APA Corporation (APA) Q1 2010 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Apache Corp. First Quarter 2010 Earnings Conference Call. [Operator Instructions] Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

Thank you. Good afternoon, everyone, and thanks for joining us for the Apache Corp. First Quarter 2010 Earnings Conference Call. On today's call, we'll have four speakers making prepared remarks prior to taking questions. Steve Farris, our Chairman and Chief Executive Officer, will lead off; followed by John Crum, our Co-Chief Operating Officer and President North America; Rod Eichler, our Co-Chief Operating Officer and President International; and Roger Plank, our President. We have again prepared a detailed supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discussed 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 discussion may contain forward-looking estimates and assumptions, and no assurance 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, Tom, and good afternoon, everyone, and thank you for joining us today. Apache took important steps forward during the first quarter on three fronts, operationally, financially and strategically. And I'd first like to go over on the operations front and mention two highlights. Our Van Gogh and Pyrenees oil development projects in Australia have now achieved maximum production ahead of what we forecasted for the year. This is an important step forward in the delivery of the large and visible pipeline of organic growth projects in our international region. In the North America, we ramped up the development of two large resource plays, the Horn River and the Granite Wash. We're going to drill over 60 gross wells this year in these two plays and expect to exit the year with net production of around 175 million a day. The Granite Wash is a liquid rich relative to most other large resource plays in North America, which gives big impact on economics. It's also differentiated by the acreage position we hold because it is primarily held by production. In the Horn River, the quality of the rock and the development efficiencies certainly differentiates it. We can achieve those through large drilling pads on continuous ground acreage. In addition, as we progress our Kitimat LNG project, our goal is to give Horn River access to international LNG markets. These are just a couple of the highlights on the operations side, and Rod and John will go over more on this as we go, which is really shows that organic growth engine is stronger than it's ever been. Going into 2010, we truly expected first quarter to be slow relative to the sequence of being of the quarters and production growth to accelerate from there and that's exactly what you see reflected on our numbers. Production ramped up throughout the quarter with March actual production coming in at 608,000 barrels of oil equivalent a day compared to our average for the quarter of 585,000 barrels a day. And we consider our 5% to 10% organic growth production outlook remains unchanged. Secondly, on the financial front, the highlights really is that we have the best quarter since 2008, both in terms of earnings and cash flow. This has been driven by our portfolio balance, and I can't say enough how important it is for our portfolio to be balanced between oil and gas, and then within gas, to have a good mix of both North American and international gas. Not only it's an important but frankly, at our size, it's pretty much impossible to replicate for companies that did not make that balanced growth choices that we've made over the last several years in getting to this position. And thirdly on the strategic front, we have taken three very important steps so far in 2010. A merger with Mariner Energy, which we announced after the quarter closed, will give Apache a new growth platform in the deepwater. Mariner gives us critical mass, experience and opportunities set that we want in this area and Apache's resources will enhance the value creation potential of this platform. In addition, Mariner gives us a rich opportunity inventory in the Gulf of Mexico Shelf and also in the Permian Basin. The asset fit is excellent. The cultural fit is outstanding. And we're working diligently with Mariner's team to progress the merger and are very much looking forward to welcoming them officially onboard as Apache. Separately, the Devon offshore property transaction gives us yet another high-quality inventory set in the core region, with very attractive returns and frankly, I can't say that we know of anyone that can generate the reserves and value better than we can. The third strategic development that took place during the quarter that Apache became operator is the Kitimat LNG facility in British Columbia, Canada. We've discussed that opportunity with you on our earnings call in February. But I'd note that just like Deepwater, LNG is a big step forward for Apache. It enables us to monetize very large gas resources, at LNG prices, which are generally linked to crude oil prices and gives us a large stable production and cash profile to complement our portfolio. Instead of following the pack, we certainly picked our own timing and direction in taking each of these steps. Looking back, I can reminisce going into Egypt in 1995, going into the North Sea in 2003 and going into Australia in 1993. All were important steps for us. And all of them were very much against the sector consensus at the time but which have created great value for our shareholders. And we're confident that the steps that we've taken in the first quarter will be looked back on in the same vein, and will provide meaningful long-term value for our shareholders. And with that, I'd like to turn it over to John Crum who will discuss North America.

Thank you, Steve. North American production averaged 276,000 barrels a day in the first quarter, down 4% from the fourth quarter 2009. Downtime associated with extreme weather in Canada and third-party held platform and pipeline downtime issues in the Gulf Coast and Central regions were the primary factors. The ramp up of drilling operation, started in the first quarter after very low activity level in 2009, will arrest that drop for the second quarter. The Gulf Coast region production for the first quarter averaged just under 119,000 barrels of oil equivalent per day, down 4% from the fourth quarter of 2009. Production gains of almost 6,000 barrels equivalent were experienced from additional hurricane repairs and resumption of the service of the Sea Robin Pipeline. However, these gains were offset by natural declines and again, the third-party host platform and pipeline issues during the quarter. The first quarter drilling program in the Gulf Coast has given us a nice start for 2010. We drilled 19 gross wells, of which 14 were successful. Four of those successful wells were exploratory and are now in evaluation and developmental planning stages. Two LLOG-operated Mississippi Canyon 199 wells successfully tested two adjacent fault blocks at our Mandy prospect, and penetrated net oil pay of 161 feet and 109 feet respectively at approximately 6,500-foot PVD. We are now evaluating subsea development plans for these wells and would expect production by mid 2011 with initial rates of around 6,000 barrels per day from each well. Apache has working interest of 15% in this field and Mariner Energy has 35% working interest in the discovery. In addition, we were successful with two tests of the N6 M [ph] at our Boomerang Prospect that main pass 308, where we identified 12 feet and 30 feet of net oil pay in the N6 M [ph] in our number one and number one sidetrack wells respectively. Regionally, the N6 M [ph] well is quite prolific with recoveries in the range of 1 million barrels of oil from 10-foot pay sections. We are currently mobilizing a rig to drill in a price of well and mainpass 309 to further delineate the reservoir and confirm our platform location for development plans. Initial rates are expected to be around 800 barrels per day per well, with the support of six wells development. First production would be expected in the first half of 2011. Apache operates this bill with 100% working interest. Other successful drilling of two wells, the Grand Isle 41 and South Pass 75, as well as the new well at High Island 129, and three new wells on to our producers will have additional production volumes for the second quarter. In our Central Region, production averaged 34,600 barrels equivalent per day, down 4% from last quarter. Third-party pipeline downtime and delays in completion of new wells were responsible for the decline. The third-party downtime issues resolved in our backlog of completions being worked off. We expect production to be up by more than 3,000 barrels equivalent in the second quarter. As most of you know, horizontal drilling with multiple stage frac stimulations has really improved the potential of the tight formations we typically target in the country United States. Our Central Region controls roughly 1 million gross acres, most of which is held by production. This has provided us with an excellent platform from which we actively and efficiently explore. We've been testing various geologic targets across the region to identify the most prospective acreage for horizontal application. Since late last year, the region has tested eight separate horizontal pay intervals within 20 wells over hundreds of square miles. More than a dozen more horizontal formation tests are planned this year. As plans are verified, leasing efforts have commenced. In the past year, 36,000 new gross acres have been leased with 16,000 of those acres being leased in the first quarter of 2010. The Central Region spud 23 wells in the first quarter, of which 13 were horizontal. The region's most active program continues to be the Granite Wash in Western Oklahoma and the Texas Panhandle. You're all aware that the Granite Wash is a series of liquid-rich tech gas, which underlies some 4,000 square miles of the Anadarko Basin. We've been active even in the decades and have only recently ramped up horizontal multi-frac operations. We have now drilled eight horizontal wells, five of which have been completed, as well as have already produced 4 bcf gas at 150,000 barrels of oil. The remaining three are now being completed. Meanwhile, we are expanding the drilling campaign and are currently operating six horizontal Granite Wash rigs. A seventh horizontal rig will be added as well as an additional vertical rig in May. At the same time, we have another three rigs targeting other horizontal effects around the region. We are quite enthused about the results of our Cherokee formation activity in Western Oklahoma. For the past several years, Apache has been successful in acquiring acreage and drilling shallow Cherokee formation wells, primarily in Hartford County, Oklahoma, one of the oldest areas of the Anadarko Basin. We drilled over 20 vertical oil wells with initial rates typically averaging 100 barrels per day. On those results, we have recently leased more than 11,000 acres and now control over 60,000 acres in the play. In the first quarter of 2010, we completed our first horizontal path in this play. The Rose Hill for 29H after 150 barrels of oil per day from a 38-foot, 100-foot lateral and has held up quite nicely, still producing over 120 barrels per day after two months. Our second test, the Bentley 5-5H has to drill over 700 barrels a day from the 4,400-foot lateral and is still producing 530 barrels a day after six weeks. The region has identified more than 30 additional horizontal locations in this play and we expect to maintain at least one horizontal drilling rig in the play for the foreseeable future. In East Texas, Apache has been active with two horizontal drilling rigs targeting Bossier Sands since late last year. The region has completed three horizontal tests today. The Folk 6H, that was this year. The Folk 6H tested for 9.2 million cubic feet of gas per day. The Moody T-7H [ph] tested for 9.4 million cubic feet of gas per day. And while the Folk 9H tested for a very strong rate of 15.5 million cubic feet gas per day. The Moody 2-8H is currently testing out their frac, an early indications that it will be the strongest well to date. As of this morning, it's already flowing at more than 15 million cubic feet of gas per day while still recovering frac water at more than 2,000 barrels per day. We're on a 100% of Moody lease in the lease and 77% of the 12 place [ph]. Our new Permian Region is operating independently after the year end spun out from our Central Region. We've been actively recruiting staff from both inside and outside Apache and expect to be fully operational from our newly leased office space in Midland by early July. Permian production averaged 54,000 barrels of oil equivalent within 1% of the prior quarter. We expect production to be up slightly for the second quarter. The Permian region drilling program got off to a fast start as well. We're currently operating five rigs, three in New Mexico and two in Texas. During the first quarter, the region drilled 51 wells targeting oil reservoirs in 11 different fields across Permian Basin. All 51 Wells are either completed and on production or will be completed in the near future. As in the Central Region, application of horizontal well technology is having a significant impact on our plants. Importantly, we drilled two successful horizontal tests in all waterflood units. The Shafterlike [ph] 606-H well was drilled and completed in the San Andres with a fixed-stage frac stimulation and came on production at the initial rate of nearly 500 barrels of oil per day. The North McElroy 4025-H was drilled and completed in the Grayburg with an eight-stage frac stimulation and tested approximately 200 barrels of oil per day. Both wells initial rates and post-drill reserve estimates were higher than pre-drill estimates. Based on this success, follow-up locations are planned in both fields, where we will test longer laterals and more fracture stimulation stages. We're very optimistic about the potential for horizontal drilling throughout the Permian Basin with additional wells planned at TSO South [ph] and Dean units in West Texas, as well as the monument area of southeast new Mexico. We expect to keep at least one horizontal rig working at the remainder of the year. We also expect to add two additional drilling rigs by the end of the second quarter to expand our traditional low risk bread-and-butter vertical oil well programs. During the first quarter, the region also sanctioned Roberts CO2-enhanced recovery expansion and just signed an agreement with Kinder Morgan for the purchase of 38 bcf of CO2 over 10 years. CO2-enhanced recovery will be an important piece to the Permian Region business for a long time given our extensive holdings in the basin. We have already identified 26 of our fields with CO2 enhanced recovery potential. In Canada, Canadian production averaged 68,000 barrels equivalent a day, down 5% from the fourth quarter. As mentioned earlier, extreme weather early in the year caused extensive freeze up across the region and was the primary reason for the drop. We are bringing on production from our winter drilling program and completion operations, which are expected to lead to a 6% increase for the second quarter. The majority of the impact of the Horn River activity will not become evident until the second half of the year. Development drilling and our conventional business units totaled 42 wells resulting in 38 producers during the first quarter, with successful gas completions at Zama, Kaybob and Nevis. Oil drilling activity was focused on House Mountain where six new horizontal wells are producing over 1,100 barrels per day. Also an 18-well winter program in our Provost area has delivered good results including one well that tested over 500 barrels of oil per day at our proposed Battle River EOR [Enhanced Oil Recovery] project area. Our Horn River activity continues to dominate Canadian operations with horizontal wells were drilled in the two island of late developed area during the quarter with four of the Apache operated 52 pan and three on enhanced and can operated 63 tape. In addition come Apache drilled through horizontal Wells in our ability area to hold expiring acreage. Drilling efficiencies that result in cost performance continued to improve with average drill times now at 19 days from the spud rig release and average drill cost at $3.7 million per well for about 7,200-foot of horizontal section. Completion operations on the 16 Wells 70 K-Pad, which was drilled in 2009 commenced in January. We have just finished the amount of frac stimulation project associated with these wells this week. Over the past three and a half months, we have completed 274 frac stimulations on those 16 Wells, accounting more than 500 million barrels of water and an excess of 100 million pounds of sand. The project also involves conducting a huge micro-seismic acquisition program with 82 individual frac stages in over 19,000 individual micro seismic events mapped. This data will be used to optimize frac design, frac spacing and then well spacing on our future pads. The first half 16 70-K came on stream on March 29 to start recovering frac load water, and we're now producing around 25 million a day from that pad. The ramp-up has been severely limited due to the space restrictions while the frac spread remain on location. We are presently demobilizing the frac equipment and would expect to have all 16 wells on production by early July. Construction of the DeBolt water treatment facility ramped up in the first quarter and is expected to be completed in early May. While it is not available for our 70-K Pad program, utilization of this water supply will ultimately reduce the volumes of fresh water used for frac stimulation purposes and the associated costs for water transportation. Steve mentioned the Kitimat operation during the first quarter, we have now received feed proposals from four parties and we're under technical evaluation. We would expect to award fees sometime or the next month and a half, two months. And that's all I have. With that, I'll turn it over to Rob Eichler.

Thank you, John. During the first quarter, production from Apache's international operations was 310,000 barrels of oil equivalent per day, a 2% increase over fourth quarter 2009. The production increase can be attributed to drilling successes in Egypt and successful commission of oil developments in Australia. In Egypt, net production was 151,000 barrels of oil equivalent per day, down 5% from fourth quarter due to higher oil prices and lower recoverable costs resulting in lower cost recovery barrels. By contrast, gross fuel per day increased 3,000 barrels a day or 1% from 300,000 barrels of oil equivalent per day to 303,000 barrels of oil equivalent per day. Exploration activity continued stronger in the quarter with operations being conducted on five free seismic surveys representing nearly 3,000 square kilometers average. Oil activity increased during the quarter with a total of 48 wells, reaching total debt including 10 exploration wells. The region heads for the quarter with 20 after drilling rigs operating and the success rate for Apache-operated exploration wells was 67%. Exploration appraisal drilling was largely focused in our expanding Faghur Basin oil play, where four plays tested in a combined rate of 12,000 barrels of oil per day and 10 billion cubic feet of gas per day from AEB reservoir. 18 well remain to drilled in the basin this year including non-exploration wells. Development of the Phiops field of the east end of Faghur Basin continued with Phiops-8 well, which encountered 124 net feet of pay and multiple AEB sands. The initial completion, AEB 3E sand tested at 4,500 barrels of oil per day and no water. Construction is during completion on the West Kalansha facility project, which will increase the export capacity of our Faghur Basin facilities from the current 11,000 barrels of oil per day to 20,000 barrels per day by midyear. Extension of the Malaha accrual pipeline and completion of the chain of infrastructure upgrades will further produce Apache's Faghur Basin production capacity to 40,000 barrels of oil per day, which we should be able to fill up by year end. Notable drilling results were also achieved in the Jade field discovered by Apache in 2007 on a Matruh development lease. The Jade-8 well was completed in AEB 3E put on production this 10th of March. In its current report, the Salam gas plant at the rate of 3,100 barrels condensate per day and 32 million cubic feet of gas per day. The Jade-10 well is drilled in that quest of Jade structure and tested 3,100 barrels of oil per day with no water from the AEB 3E. Additional field wells are planned in 2010 to accelerate this oil development. To date, the Jade field has produced 47 Bcf and 4.5 million barrels of oil and condensate and presently produces 107 million cubic feet of gas per day and 12,000 barrels of oil and condensate per day. Apache has 100% contract interest for all the previously referenced wells. In Australia, net production was 61,600 barrels of oil equivalent per day, a 40% increase over fourth quarter and double the rate for first quarter of 2009. Gas production increased by 1% from fourth quarter while oil production nearly tripled. The substantial increase in net oil production from 9,900 barrels of oil per day to 27,000 barrels per day was due to successful commissioning of the of Van Gogh and Pyrenees development projects. Their region also benefited from the absence of cyclones in the first quarter compared to three cyclones and storm production eruptions for the same period of 2009. At the Van Gogh oil project, which Apache operates for 52.5% working interest, the Ningaloo Vision FPSO arrived on location and following a five-week commissioning period, the field commenced production on February 13. Well performance has been excellent with oil wells tested above 10,000 barrels of oil per day on Cleo [ph]. Production peaked at 72,200 barrels of oil per day gross in March, and averaged 66,000 barrels of oil per day gross or 34,700 barrels a day net in the last week of the quarter. To date, the field has produced 3.4 million barrels of oil or 1.8 million barrels net. Nearby, BHP Billiton operated Pyrenees FPSO development in which Apache has a 28.6% working interest commenced production February 24. Production ramped up quickly to 90,000 barrels a day gross from the seven WA-42 L permit wells with six wells remain to be completed on the adjacent WA-43 L permit in which Apache has a 31.5% working interest. To date, Pyrenees field has produced 4.4 million barrels of oil gross and 1.3 million barrels net for Apache. These high initial rates for both fields are essentially flush production as we commission the facilities and we expect the region's net oil production to average 40,000 to 50,000 barrels of oil per day for the year. Work is progressing in our Devil Creek Reindeer development project in which Apache is the operator with 55% working interest. Gas plant in both Earthworks were sort of completed in the first quarter and several works commenced. The first shipment of the Thailand fabricated gas plant hyperact modules arrived on site and installation in progress. The onshore pipeline from the beach crossing to the gas plant and the horizontal directional-drilling operations on the beach was started. Fabrication of the Reindeer Wellhead Platform deck is underway in China. The project is on schedule for postproduction in third quarter 2011. Also during the first quarter, four Apache-operated wells reached TD yield in two trend exploration dry holes and two successful appraisal wells on Australia's North Sea shell. The Julimar Southwest 1 and Southwest 2 how much Apache has a 65% working interest were drilled in a single surface location to confirm productivity of the Mungaroo formation in the southern part of the Julimar horse block. Both wells are part of the Julimar-Brunello development component of the Chevron-operated Wheatstone LNG project. In the North Sea, production averaged 58,300 barrels of oil equivalent per day, an increase of 2% for the fourth quarter. 32,000 barrels of oil per day average for the quarter was added to new drilling where we lost 1,800 barrels a day from mechanical failures, unplanned events in normal times. At the end of the quarter, seven development wells and five pilot holes were drilled and completed. Notably, the Forties Alpha 15A 53W [ph] in the Forties Charlie 24 C - 44 Y [ph] development wells tested 3,031 barrels of oil per day, respectively. The field development plan for the mall field, a new field using oil discovery made by Apache in the fourth quarter has been proved by the Department of Energy and Climate Change. First oil expected late in the second quarter of 2010. The field has qualified as a small field development yielding up to 75 million pounds earning a supplement corporation tax breaks as well as exemption from the petroleum revenue tax. In Argentina, net production was 39,000 barrels of oil equivalent per day, down 8% from the fourth quarter. The normal decline as well as mechanical and other related downtime in Neuquén fields pushed oil production down while gas production separate from lower than normal residential seasonal demand and lower demand by power generation customers from increased hydroelectric power capability, availability all result in increased gas, injection and shutting gas wells throughout the first quarter. In total, we reinjected close to 4 million cubic feet of gas per day net more than in the first quarter compared to previous quarter. Regions shallow [ph] program however was very successful in the first quarter, with 10 wells drilled with no dry hole adding net reserves is 2.6 billion barrels of oil equivalent. In the shallow drilling program in the Neuquén Basin three successful wells were drilled at a gross production of 5.3 million cubic feet of gas per day and 335 barrels of oil per day from Centenario and Cuyo reservoirs. All three wells are drilled at depths of only 4,000 feet. An additional 16 Wells are planned for this year. Also the Neuquén Basin, four successful wells are drilled as part of the Gas Plus program. Three wells in EFO field have been completed in the Lajas the depth 11,500 feet and our production can combined rate of 5.9 million cubic feet of gas per day or 108 barrels of currency per day after multizone stimulated completions. If fourth well, the EFO 109, encountered 328 feet of net pay in the Lajas, it is being completed and frac is stimulated in six zones. Those are currently cleaning up after frac of the first three zones at a rate of 3.1 million cubic feet of gas per day. Based on the quality of paying [ph] and the results of the first three zone the EFO 109 is expected to produce over 500 million cubic feet of gas per day and 125 barrels of condensate per day. Eight additional wells are planned in EFO field to develop gas volumes for the Gas Plus contracts that is currently being negotiated to provide 15 million cubic feet of gas per day at a price of $5 per million BTU on January 1, 2011. 10 additional wells in AC and Ronaco fields will also be drilled this year to support the Gas Plus program. Apache operates the reference Neuquén Basin wells and fields with 100% working interest. Now let's turn the presentation over to Roger Plank for the finance.

Thanks, Rod. Good afternoon, everyone. I'm going to finish up with a few quick notes from a financial perspective. Apache turned in a standout first quarter setting, the stage for what is the makings of a truly exceptional year. Earnings of $705 million or $2.08 per share were 21% higher than the prior quarter and our highest since third quarter of '08. Adjusted for the impact of FX on our deferred tax balances, earnings totaled $712 million or $2.10 a share. Cash flow from operations for us $1.5 billion also for the first time since third quarter of '08. Apache's substantial oil and liquid production base was the primary driver behind our results. Highland liquids represented half of our equivalent production but generated nearly 3/4 of revenue, and are principally responsible for our revenue rising $118 million sequentially to $2.7 billion. Long before the current industries stampede began oil exposure, Apache took deliberate steps to achieve a balanced production mix. As a result, we're already benefiting from a current 20 to 1 multiple in the price of oil versus gas. And we are ramping up activity on the oil side of our portfolio. In the first quarter, for example, Van Gogh and Pyrenees enabled Apache's lower production to rise 3% sequentially, nearly offsetting a 4% temporary decline in gas production. I would note that absent the impact of higher prices had on both price-sensitive volumes in Egypt and to a lesser extent in Canada, on a production volumes, would've been up slightly and pretty much spot on our first quarter plan. A few quick comments on costs, cash costs excluding taxes other than income, came in at $11.89 per barrel of oil equivalent, impacted by slightly lower production. Rising future productions should drive us toward our goals to match 2009's average of $11.25 per boe. You're maybe wondering about the potential impact of our recently announced transactions on 2010. Because it so much depends on exactly when the transactions closed. The precise impact is difficult to measure but here's some broad indicators. Absent the exercise of preferential purchase rate, which covers some 7,500 barrels equivalent per day, Apache is picking up 19,000 barrels equivalent per day from Devon and another 63,000 with Mariner. A combined 82,000 equivalent barrels per day represents 14% of Apache's first quarter worldwide production. With respect to the financial 2010 impact, assuming Devin closes in early June and Mariner late in the third quarter, 2010 average volumes should rise around 25,000 barrels of oil equivalent per day or 4% to 5% from these transactions alone. Now this is over and above our earlier production growth target of 5% to 10% growth pre-acquisitions. I would note that for the last couple of years, Apache chose to build cash rather than pursue transactions of size in what was generally considered a profiting market. Net cash was in fact pent-up growth potential that is now being put to work and will benefit all key per share metrics over the next several years. While we potentially took up 14% more production, share count rises just 5%, resulting in accretion to per-share earnings, cash flow, production and reserves in the first full year of ownership. The bottom line is our outlook for growth is excellent. I would also note that in our two recent deals, about 60% of combined production is gas. Approximately 60% of the revenue is generated from oil and liquids. There's also a deep inventory of future development projects as well as exploration prospects that are oil. One final note on our balance sheet, while the combined transactions totaled $5 billion, our financial flexibility remains intact. Approximately $2 billion at consideration is equity and we will also tap a significant portion of our $2.1 billion of cash balances to close these deals. By year-end, debt cash should be below 25% and cash balances above $1 billion, leaving us in excellent position to continue to carry out Apache's growth strategy. Steve?

Thank you, Roger. I'd like to sum up what I think were the three main messages from all the information that we shared with you on this call. First, we had a very good quarter operationally. As you heard mentioned few times Van Gogh and Pyrenees have ramped up. Our organic growth engine as strong as ever and our organic growth production's expectations for the year remain at 5% to 10%. Secondly, we have had a very good quarter from a financial perspective, with the highest earnings and cash flow since 2008. We achieved this in spite of a weak price environment from North American gas and it's because of our portfolio, which is really a central part of our strategy and a key differentiating factor for most of our peers. And third, we certainly took very important strategic steps during the quarter. You got further omissions that are a little, profitable long-term growth our shareholders. We picked our own timing and direction. And we're very excited about the growth and value creation potential by the Mariner merger, the Devon offshore acquisition and our Kitimat LNG project. And with that, we're ready to take your questions.

[Operator Instructions] And our first question today comes from Philip Dodge with Tuohy Brothers Investment Research. Philip Dodge: On the Horn River, you mentioned some metrics growth that are rig release average cost per oil. I didn't hear fracturing stages or EURs but you said you a lot of the cash but I didn't hear?

No, I probably -- I didn't give you the map on it. We did 274 fracs on 16 wells, so that comes up to just over 17 fracs per well. We did as many as 22 stages on individual wells. And the length of the horizontals that we're typically targeting now are somewhere in the range of 2,200 meters or 7,200 feet. Philip Dodge: Anything on EURs as you see is the most recently in decline rates?

We're still early to tell you anything about the decline rates here because we're still unloading water. We couldn't really bring these things on. We're just flowing through test separator equipment on location. We've got -- we're still running with a number that we believe we're going to be able to drain an excess of 10 bcf per well on all of these.

Your second question today comes from Leo Mariani with RBC Capital.

Just a quick follow up on the Horn River here, I think you guys give a well cost there, but I don't think I heard it right? What was your average well cost up there now?

We just gave you the drilling costs, Leo. The drilling costs were now at $3.7 million per well but that's on considerably extended lateral length to. You've heard me talk and pass about spending $10 million per well. We averaged around $11 million per well in this program. We were not able to get our new water plant on production in time to do these wells and that's why I believe it will add another million to our total costs. The real key here and I mentioned over tons of paper for here is we continued to that stages as we go forward and of course instead of using up some of our ability to reduce the costs.

You talked about experimenting with the horizontals in the Permian Basin here. Just trying to get a sense of how long you guys been doing that? And how much your acreage do you think is prospective and what types of improvements are you seeing and economics versus critical drilling for this play.

I'd say we really just getting started in the Permian Basin. There a number of players who have been doing some horizontal drilling certainly in the Southeast, New Mexico and in far West Texas for the past year, year and a half. And we really good guy getting started. These two wells I talked about were especially important because for drilling needs to wield of water that you do so that to get those kinds of results and those kind of reservoirs is pretty impressive. We would've expected to have so much water coming back in a typical well there that will create some new problems for us but that's going to lead us to try a lot of different things across the nation over the rest of this year.

Any further estimates as opposed to how much of benefit you're seeing here? Do you think you're getting to through funds back for the boss and verticals in some of these fields or?

Well again, a little early on, I only got two of them completed. We would be getting more than twice as much from these wells if our estimates hold up.

You guys also talked a little bit about East Texas doing some closure wells, some kind of a hot topic in the industry layaway. So the serious how much acreage this you think this is expected other.

We have a fairly modest position in these assets where we continue in that in areas that we're comfortable with. So again that's not our hottest area but we're getting pretty worked up about it because we got some great results out of our recent programs and knowledge and hope.

It sounds like you got five completion spirit you talked about some kids with all five wells took any kind of sense of kind of what these average rates are on these wells when you drill.

I have to give you average rates but I would say we we're averaging somewhere around $10 million.

And we'll go next to Judy Delgado with Alpine Associates.

Wanted to know whether companies have that the situation going on in the Gulf of Mexico and the newly announced administration's plans to be a little more stringent in their efforts to help. Do you have any thoughts on that?

I think it's tragic that we have the loss of lives in the Gulf and I think its a little early to try to figure out what the problem was. Certainly, it's going to be an area of a lot of attention and I hope we come up with something that is workable and safe and environmentally friendly.

Is the company experiencing any shutdowns now? Are you planning for any shutdowns in the future?

Well we don't have any shutdowns right now and it's going to depend on the direction that I assume you are speaking to this scale it's up for direction, we're not in danger to those amounts any of the spills reaching any of our existing production facilities. That's a wait-and-see.

And we'll go next to Brian Singer with Goldman Sachs.

I want to see if you can touch on that more on the cost inflation or lack of it as you go through your major areas and maybe on short-term site in terms of is some be on shore drilling and completion activities and also anything your seeing on the steel pricing processing when you think about the costs of LNG extensions in Australia and in Canada?

I'll let John talk about North America and then I might talk a little bit about overall what we're seeing on costs. I would start off from a generalization. I think personally, I think it's premature to extrapolate cost increases that we've seen in the first quarter throughout the year. Winter is difficult for us in Canada and unfortunately, it's difficult for us in the central region because we've got one of the more severe freezes that we've had through that part of our portfolio in the first quarter. So a lot of costs with respect to activities to start production again is part of those costs and the other thing is to be honest with you, our production was down a little bit and one of the major culprits was because we are in a CS3 a production sharing agreement in Egypt and the bedside of is all prices go up come in the downside of it is we see less production which cost us about 5000 barrels a day in Egypt. And gross operated was actually up. But overall, I don't think the cost side of it is going to get out of line. On the steel prices, that's certainly going to have an impact and I'm sure everyone's over the steel prices are going up. And we'll just have too wait and see what the impact of it is on those budget.

I don on that steel costs, I guess I'd like to think there's a positive tied to that but all in only indicates increased demand so hopefully, we can get some strength in prices to support some of that activity but obviously, that's something we do have to watch break also because it has a big impact on virtually all of our business.

On the Granite Wash going forward basis, for the next batch of gross, what are your expectations for percent gas versus percent NDLs versus?

I have to do the math call Brian. Can I just call you back would that?

Are you concentrating more on the Atoka relative to some of the where the oil comes on?

We're concentrating on higher liquid yields as we at testing a lot of different zones year but obviously, we're looking at the highest liquid yields the hardest.

And we'll go next to Doug Leggett with Bank of America.

Can you give us any better feel for where your CapEx may go this year, partly obviously the increase but also when you take a cut of the additional assets are going to have in the portfolio? Any guidance would be appreciated.

Could you first about that way maybe?

Your capital expenditure guidance for the current year, how is that likely to change going how do you expect your capital expenditure to trend over the balance of this year and can you give a details?

In terms of our overall capital budget, we've indicated before dividend, before the Mariner acquisition or merger, that we would be a little north of $6 million. And I think what you're going to see is from an activity level, our acquisition forecast for Devon, we had about $100 million of capital we're 10. Depending on what kind of opportunities we see them increase but we can generate about $285 million worth of cash out of that acquisition. With respect to Mariner, they have probably won't close that until September issue or later. They have a capital budget of about $550 million internally, which they're going to spend. So from our standpoint, which you'll see out of Apache, is not a significant increase from the acquisitions. Now depending on what prices do, reallocate capital quarters and we put a few more rigs to work starting in the second quarter than we've had running so you might see a little upward movement on our overall capital program.

So in materials.

Not in the present time to.

It that could jump over to Egypt, can you give us some sense as to how you see your production play through the balance of this year? Obviously call there's a lot of moving parts but it all pretty it was we're right now, how would the trajectory play out as you move through 2010?

Gross production gross gas production will soon about of the year because we are facilities limited with existing gas processing facilities although if you remedy debt by 2012 with additional pipeline construction. On the oil side combines to pay the continued growth in the quarter to quarter because we can't handle more oil as you so we have substantial interest forecast oil on gross oil beginning later this quarter from our opposite is project and by year end, we expect that to double again.

And from the price standpoint, if we stay static, that's where we're today. I think our March numbers were about 9,000 barrels per day net so when we broke for gross the number you saw average for March, you're going to grow from there.

Typically you guys tend to spend your cash flow just on a regional basis. I'm trying to think where that capital expenditure program in Egypt can take you if I heard you correctly, it sounded like you're going to drill about 19 exploration wells. I thought you were going to go this year if you could just give us.

That's 19 exploration wells in the area. The total exploration was about 33 wells.

[Operator Instructions] And our next question comes from Eric Marzucco with Dominick and Dominick.

As far as what you commented before about the recent developments in the Gulf having no frac on the deal comedy think it will affect timing any way, shape, or form?

Now, I wouldn't expect it to. I have no reason to believe that we'd expect it to.

That changes nothing as far as commitment common desire commenting on your end I assume?

No, none, whatsoever.

And our next question comes from Brian Lively with Tudor, Pickering, Holt.

In the Permian Basin, your horizontal drilling is pretty interesting but I was just interested in sort of a concept of approaching old water flood units with horizontal wells. The cost of their try to find lower permeable decisions that have been swept, or verticals or is there something else to it?

That's the primary answer. A lot of those reservoirs out there even under secondary recovery somewhere in the range of 35% to 40% so that's you're exactly right. That's what we're trying to get done has access reserves have never been touched.

We have a huge position with respect to specially water flows and the PUCO twos is done more that we have 26 different projects that we're looking at for CO2 so it's really at the present time, it's a somewhat of an experiment but if it works, you have a tremendous acreage position and full water potential to really ramp up production.

Switching gears to Australia, Pyrenees and Van Gogh, what are your volume limitations? I'm interested in as an oil volume water to total fluids and is there any upside as perhaps the water cut is lower than you expect?

There's a specific limitation on both the vessels, the thirties vessels come of the larger than what we have at Van Gogh. I think we're capped out at about, the Van Gogh little over about 65,000 barrels of oil per day capability. I forgot the number over 30 some it's a 100,000 barrels of oil per day is their capacity. In the second part of your question was what?

I was really just looking forward from the standpoint of total fluid handling versus oil volumes, I think you answered it.

It also has of a water and to date, we've seen no water in the first two months of production, which is really good news.

And we have no more questions at this time.

Okay, thank you. For other questions, I'll be in my office after the call.

This concludes today's call. We thank you for your participation.