geologically for robust unconventional resource in at least the Bakken [indiscernible] shale and the [indiscernible] shale in the Central Neuquén Basin area. I guess that's about all I can say right now.

The only point I would make is usually, when you see shale plays, you see a few people that are -- and you see them down there, same folks are punting around down there. I mean, this is not an unknown quantity. It's just we've been down there long enough, but we've got a significant acreage position ahead of a lot of other folks.

Is it a fixed shale? And how long is your lateral? How many stages do you think you'll frac it, I mean, the first well?

The current well is, we anticipate, 1,000-meter lateral, 10-frac stages.

And the thickness of the rock reservoir?

I'd say the general to vertical thickness is probably in -- productive thickness is probably 200 meters to 300 meters.

And your next question comes from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co.: In the U.K., any major exploratory projects for the rest of this year?

Yes. So area aside from our exploitation around Forties. As I mentioned in my remarks, we have a couple of prospects that are operated by Talisman, which we will likely see drilled later in 2011. And of course, we picked up four blocks in the most recent bid round, which we'll be doing the necessary evaluation work to lead the drilling late this year or in 2012.

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

Can you tell us, please, what was the exit rate on production for 2010? And if you could maybe quantify the outages because obviously, there's a fair amount of down time, I guess, U.K. and Australia.

Yes, I think the biggest -- I don't remember the December number. Alfonso can get with it offline. I think say the biggest difference between that and what we posted is we had Van Gogh off, which is about 22,000 barrels a day, and we also had about 9,000 barrels a day off in the North Sea. I mean, it was -- the North Sea stuff probably won't come back until September. Van Gogh started to come back up, but it was off all of January and will be off a portion of February. And then we've had three cyclones in the Gulf. So, I mean, in the Carnarvon Basin.

This one, I know, is going to be difficult to answer, but I'm going to try anyway. So you're already at just over $8 billion as Bob pointed out. It sounds you're pretty quickly going to get to your debt targets. So how should we think about the sensitivity of your growth numbers to capital expenditure? Like I said, I know it's a pretty tough one to answer, but if you could at least try and frame it, that would be great.

Well, frankly, and I am going to say that I don't have any budgeting numbers to go by, it's just an obvious answer. And that is we've got all the base costs in the base budget. So you've got all your seismic costs, all those kind of costs are in the base budget. So most of the things that you'll be seeing other than some exploration stuff that we had a little program in Australia or if somewhere else, deepwater, Gulf of Mexico, God forbid, if we actually got a permit to drill there. You're going to see performing capital. So you should see a disproportionate benefit out of the incremental capital that we spend based on the overall capital budget that we rolled out there right now.

That's absolutely right, and then kind of mitigating that is the earlier we let that capital go, the more you'll see in the annual average. So part of the juggling is we want to have some confidence that these prices are going to stay at these levels before we release too much capital. So there's a balance act is what I'm trying to say.

And the sooner we can get a package out on the street and sold, we'll be -- there's a lot of moving parts going into this year. And the biggest thing I would say is, I want and I hope everybody recognize what I'm saying, the last two years we spent $8 billion drilling oil and that kind of stuff. We spent $12 billion in acquisitions. So our goal for 2011, obviously, is purely capital allocation. This is going to come from those acquisitions. But the biggest thing it brought us is that if we don't buy another thing for the next five years, we can grow this thing -- the high single-digit numbers anyway. So we've set ourselves up to some growth going forward that is significant.

There's a lot of running room, Steve. I guess two very quick follow-ups, and I'll leave it to somebody else. Could you give us an idea or contract updates rather on Australia gas? And the final one is I just wanted to be clear on the 5,000 locations I think John mentioned in the Permian, how does -- is that an apples-to-apples comparison with what you gave us at the time of the deal? Or if you could maybe just elaborate on what's happened to the visibility that you gave us with the Yeso and the Spar barrier at the time, in terms of drilling activity. I mean in other words, how much have you been able to evaluate and add to your drilling locations in the BP assets?

The gas contracts in Australia -- I think, we are pursuing contracts that are significantly higher. I think we probably will announce some. But before we do that, I'd better not comment on that. But that is going to happen, if you understand what I'm saying. In terms of locations, John?

Yes, I guess, Doug, what I'd say is, obviously, we continue to work to go along. And one of our key work processes is really developing resource potential across all of our acreage. So we're just getting through all of these, but we're gradually cataloging what we know are going to be developable assets out there. So that's kind of the number we're at right now and I think we can get higher than that pretty easily.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce Hammond - Simmons & Company International: You mentioned that your operations have not been impacted in Egypt. However, some service companies have talked about limited activity. What do field operations look like now versus a month ago?

Prior to the changes in government, mid-January, we had 23 rigs operating in the desert. And today, we have 23 rigs operating. In fact, that same number operating continually. No single well was shut down with the exception of one wildcat. We were drilling in the far reaches of the Western Desert near Libya. And we got to a safe place to set casing and temporarily abandon the well for lack of services at a remote location. We didn't want to risk a potential well control problem without having a way of correcting that. That well has since been restored to drilling operations. I think we had one or two days where diesel fuel was a little bit short, but that was corrected immediately by the government. And essentially, we had, as I said, we had no noticeable changes, a slight inconvenience, but no real change in the production operations. Gas plants operating straight through, no change in the gas production crew. Same with oil production. Pearce Hammond - Simmons & Company International: And then, now that you're starting to get your hands around the BP assets that you purchased in the Permian, is there anything that you find, particularly in treating from those BP assets, something that you might want to move higher up in the queue?

Well, I don't know that I've got something that runs in front of that Yeso play, because that's just about as good as it gets. So that's the first thing that showed up. John Christmann was in the office this morning and said that he had just signed an AFP to drill nine wells for Penn section in the Wilshire acreage. So that's probably the next interesting thing we'll get started on.

And John Christmann is, for those of you who don't know, is our Regional Vice President in Midland. Pearce Hammond - Simmons & Company International: And then just one housekeeping question on when do you plan to file your 10-K?

On the 28th of February.

Your next question comes from the line of John Malone with Ticonderoga.

Can you guys speak at all as to the status of your pilot program up in New Brunswick? Any new data on those wells?

Well, I'd love to give you some good news, but we're really still trying to figure out what's happened there. I feel like we've got good frac jobs on them, but they're not coming back very quick. We've set up one of the wells to be gas lifted so that we can continue to get the water off of them. I guess we got a number of scientists working on it, and we'll be able to get back to you once we know a little more.

I think like any -- one thing I would say about that whether it's -- we drilled a couple of dusters, or not really dusters, just teasers in Chile. We have 1 million acres in Chile. We have a big acreage position in New Brunswick. And I will tell you, both of them had hydrocarbons in them. We just got to figure out how to, technically, how to get it out of the ground.

And your final question for the day comes from the line of Leo Mariani with RBC Capital.

I want to see if you could kind of break down your $7.5 billion CapEx budget by country in sort of rough terms for us here.

If you go to the website and you look on the supplemental disclosure for the fourth quarter earnings, you'll see a bullet table breakdown of the capital by region.

For 2011.

For 2011 on a budget base.

I guess with respect to the North Sea, you're looking at your realized oil price in the fourth quarter, it's down a fair bit. It was about 11% discount to Brent. The past it was sort of 2%, 3% discount. Anything going on there that we should be concerned about? I mean, you guys still getting pretty close to Brent on your North Sea oil?

Yes. It could be a signing issue that you may be looking at.

Any new results in the Granite Wash that do you guys care to share?

I don't think we have anything new. That continues to be just a great play for us. We continue to push, obviously, looking for the ones that have the highest liquid contents. I've told you in the past about the Hogshooter. Ten of those 40 wells we've drilled this year with Hogshooter. Our market horizontals appeared to be working pretty well, and then we're working the Cleveland actually as well, in horizontal sections up north of there.

And ladies and gentlemen, this does conclude today's Q&A portion of the call. Speakers, do you have any closing remarks?

Thank you, all, very much for your time. For any follow-up questions, I'll be right back in my office. Thank you.

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