Filed by Apache Corporation
Pursuant to Rule 425 of the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Mariner Energy, Inc.
Commission File No. 1-32747


Additional Information
     This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. Apache will file with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that will include a proxy statement of Mariner that also constitutes a prospectus of Apache. A definitive proxy statement/prospectus will be mailed to stockholders of Mariner. Apache and Mariner also plan to file other documents with the SEC regarding the proposed transaction. INVESTORS AND SECURITY HOLDERS OF MARINER ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND OTHER DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Such documents are not currently available. Investors and security holders will be able to obtain the documents (when available) free of charge at the SEC’s web site, www.sec.gov. Copies of the documents filed with the SEC by Apache will be available free of charge on Apache’s website at www.apachecorp.com under the tab “Investors” or by contacting Apache’s Investor Relations Department at 713-296-6000. Copies of the documents filed with the SEC by Mariner will be available free of charge on Mariner’s website at www.mariner-energy.com under the tab “Investor Information” or by contacting Mariner’s Investor Relations Department at 713-954-5558. You may also read and copy any reports, statements and other information filed with the SEC at the SEC public reference room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) 732-0330 or visit the SEC’s website for further information on its public reference room.
     Apache, Mariner, their respective directors and executive officers and other persons may be deemed, under SEC rules, to be participants in the solicitation of proxies from stockholders of Mariner in connection with the proposed transaction. Information regarding Apache’s directors and officers can be found in its proxy statement filed with the SEC on March 31, 2010 and information regarding Mariner’s directors and officers can be found in its proxy statement filed with the SEC on April 1, 2010. Additional information regarding the participants in the proxy solicitation and a description of their direct and indirect interests in the transaction, by security holdings or otherwise, will be contained in the proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.
Forward-Looking Statements
     Statements in this document include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The opinions, forecasts, projections, future plans or other statements other than statements of historical fact, are forward-looking statements. We can give no assurance that such expectations will prove to have been correct. Actual results could differ materially as a result of a variety of risks and uncertainties, including: the timing to consummate the proposed agreement; the risk that a condition to closing of the proposed agreement may not be satisfied; the risk that a regulatory approval that may be required for the proposed agreement is not obtained or is obtained subject to conditions that are not anticipated; negative effects from the pendency of the merger; our ability to achieve the synergies and value creation contemplated by the proposed agreement; our ability to promptly and effectively integrate the merged businesses; and the diversion of management time on agreement-related issues. Other factors that could materially affect actual results are discussed in Apache’s and Mariner’s most recent Forms 10-K as well as each company’s other filings with the SEC available at the SEC’s website at www.sec.gov. Actual results may differ materially from those expected, estimated or projected. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to publicly update or revise any of them in light of new information, future events or otherwise.


     First Quarter 2010 Earnings Release
Earnings Release
1st Quarter 2010 Earnings Release
     MODERATOR: Good day, everyone, and welcome to the Apache Corporation 1st Quarter 2010 Earnings Conference Call. This call is being recorded. Today’s presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.
Tom Chambers, V. P. Corporate Planning, Investor Relations
Thank you. Good afternoon, everyone and thanks for joining us for the Apache Corporation 1st 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’ve 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 cost 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.
Steve Farris, Chairman, Chief Executive Officer
Thank you, Tom and good afternoon everyone and thank you for joining us today. Apache took important steps forward during the 1st 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 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 a large and visible pipeline of organic growth projects in our international regions. In our 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
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with net production of around 175 million a day. Granite Wash is a liquid rich relative to most other large resource plays in North America, which gives big impact on the 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 efficiency 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 operation side and Rod and John will go over more of them as we go, which is really shows the organic growth engine is stronger than its ever been.
Going into 2010, we truly expected 1st quarter to be slow, relative to the sequencing of the quarters and production growth to accelerate from there and that’s exactly what you see reflected in 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. We consider our 5 to 10 percent organic growth production outlook remains unchanged. Secondly, on the financial front, the highlight really is that we had the best quarter since 2008, both in terms of earnings and cash flow. It’s 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 is it 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.
    The 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 opportunity set 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
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     First Quarter 2010 Earnings Release
      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 Apaches.
    Separately, the Devon offshore property transaction gives us yet another high quality inventory set in a 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 quarters at Apache became operator at the Kitimat LNG facility in British Columbia, Canada. We 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 flow 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 to 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 ‘em 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 1st 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.
John Crum, Co-Chief Operating Officer/President, North America
Thank you, Steve. North American production averaged 276,000 BOE in the 1st quarter down 4 percent from the 4th quarter 2009. Downtime associated with extreme weather in Canada and third-party host platform and pipeline downtime issues in the Gulf Coast and Central regions were the primary factors. The ramp up of drilling operations started in
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     First Quarter 2010 Earnings Release
the 1st quarter after a very low activity level in 2009 will arrest that drop for the 2nd quarter.
The Gulf Coast region production for the 1st quarter averaged just under 119,000 BOED, down 4 percent from the fourth quarter of 2009. Production gains of almost 6,000 BOED equivalent were experienced from additional hurricane repairs and resumption of 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 1st 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 pays of 161’ and 109’, respectively, at approximately 6500’ TVD. We are now evaluating subsea development plans for these wells and would expect production by mid-2011 with initial rates of around 6,000 BOPD from each well. Apache has a working interest of 15 percent in this field and Mariner Energy has 35 percent working interest in the discovery.
In addition, we were successful with two tests of the “N6” at our Boomerang prospect at Main Pass 308, where we identified 12’ and 30’ of net oil pay in the “N6” sand at our #1 and #1ST wells, respectively. Regionally, the “N6” well was quite prolific with recoveries in the range of 1 million barrels of oil from 10’ pay sections. We are currently mobilizing a rig to drill an appraisal well in Main Pass 309 to further delineate the reservoir and confirm our platform location for development plans. Initial rates are expected to be around 800 BOPD per well with a support of six well development. First production would be expected in the first half of 2011. Apache operates this field with 100 percent working interest.
Another successful drilling of two wells at Grand Isle 41 and South Pass 75, as well as a new well at High Island 129 and three new onshore producers will add additional production volumes for the second quarter.
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     First Quarter 2010 Earnings Release
In our Central Region, production averaged 34,600 barrels equivalent per day down 4 percent from the last quarter. Third party pipeline downtime and delays in completion of new wells were responsible for the decline. With the third party downtime issues resolved and our backlog of completions being worked off, we expect production to be up by more than 3,000 barrel 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 central United States. Our Central Region controls roughly one 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 plays 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 are all aware that the Granite Wash is a series of liquid rich stacked gas pay sands which underlay some 4,000 square miles of the Anadarko Basin. We’ve been active in the play for decades but have only recently ramped up horizontal multi-frac operations. We have now drilled 8 horizontal wells, 5 of which have been completed. Those wells have already produced 4 BCF of gas and 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 objectives 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 Harper County, Oklahoma, one of the oldest areas of the Anadarko Basin. We drilled over 20 vertical oil wells with
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     First Quarter 2010 Earnings Release
initial rates typically averaging 100 BOPD. On those results, we have recently leased more than 11,000 acres and now control over 60,000 acres in the play. In the 1st quarter of 2010, we completed our first horizontal test in this play. The Rose Hill 4-29H tested 150 BOPD from a 3800 foot lateral and has held up quite nicely, still producing over 120 BOPD after two months. Our second test, the Bentley 5-5H, tested just over 700 BOPD from a 4400 foot lateral and is still producing 530 BOPD 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’s been active with two horizontal drilling rigs targeting the Bossier sands since late last year. The region has completed three horizontal tests to date. The Folk 6H — that was this year — the Folk 6H tested for 9.2 million cubic feet of gas per day. The Moody 2-7H tested for 9.4 million cubic feet of gas per day, while the Folk 9H tested for a very strong rate of 15.5 million cubic feet of gas per day. The Moody 2-8H is currently testing after frac and earlier indications are that it will be the strongest well to date. As of this morning, it was already flowing at more than 15 MMCFD while still recovering frac water at more than 2,000 barrels per day. We own 100 percent of the Moody lease and 77 percent of the Folk lease.
Our new Permian Region is operating independently after the year-end spin 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 percent 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 are 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 the Permian Basin. All 51 wells are either completed and on production or will be completed in the near future.
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     First Quarter 2010 Earnings Release
As in the Central region, application of horizontal well technology is having a significant impact on our plans. Importantly, we drilled two successful horizontal tests in old water flood units. The Shafter Lake 606H well was drilled and completed in the San Andres with a six-stage frac stimulation and came on production at an initial rate of nearly 500 BOPD. The North McElroy 4025H was drilled and completed in the Grayburg with an eight-stage fracture stimulation and tested approximately 200 barrels per day. Both wells initial rates and post drill reserve estimates were higher than pre-drill estimates. Based on the 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 TXL South 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 the remainder of the year. We also expect to add two additional drilling rigs by the end of the 2nd quarter to expand our traditional low risk bread and butter Vertical Oil Well Programs.
During the first quarter, the region also sanctioned Roberts Unit 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 of 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 BOED, down 5 percent from the 4th quarter. As mentioned earlier, extreme weather early in the year caused extensive freeze-ups 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 percent increase for the 2nd quarter. The majority of the impact from the Horn River activity will not become evident until the second half of the year.
Development drilling in our conventional business units totaled 42 wells resulting in 38 producers during the 1st 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 1100 BOPD. Also, an 18-well winter program in our Provost
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     First Quarter 2010 Earnings Release
area has delivered good results including one well that tested over 500 BOPD at our proposed Battle River EOR project area.
Our Horn River activity continues to dominate Canadian operations. Seven horizontal wells were drilled in the Two Island Lake development area during the quarter with four on the Apache operated 52-L pad and three on the EnCana operated 63-K pad. In addition, Apache drilled three horizontal wells in our Dilly area to hold expiring acreage. Drilling efficiencies and resulting costs performances continue to improve with average drill times now at 19 days from spud to rig release, an average drill costs at 3.7 million per well for a 7200-foot horizontal section.
Completion operations on the 16 well 70-K pad which was drilled in 2009, commenced in January. We have just finished the mammoth frac stimulation project associated with these wells this week. Over the past 3 1/2 months, we have completed 274 frac stimulations on those 16 wells pumping more than 5 million barrels of water and in excess of 100 million pounds of sand. The project also involved conducting a huge micro-seismic acquisition program with 82 individual frac stages and over 19,000 individual micro-seismic events mapped. This data will be used to optimize frac design, frac spacing, and inter-well spacing on our future pads.
The first of 16, 70-K wells came onstream on March 29th to start recovering frac load water, and we are 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 remained on location. We are presently de-mobilizing 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 1st quarter and is expected to be completed in early May. While it was not available for our 70K 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 1st quarter, we have now received feed proposals from four parties and we’re under technical evaluation. We would expect to
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     First Quarter 2010 Earnings Release
award feed sometime in the next month and a-half, two months. And that’s all I have. With that, I’ll turn it over to Rod Eichler.
Rod Eichler, Co-Chief Operating Officer and President International
Thank you, John. During the first quarter, production from Apache’s international operations was 310,000 BOEPD, a 2 percent increase over 4th quarter 2009. The production increase can be attributed to drilling success in Egypt and successful commissioning of oil developments in Australia.
In Egypt, net production was 151,000 BOEPD, down 5 percent from 4th quarter due to higher oil prices and lower recoverable costs resulting in lower cost recovery barrels. By contrast, gross BOEPD increased 3,000 BOEPD or 1 percent from 300,000 BOEPD to 303,000 BOEPD.
Exploration activity continued stronger in the quarter with operations being conducted on five 3D seismic surveys representing nearly 3,000 square kilometers of coverage. Drilling activity increase during the quarter, with a total of 48 wells reaching total depth including 10 exploration wells. The region exited the quarter with 20 active drilling rigs operating and the success rate for Apache-operated exploration wells was 67 percent.
Exploration and appraisal drilling was largely focused in our expanding Faghur Basin oil play where four wells tested at a combined rate of 12,000 BOPD and 10 MMCFGD from AEB and SAFA reservoirs. Eighteen wells remain to be drilled in the Basin this year including nine exploration wells.
Development of the Phiops field at the east end of the Faghur Basin continued with the Phiops-8 well, which encountered 124 net feet of pay in multiple AEB sands. The initial completion in the AEB-3E sand tested at 4500 BOPD with no water.
Construction is nearing completion on the West Kalabsha facilities project, which will increase the export capacity of our Faghur Basin facilities from the current 11,000 BOPD to 20,000 BOPD by mid-year. Expansion of the Meleiha crude oil pipeline and completion of a chain of infrastructure upgrades will further boost Apache’s Faghur
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     First Quarter 2010 Earnings Release
Basin production capacity to 40,000 BOPD, 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 the Matruh Development Lease. The Jade-08 well was completed in the AEB-3G sand, put on production the 10th of March, and is currently flowing to the Salam gas plant at a rate of 3,100 BCPD and 32 MMCFGPD. The Jade-10 well was drilled on the crest of the Jade structure and tested 3100 BOPD 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 MMBO&C and presently produces 107 MMCFGD and 12,000 BO&CPD. Apache has a 100 percent contractor interest in all of the previously referenced wells.
In Australia, net production was 61,600 BOEPD, a 40 percent increase over 4th quarter and double the rate for 1st quarter of 2009. Gas production increased by 1 percent from 4th quarter while oil production nearly tripled. The substantial increase in net oil production from 9900 BOPD to 27,000 BOPD was due to the successful commissioning of the Van Gogh and Pyrenees’ development projects. The Region also benefited from the absence of cyclones in the 1st quarter, compared to three cyclone and storm production interruptions in the same period of 2009.
At the Van Gogh oil project, which Apache operates with 52 1/2 percent working interest, the Ningaloo Vision FPSO arrived on location and following a five-week commissioning period, the field commenced production on February 13th. Well performance has been excellent with all wells testing above 10,000 BOPD on clean-up. Production peaked at 72,200 BOPD gross in March and averaged 66,000 BOPD gross or 34,700 BOPD net in the last week of the quarter. To date, the field has produced 3.4 MMBO or 1.8 MMBO net.
The nearby BHP Billiton-operated Pyrenees FPSO development in which Apache has a 28.6 percent working interest commenced production February 24th. Production ramped up quickly to 90,000 BOPD gross from the seven WA-42L permit wells with six wells remaining to be completed on the adjacent WA-43L permit in which Apache has a 31.5 percent working interest. To date, the Pyrenees’ field has produced 4.4 MMBO gross,
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     First Quarter 2010 Earnings Release
1.3 MMBO net to Apache. These high initial rates for both fields are essentially flush production as we commission the facilities and we expect the regions’ net oil production to average 40, to 50,000 BOPD for the year.
Work is progressing at our Devil Creek-Reindeer development project in which Apache is the operator with a 55 percent working interest. Gas Plant bulk earthworks were essentially completed in the 1st quarter and civil works commenced. The first shipment of the Thailand-fabricated Gas Plant pipe-rack modules arrived on site and installation is in progress. The onshore pipeline from the beach crossing to the Gas Plant and the horizontal directional drilling operations under the beach were started. Fabrication of the Reindeer wellhead platform deck is underway in China. The project is on schedule for first production in 3rd quarter 2011.
Also during the 1st quarter, four Apache-operated wells reached TD yielding two trend exploration dry holes and two successful appraisal wells on Australia’s Northwestern Shelf: The Julimar-SW1 and SW2 in which Apache has a 65 percent working interest, were drilled from a single surface location to confirm productivity a the Mungaroo formation in the southern part of the Julimar horst 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 BOEPD, an increase of 2 percent over 4th quarter. 3200 BOEPD average for the quarter was added from new drilling but we lost 1800 BOEPD from mechanical failures, unplanned events, and normal declines. At the end of the quarter, seven development wells and five pilot holes were drilled or completed. Notably, the FA 15-A53W and the FC 24-C44Y development wells tested 3,000 and 3100 BOPD, respectively.
The Field Development Plan for the Maule field, a new field, Eocene oil discovery made by Apache in 4th quarter has been approved by the Department of Energy and Climate Change. First oil is expected late in the 2nd quarter of 2010. The field has qualified as a ‘small field development’ yielding up to 75 million pounds Sterling of supplemental corporation tax breaks as well as exemption from the Petroleum Revenue Tax.
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     First Quarter 2010 Earnings Release
In Argentina, net production was 39,000 BOEPD, down 8 percent from the 4th quarter. Normal decline as well as mechanical and other related down time in the Neuquen fields pushed oil production down while gas production suffered fro lower than normal residential seasonal demand and lower demand by power generation customers from increased hydroelectric power capability and yield ability, all resulted in increased gas re-injection and shutting gas wells throughout the 1st quarter. In total, we reinjected close to 4 MMCFGD net, more than the 1st quarter compared to previous quarter. Regions drilling program, however was very successful in the 1st quarter with 10 wells drilled with no dry holes adding net reserves to 2.6 MMBOE.
In the Shallow Drilling Program of the Neuquen Basin, three successful wells were drilled that added gross production of 5.3 MMCFGD and 335 BOPD from Centenario area and Cuyo reservoirs. All three wells were drilled to a depth of only 4,000’. An additional 16 wells are planned for this year.
Also, the Neuquen Basin, four successful wells were drilled as part of the “Gas Plus” program. Three wells in the EFO field have been completed in the Lajas at a depth of 11,500’ and are in production at a combined rate of 5.9 MMCFGD and 180 BCPD after multi-zoned, fracture-stimulated completions. A fourth well, the EFO-109, encountered 328’ of net pay in the Lajas and is being completed and fracture stimulated in six zones. The well is currently cleaning up after frac of the first three zones at a rate of 3.1 MMCFGD. Based on the quality of pay encountered and the results of the first three zones, the EFO-109 is expected to initially produce over 5 MMCFGD and 125 BCPD.
Eight additional wells are planned in the EFO Field to develop gas volumes for the Gas Plus contract that is currently being negotiated to provide 50 MMCFGD at a price of $5.00/MMBTU on January 1, 2011. Ten additional wells in the AC and Guanaco Fields will also be drilled this year to support the Gas Plus Program. Apache operates the referenced Neuquen Basin wells and fields with 100 percent working interest.
I would now like to turn the presentation over to Roger Plank who will review finance.
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     First Quarter 2010 Earnings Release
Roger Plank, President
From a financial perspective, Apache turned in a stand-up 1st quarter setting the stage for what is the makings to be a truly exceptional year. Earnings of $705 million or $2.08 per share are 21 percent higher than the prior quarter and are highest since 3rd quarter of ’08. Adjusted for the impact of FX in our deferred tax balances earnings totaled $712 million or $2.10 a share. Cash flow from operations crossed $1.5 billion also for the first time since the 3rd quarter of ’08. Apache’s substantial oil and liquids production base was the primary driver behind our results. Oil and liquids represented half of our equivalent production which generated nearly three quarters of revenue and were principally responsible for our revenue rising $118 million sequentially to $2.7 billion. Long before the current industry stampede to gain oil exposure, Apache took deliberate steps to achieve a balanced production mix. As a result, we’re already benefiting from the 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 1st quarter, for example, Van Gogh and Pyrenees enabled Apache’s oil production to rise 3 percent sequentially nearly an offsetting of 4 percent temporary decline in gas production. I would note that absent the impact that higher prices had on price sensitive volumes in Egypt and to a lesser extent Canada, production volumes would have been up slightly and pretty much “spot on” our 1st 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 production should drive us toward our goal to match 2009’s average of $11.25 per BOE. You may be wondering about the potential impact of our recently announced transactions on 2010. Because 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 rights which covers some 7500 barrels equivalent per day, Apache is picking up 19,000 barrels equivalent per day from Devon and another 63,000 with Mariner. The combined 82,000 equivalent barrels per day represents 14 percent of Apache’s 1st quarter worldwide production. With respect to potential 2010 impacts, assuming Devon closes in early June and Mariner late in the 3rd quarter, 2010 average volume should rise around 25,000 barrels of oil equivalent per day or 4 to 5 percent from these transactions alone. Now, this is over and above our earlier production growth target of 5 to 10 percent growth pre-acquisition.
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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 frothy market. That cash was in effect “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 pick up 14 percent more production, share count rises just 5 percent 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, while 60 percent of the combined production is gas, approximately 60 percent of the revenue is generated from oil and liquids. There is 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 total $5 billion, our financial flexibility remains intact. Approximately, $2 billion of 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/cap should be below 25 percent and cash balances above $1 billion, leaving us in excellent position to continue to carry out Apache’s growth strategy. Steve?
While the combined transactions total $5 billion, our financial flexibility remains intact. Approximately, $2 billion of 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/cap should be below 25 percent and cash balances above $1 billion, leaving us in excellent position to continue to carry out Apache’s growth strategy. Steve?
Closing Remarks (Chairman)
Thank you, Roger. I’d like to sum up what I think are 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 a few times, Van Gogh and Pyrenees are ramped up and our organic growth engine is strong as ever and our organic production growth expectations for the year remain at 5 to 10 percent. Secondly, we had a very good quarter from a financial perspective with the highest earnings in 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 simple part of our strategy and a key differentiating factor for most of our peers. And, third, we certainly took very important
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strategic steps during the quarter that furthered our mission to deliver consistent profitable long-term growth for our shareholders. We picked our own timing and direction and were 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.
Question/Answer Session
O:    Please press star 1 on your touch tone phone to ask a question. Make sure your mute button is disengaged to allow your signal to reach our equipment. And our first question today comes from Phillip Dodge (phonetic) with Tuohy Brothers Investment Research.
Q:    Just to be clear, on the Horn River, you’ve mentioned some metrics drilled to release — rig release, average cost per well, length of lateral. I didn’t hear fracturing stages or EURs. But you said it and I look it up in the transfer, but I didn’t hear it.
A:    No, I probably didn’t. I didn’t give you the math on it. We did 274 fracs on 16 wells. So, that comes out 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 2200 meters or 7200 feet.
Q:     Yep, which I had. And anything on EURs as you see it most recently in decline rates?
A:    Yeah, we’re — it’s a little early to tell anything about the decline rates here because we’re just 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 in excess of 10 BCF per well on all of these.
Q:     Yeah, so no change there. Okay. Thanks very much.
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     First Quarter 2010 Earnings Release
O:     And our second question today comes from Leo Mariani (phonetic) with RBC Capital (phonetic).
Q:     Hey, guys. Just a quick follow-up on the Horn River here. I think you guys gave a well cost there, but I don’t think I heard it right. What was your — what is your average well cost up there now?
A:    Well, we just gave you the drilling cost, Leo. The drilling cost, we’re now at 3.7 million per well, but that’s on a considerably extended lateral length, too. You’ve heard me talk in the past 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 what I believe is adding another million to our completion — I mean to our total cost. Now, the real key here, and I’ve mentioned it a number of times to people here, is we continue to add stages as we go forward. And, of course, that’s using up some of our ability to reduce the cost.
Q:     Okay. If we make that. You talked about experimenting with horizontals in the Permian Basin here. Just trying to get a sense of how long you guys have been doing that and, you know, how much you’re anchored (?) in, you think is perspective and what type of improvements are you seeing in economics versus vertical drilling for these plats.
A:    Well, I’d say we’re really just getting started in the Permian Basin. There are a number of players who have been doing some horizontal drilling certainly in southeast New Mexico and in far West Texas for the past year, year and a half, and we’re really just getting started. These two wells I talked about were especially important because we’re drilling these in old water flood units. So, to get those kind of results in those kind of reservoirs is pretty impressive. We would have expected to have so much water coming back. In a typical well there, that would create some real problems for us, but that’s going to lead us to try a lot of different things across the basin over the rest of this year.
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Q:     Okay. I mean any sort of, you know, kind of estimates as opposed to how much a benefit you’re seeing here? Do you think you’re getting two or three times bang for the buck versus a vertical well in some of these fields or?
A:    Well, again, a little early on. I’ve only got two of them completed. But we would be getting more than twice as much from these wells if our estimates hold up.
Q:     Okay. You guys also talked a little about East Texas doing some Bossier wells. That’s been a hot topic in the industry lately. Just curious as to how much acres you have you think is perspective out there for Bossier.
A:    Yeah, we have a fairly modest position in East Texas, but we’re continuing to add in areas that we’re comfortable with. So, again, that’s not our hottest area, but we’re getting pretty worked up about it ‘cause we’ve had some great results out of our recent programs there on Moody and Folk.
Q:     Okay. Just jumping over the Granite Wash, it sounds like you had five completions. You talked about some cums (?) with all five wells. Any kind of a sense of kind of what these average rates are on these wells? I’m not exactly sure when you brought them on line.
A:    Yeah. I’ll have to get you average rates, but I would say we’re averaging somewhere around 10 million.
Q:     Okay. Thanks a lot.
O:     And we’ll go next to Judy Delgado with Alpine Associates.
Q:     Yes. Good morning. Just a general question wanting to know how the company’s felt about the situation going on in the Gulf of Mexico and the newly announced administration’s plan to be a little more stringent in their efforts to help. Do you have any thoughts on that?
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     First Quarter 2010 Earnings Release
A:    Well, I think it’s tragic that we had a loss of lives in the gulf and I think it’s 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.
Q:     Is the company experiencing any shutdowns now or are you planning for any shutdowns in the future?
A:    Well, we don’t have any shutdowns right now and it’s just going to depend on the direction of the — I assume you’re speaking to the spill itself, to the direction. We’re not in danger today about any of the spills reaching any of our existing production facilities, but that’s a “wait and see”.
Q:     Okay. Thank you.
O:     And we’ll go next to Brian Singer with Goldman Sachs.
Q:     Thanks. Good afternoon.
A:    Hi, Brian.
Q:     I wanted to see if you could touch a little bit more on cost inflation or lack of it as you go through your major areas both (inaudible) on the shorter term side in terms of some of the onshore drilling and completion activities and also anything you’re seeing on the steel pricing fronts when you think about the cost of LNG expansions in Australia and in Canada.
A:    Well, I’ll let John talk about North American and I might talk a little bit about overall what we’re seeing on it. I would start off from a generalization. I think it’s — personally, I think it’s premature to extrapolate cost increases that we’ve seen in the 1st quarter throughout the year. Winter is difficult for us in Canada and unfortunately was difficult for us in the central region because we’ve had one of the more severe freezes that we’ve had through that part of our portfolio in the 1st quarter. So, a lot of cost with respect to activities to get out there and start
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     First Quarter 2010 Earnings Release
    production again is part of those costs. And the other thing is, to be real honest with you, our production was down a little bit and one of the major culprits was because we are in a PIC and production sharing agreement in Egypt. And the good side of it is, oil prices go up. The downside of it is, is that we see less production which costs us about 5,000 barrels a day in Egypt. 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. I mean I’m sure everyone’s aware that steel prices are going up, and we’ll just have to wait and see and see what the impact of it is on those projects.
    John, do you have a —
A:    I guess I’d — yeah, I’d add on that steel cost. I guess I’d like to think there’s a positive side to that that probably indicates increased demand so hopefully we can get some strength in prices to support some of that activity, but obviously that’s something we’ll have to watch pretty closely because it has a big impact on virtually all of our business.
Q:     Great. Thanks. And, secondly, on the Granite Wash — probably both of you mentioned this earlier, but on a going forward basis for the next batch of wells you’re drilling, what are your expectations for percent gas versus percent NGOs versus percent connotator (?) well?
A:    I’m going to have to do the math, Brian. Can I just call you back with that one?
Q:     Yeah, absolutely. But I — or I guess just a bigger picture, are you concentrating more on the atoker (?) or the drier gas sounds relative to relative some of the shale or other oil (inaudible)?
A:    No, no, we’re concentrating on as high a liquid yield as we can get. We’re testing lots of different zones here, but obviously we’re looking at the highest liquid yields hardest.
Q:     Great. Thank you.
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     First Quarter 2010 Earnings Release
O:     Okay. We’ll go next to Doug Leggate (phonetic) with Bank of America.
Q:     Thanks. Good afternoon, gentlemen. A couple of questions. First of all, can you give us any better feel for where your capex may go this year partly on the — obviously the increased activity in the Granite, but also when you take account of the additional assets you’re going to have in the portfolio? And again, this would be appreciated.
A:    I’m sorry, can you phrase that a different way maybe?
Q:     Sure. Your capital expenditure gains for the current year, how is that likely to change? How do you expect your capital expenditure to trend over the balance of this year given that you’ve had —
A:    Well, in terms of — in terms of our overall capital budget, we’ve indicated before Devon and before the Mariner acquisition or merger that we would be a little more than $6 billion. And I think what you’re going to see is from an activity level, in our acquisition forecast for Devon, we have about a hundred million dollars of capital plugged in. Now, that number, depending on what kind of opportunities we see, may increase, but we’re going to generate about $285 million worth of cash out of that acquisition. With respect to Mariner, they have — we probably won’t close that until September-ish or later. They have a capital budget of about $550 million internally, which they are going to spend. So, from our standpoint, what you’ll see out of Apache is not a significant increase from the acquisitions now depending on what prices do. We allocate capital quarterly. And we put a few more rigs to work starting in the 2nd quarter than we’ve had running. So, you might see a little upward movement on our overall capital program.
Q:     Doesn’t sound like it’s anything to materials (inaudible).
A:    Not at the present time.
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     First Quarter 2010 Earnings Release
Q:     Okay. If I could jump forward to Egypt, could you give us some sense as to how you see your production playing out through the balance of this year? Obviously, there was an awful lot of moving parts, but if oil prices stayed pretty static at where they are right now, how would the trajectory play out as you move through 2010?
A:    Gross production — gross gas production will remain constant throughout the balance of the year because we are a facilities limited with existing gas processing facilities, although we tend to remedy that by 2012 with additional gas plant construction. On the oil side, I anticipate continued growth into oil quarter to quarter because we can’t handle more oil. As you saw, we have a substantial increase forecast in oil, on gross oil beginning later in this quarter from our West Kalabsha facilities project, and by year-end, we expect that to double again.
    And from the price standpoint, if we stay static as to where we are today — I think our March numbers were about 90,000 barrels a day net. So, if we grow up on gross and you see exactly the same number you saw average for March, you’re going to grow from there.
Q:     Okay. Where I was going with this, Steve, is that typically you guys tend to spend your cash flow I guess on a regional basis. I’m kind of thinking where the capital expenditure (inaudible) in Egypt particularly can take you. If I heard you correctly, it sounded like you’re going to drill about 19 exploration wells and that’s about half of what I thought you were going to drill this year. So, if you could just give me some clarity on that, I’ll leave it there. Thank you.
A:    That’s 19 exploration wells just in the Faghur Basin area. The total program for Egypt exploration wise is about 33 wells.
Q:     Oh, I see. Okay. Thanks.
O:     And our next question comes from Eric Marzucco (phonetic) with Dominic & Dominic.
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     First Quarter 2010 Earnings Release
Q:     Hi, it’s Tony Reiner. How are you?
A:    Good. How are you doing today?
Q:     Good. And I know these are crazy days for you. As far as what you commented before about the recent developments in the Gulf having no effect on the deal, do you think it will affect timing in any way, shape or form?
A:    No, I wouldn’t expect it to. I mean I have no reason to believe that we’d expect it to.
Q:     And it changes nothing as far as commitment, desire or anything on your end, I assume?
A:    No, none whatsoever.
Q:     Okay. Thanks so much. Appreciate your time.
O:     And our next question comes from Brian Lively (phonetic) with Tudor Pickering Holt.
Q:     Good afternoon. In the Permian Basin, your horizontal drilling is pretty interesting, but I was just interested in sort of the concept of approaching old water flood units with horizontal wells. Is the concept there to try to find some of the lower permeability sections that haven’t been swept by verticals or is there something else to it?
A:    No, that’s the primary answer. You know, a lot of those reservoirs out there even under secondary have only recovered somewhere in the range of 35 to 40 percent. And so that’s — you’re exactly right. That’s what we’re trying to get done is access reserves that have never been touched.
A:    And I might say John didn’t quite (inaudible). We have a huge position with respect to specially water floods and a few CO2’s ‘cause John just pointed out we
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    have 26 different projects that we’re looking at for CO2’s. So, it’s really — at the present time, it’s somewhat of a experiment, but if it works, you have a tremendous acreage position and water flood potential to really ramp up production.
Q:     Okay. That’s very interesting. Switching gears to Australia, Pyrenees and Van Gogh, what are your current FPSO volume limitations? I’m interested in is it an oil volume, water total fluids, and is there any upside as perhaps the water cut is lower than you’d expect?
A:    There’s a specific limitation on both vessels. The Pyrenees vessel is a larger FPSO than the one we have in Van Gogh. I think we’re kind of capped out at about — Van Gogh at about a little over about 65,000 barrels of oil a day — oil processing capability. And I forget the number over at Pyrenees. It’s about a hundred thousand barrels a day I think is their oil capacity.
    The second part of your question was what?
Q:     I was really just looking for it from the standpoint of total fluid handling versus oil volume, but I think you answered it.
A:    I think you’d also asked about water, and to date, we’ve seen no water in the first two months of production which is really good news.
Q:     Okay. That’s all the questions I have.
O:     And we have no more questions at this time.
Okay. Thank you. If anybody has any further questions, I’ll be in my office after the call.
(End of 1st Quarter Earnings Call)
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