UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

Commission File Number 1-4300

Apache Corporation

 

One Post Oak Central

2000 Post Oak Boulevard, Suite 100

Houston, Texas 77056-4400

Telephone Number (713) 296-6000

Securities Registered Pursuant to Section 12(b) of the Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Act:

Common Stock, $0.625 par value

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes [X]     No [ ]

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes [ ] No [X]

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]     No [ ]

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ ]

 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act

Large accelerated filer [X]     Accelerated filer [ ]     Non-accelerated filer [ ]

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes [ ]     No  [X]

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Portions of registrant’s proxy statement relating to registrant’s 2007 annual meeting of stockholders have been incorporated by reference into Part III hereof.

 

 

TABLE OF CONTENTS

 

DESCRIPTION

 

 

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (b/d) and thousands or millions of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

 

General

 

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production interests are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production interests onshore Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea), and onshore Argentina. Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since January 2004. On May 18, 2006, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our chief executive officer’s certification of compliance with the NYSE standards. Through our website, http://www.apachecorp.com, you can access electronic copies of the charters of the committees of our Board of Directors, other documents related to Apache’s corporate governance (including our Code of Business Conduct and Governance Principles), and documents Apache files with the Securities and Exchange Commission (SEC), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports. Included in our annual and quarterly reports are the certifications of our chief executive officer and our chief financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as practicable after filing with the SEC. You may also request printed copies of our committee charters or other governance documents by writing to our corporate secretary at the address on the cover of this report.

 

We hold interests in many of our U.S., Canadian, and other International properties through subsidiaries, including Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache North America, Inc., and Apache Overseas, Inc. Properties referred to in this document may be held by those subsidiaries. We treat all operations as one line of business.

 

Our Growth Strategy

 

Apache’s goal is to grow a profitable oil and gas company for the long-term benefit of our shareholders. Our strategy is to build a portfolio of core areas which provide growth opportunities through both grass-roots drilling and acquisition activity. We now have operations in six countries — the United States, Canada, Egypt, the United Kingdom sector of the North Sea, Australia, and our newest core area — Argentina. Whether in our oldest region, the U.S. Central region, or our newest, we seek to grow profitably while building critical mass that supports sustainable, lower-risk, repeatable drilling opportunities, balanced by higher-risk, higher-reward exploration. We also seek a balance in terms of gas vs. oil, geologic risk, reserve life and political risk.

 

When acquisition opportunities are identified, operational and technical teams participate in the evaluation process, enabling our personnel to move in quickly to execute exploitation activities (including workovers, recompletions and drilling) that will increase production and reserves, reduce costs per unit produced and enhance profitability. Over time, we build teams that have the technical knowledge and sense of urgency to maximize value. Our local knowledge of producing basins and our proactive culture provide a platform for continued growth through strategic acquisitions and drilling.

 

We also periodically evaluate our existing assets to determine whether sales of certain assets will provide opportunities to redeploy our capital resources to rebalance our portfolio and generate better prospective rates of return. As a result of this process, in January 2006, we sold our 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million, and in August we sold our China holdings to Australia-based ROC Oil Company Limited for $260 million. We reinvested these proceeds and purchased estimated proved reserves of 109 MMboe in Argentina.

 

More than a decade ago, recognizing that the United States was a mature oil and gas country, we added an international exploration component to our portfolio strategy, which provides exposure to larger reserve targets with

which to grow production and reserves through drilling. Apache is also one of the leading acquirers of three-dimensional (3-D) seismic data in the industry today. Our technology experts have developed strategies for rapid and cost-effective acquisition and processing of 3-D data, enabling our technical teams to analyze large swaths of acreage and generate drilling prospects on an accelerated timetable.

 

Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flow and rate-of-return targets, which are measured monthly, reviewed with senior management quarterly and utilized to determine annual performance rewards.

 

In the United States, the Gulf Coast region consistently delivers high returns on capital invested, as well as cash flow significantly in excess of our exploration and development spending there. Acquisitions play an important role because with steep decline rates, offshore reserves are generally short-lived and difficult to replace through drilling alone. The Central region brings the balance of long-lived reserves and consistent drilling results in the Permian basin of West Texas and New Mexico, East Texas and the Anadarko basin of western Oklahoma. Apache’s future growth in the United States is more likely to be achieved through a combination of drilling and acquisitions, rather than through drilling activity alone. Our $821 million Gulf of Mexico acquisition from BP and $269 million Permian basin acquisition from Amerada Hess, for example, complimented our active drilling program in 2006 and buttressed our growth in the U.S.

 

In Canada, we have almost seven million gross acres across the Provinces of British Columbia, Alberta, Saskatchewan and the Northwest Territories. We have a multi-year inventory of low-risk drilling opportunities in a number of Apache fields in Central Alberta, including Provost, Hatton and Nevis, and on acreage acquired in the Exxon Mobil Corporation (ExxonMobil) farm-in agreements of 2004 and 2005. With acquisition and land costs having risen significantly in Canada, these farm-ins provide a way for Apache to earn acreage through drilling with no upfront costs. ExxonMobil retains a royalty on fee lands and a convertible working interest on leasehold acreage, both of which vary dependent on activity levels. We also have opportunities to drill deeper exploration targets with higher reserve potential in Northwest Alberta and Northeast British Columbia.

 

In Egypt’s Western Desert, Apache’s 10.2 million gross acres encompass a sizable resource in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from lower Cretaceous to Jurassic, established producing trends. The Qasr gas/condensate field, discovered in 2003, is the largest field ever found by Apache with more than 2 trillion cubic feet of gas and 60 million barrels of estimated recoverable reserves.

 

In Australia, we have expanded our exploration program to the high-potential Exmouth, Browse and Gippsland basins while continuing to exploit our acreage position and control of key infrastructure in the Carnarvon basin. In the Gippsland basin we actively acquired almost 1.8 million acres over the past three years and have generated a 10-well inventory of high potential exploration prospects to be drilled in 2008. Additionally, Apache and its partners are designing three development projects in the Exmouth basin that are in process of being sanctioned and approved by all parties.

 

Apache entered the North Sea in 2003 with our acquisition of the Forties field (Forties), the largest field ever discovered in the United Kingdom. As operator, through drilling and extensive improvements to the production infrastructure, we virtually doubled production — and significantly reduced per-unit operating costs — from the second quarter of 2003. Our 2007 plans include infill and extentional drilling activity at Forties to determine if we can extend the field to the west, as well as exploration drilling on acreage blocks obtained over the past couple of years. We currently have around 100 Forties field drilling locations in our inventory.

 

For several years we held small interests in Argentina with the long-term view of expanding there through acquisitions. In April 2006, we purchased Pioneer Natural Resources’ (Pioneer) interests in Neuquén and the Austral basins for $675 million and subsequently purchased our partner’s, Pan American Fueguina S.R.L. (Pan American), interests in Tierra del Fuego, gaining operatorship in the under-exploited, highly prospective Austral basin concessions. Through subsequent workovers, recompletions and development activities, we increased production on the acquired properties and have established Argentina as Apache’s latest core area. While we expect unique challenges with evolving governmental regulations, we anticipate growing reserves and production in Argentina.

 

We exited 2006 with a year-end debt-to-capitalization ratio of 22 percent despite record capital spending of $6.4 billion, excluding asset retirement costs. This flexibility enables us to quickly act on attractive acquisition

transactions as they are identified, such as our agreement in January 2007 to acquire, through a joint venture interest, Permian basin assets from Anadarko Petroleum Company (Anadarko) for $1 billion. The transaction, which is subject to normal closing conditions and adjustments for matters such as preferential rights, is expected to close around the end of the first-quarter of 2007.

 

Apache has increased reserves in each of the last 21 years and production in 27 of the last 28 years. We believe our strategy and our diversified portfolio of assets provide a platform for profitable growth through drilling and acquisitions across the cycles of our dynamic industry.

 

In 2007, we are planning another active year of drilling. We revise our capital expenditure estimates throughout the year based on changing industry conditions and results to date. Therefore, accurately projecting annual capital spending is difficult at best. Our preliminary 2007 capital budget approaches $4.5 billion. While in most years capital budgets are expanded as the year unfolds, if commodity prices soften from year-end 2006 levels and service costs do not also decline; we plan to reduce our capital spending. Regarding potential acquisitions, we continually look for properties to which we believe we can add value and earn adequate rates of return and will take advantage of those acquisition opportunities as they arise.

 

Operating Highlights

 

Following the sale of our interest in China in the third quarter of 2006, our interests in six countries now comprise our reportable segments: the United States, Canada, Egypt, Australia, the North Sea, and Argentina. In the U.S., our exploration and production activities are spread between two regions: Gulf Coast and Central.

 

The following table sets out a brief comparative summary of certain key 2006 data for each area. More detailed information regarding oil, natural gas and natural gas liquids (NGLs) production and the average sales prices received in each geographic area for 2006, 2005, and 2004 is available later in this section under “Production, Pricing and Lease Operating Cost Data.” Also, further discussion and analysis of this data is available in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. For information concerning the revenues, expenses, operating income (loss) and total assets attributable to each of our reportable segments, see Note 13, Supplemental Oil and Gas Disclosures (Unaudited), and Note 12, Business Segment Information of Item 15 in this Form 10-K. For information regarding Oil and Gas Capital Expenditures for each of the last three years, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity” in this Form 10-K.

 

The following discussions include references to our plans for 2007. These only represent initial estimates and could vary significantly from actual results. In recent years, there have been large differences between our capital expenditure forecasts and our actual activity. During the year, we routinely adjust our level of spending based on results and changing industry conditions.

 

United States

 

Gulf Coast — The Gulf Coast region comprises our interests in and along the Gulf of Mexico, in the areas on-and offshore Louisiana and Texas. Apache is the largest held-by-production acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep. For the third year in a row, the Gulf Coast was our leading region for both production volumes and revenues. Gulf Coast activities in 2006 focused on restoring production impacted by the 2005 hurricanes, while maintaining an active drilling program. This region performed 296 workover and recompletion operations during 2006 and completed 65 out of 83 total wells drilled as producers. Our drilling locations mostly included proved undeveloped reserves at platforms sustaining minimum or no hurricane damage with access to third-party transport facilities. In June 2006, we acquired producing properties, facilities and prospects on the Outer Continental Shelf of the Gulf of Mexico from BP plc (BP) for $845 million, adding an estimated 44.2 MMboe of proved reserves. The purchase price was allocated as follows: $747 million producing properties, $42 million prospects, $56 million facilities. As of year-end 2006, the Gulf Coast region accounted for 17 percent of our estimated proved reserves. Although actual annual capital expenditures may change considerably in 2007, we currently estimate investing approximately $900 million to drill over 90 wells and to continue our production enhancement and exploitation programs. In addition, we plan to spend an estimated $350 million on repair, redevelopment, and plugging and abandonment work required to repair damage caused by Hurricanes Katrina and Rita in 2005 that will not be covered by insurance.

 

Central — The Central Region includes assets in the Permian basin of West Texas and New Mexico, East Texas, and the Anadarko basin of western Oklahoma, where the Company got its start over 50 years ago. On January 5, 2006, the Company expanded its presence in the Permian basin by purchasing an estimated 31.5 MMboe of reserves in eight fields for $269 million from Amerada-Hess. In early 2007, we also entered into agreements to acquire additional Permian basin interests from Anadarko as described in more detail below under “Subsequent Events.” As of year-end 2006, the Central region accounted for approximately 24 percent of our estimated proved reserves, the second largest concentration in the Company. During 2006, we participated in drilling 374 wells, 363 of which were completed as productive. Apache performed 615 workovers and recompletions in the region during the year. We currently estimate spending approximately $570 million in 2007 on drilling and production enhancement projects.

 

Marketing — In general, most of our U.S. gas is sold on a monthly basis at either monthly or daily market prices. Our natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, integrated major oil and gas companies and marketers. In an effort to increase sales to direct users of natural gas and to meet the needs of our customers, we also periodically sell some gas under long-term contracts at prices that fluctuate with market conditions. Approximately eight percent of our 2006 U.S. natural gas production was sold under long-term fixed-price physical contracts which expire in 2007 and 2008. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk “Commodity Risk” in this Form 10-K.

 

Apache has historically marketed and continues to sell its U.S. crude oil to integrated major oil companies, purchasers, transporters, and refiners. The objective is to maximize the value of the crude oil sold by identifying the most economical markets and transportation routes available to move the crude oil via pipeline, truck or barge. Sales contracts are generally thirty (30) day evergreen contracts and renew automatically until canceled by either party. These contracts provide for sales at prices which fluctuate with daily oil market conditions, thus capturing the market value of the crude oil each day. We manage our credit risk by selling our oil to creditworthy counterparties and monitoring our exposure on a daily basis.

 

Canada

 

Overview — Our exploration and development activity in our Canadian region is concentrated in the Provinces of Alberta, British Columbia, Saskatchewan and to a lesser degree the Northwest Territories. The region comprises

24.9 percent of our estimated proved reserves, the largest in the Company. We hold over 4.9 million net acres in Canada, the largest of our North American regions. Canada was our most active drilling area in 2006, with Apache participating in 874 wells, focused primarily on low-risk shallow development wells. We completed 740 as producers and conducted 274 workover and recompletion projects. Although actual annual capital expenditures may change with industry conditions and results, we currently estimate spending approximately $770 million in 2007 to drill approximately 380 wells, continue our exploitation program, albeit at a lower level, and continue developing our gas processing infrastructure. Our 2007 drilling program will include more deeper, higher risk-reward exploration wells and fewer shallow development wells.

 

Apache is also targeting fields such as Provost and Nevis in Alberta for coalbed methane (CBM) and in the process has emerged as one of Canada’s largest producers of CBM. The North and South Grant Lands obtained through farm-in agreements (discussed below) provide additional CBM potential.

 

In 2005, Apache signed a farm-in agreement with ExxonMobil covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil retains a royalty on fee lands and a convertible working interest on leasehold acreage, both of which vary dependent on activity levels. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in a 2004 farm-in agreement with ExxonMobil. The 2004 farm-in agreement covered approximately 380,000 acres and stipulated drilling at least 250 wells over a two-year period beginning in October 2004. The 250 well commitment was met and the agreement was extended for an additional year. In 2006, Apache drilled 218 wells on the 2005 and 2004 farm-in acreage earning 93 additional acreage sections. Through the end of 2006, Apache has now drilled a total of 675 wells on the farm-in acreage from both agreements.

 

Marketing — Our Canadian natural gas sales focuses on sales to LDCs, utilities, end-users, integrated majors, supply aggregators and marketers. Our composite client portfolio is credit worthy and diverse. Improved North American natural gas pipeline connectivity has triggered a closer correlation between Canadian and United States natural gas prices. To diversify our market exposure and optimize pricing differences in the U.S. and Canada, we transport natural gas via our firm transportation contracts to California, the Chicago area, and eastern Canada. Our objective is to sell the majority of our production monthly, either into the first of the month market, or the daily market. Over 95 percent of our Canadian natural gas production is sold on a monthly basis at either monthly or daily market prices. Approximately two percent of our sales are long-term fixed-price sales. The longest term for these sales expires in 2011. The remainder is sold under long-term commitments to Canadian aggregators and end-users where the prices we receive under these contracts fluctuate monthly with market indices.

 

Our Canadian crude oil is primarily sold to refiners, integrated majors and marketers. To increase the market value of our condensate and heavier crudes, our condensate is either used or sold for blending purposes. We sell our crude oil and NGLs on Canadian Postings, which are market reflective prices that depend on worldwide crude oil prices and are adjusted for transportation and quality. In order to reach more purchasers and diversify our market, we transport crude on 12 pipelines to the major trading hubs within Alberta and Saskatchewan.

 

Egypt

 

Overview — In Egypt, our operations are conducted pursuant to production sharing contracts under which the contractor partner pays all operating and capital expenditure costs for exploration and development. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is the second largest acreage holder and the most active driller in the Western Desert of Egypt. Egypt is the country with our largest single acreage position where, as of December 31, 2006, we held approximately 10.2 million gross acres in 19 separate concessions. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries, or on a negotiated basis. Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert. Egypt contributed approximately 21 percent of Apache’s production revenues and 19 percent of total production. Egypt accounted for 12 percent of total estimated proved reserves as of December 31, 2006. The Company reports all estimated proved reserves held under production sharing agreements utilizing the economic interest method, which excludes the host country’s share of reserves.

 

In 2006, Apache had an active drilling program in Egypt, completing 140 of 163 wells, an 86 percent success rate, and conducted 390 workovers and recompletions. We currently plan to spend approximately $1 billion in 2007. Of this, $600 million will be for drilling and production enhancement work. We recently received approval to expand our Western Desert gas processing capacity and infrastructure to evacuate an additional 200 MMcf/d gas volumes driven by the Qasr field discovery. We project that this upgrade will take two years to complete at a total cost of $950 million, excluding actual gas well drilling costs and we have included $350 million in our capital expenditures for 2007.

 

On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million.

 

Please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for a discussion of our Egyptian receivables.

 

Marketing — We and our partners have sold our gas production to EGPC under an Industry Pricing Formula; which is a sliding scale based on Dated-Brent crude oil with a minimum of $1.50 per MMbtu and a maximum of $2.65 per MMbtu which corresponds to a Dated-Brent price of $21.00 per barrel. Generally, the Industry Pricing Formula applies to all new gas discovered and produced. In exchange for extension of the Khalda Concession lease in July 2004, Apache agreed to accept Industry Pricing on all production in excess of 100 MMcf/d, but preserved the higher price formula until 2013 on the initial 100 MMcf/d.

 

Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is either sold directly to EGPC or other third-parties. The oil sales are made either directly into the Egyptian oil pipeline grid, exported via one of two terminals on the north coast of Egypt, or sold to third parties (non-governmental) through the MIDOR refinery located in northern Egypt. Oil production that is presently sold to EGPC is sold on a spot basis at a “Western Desert” price (indexed to Brent). In 2006, we exported 28 cargoes (approximately 8.6 million barrels) of Western Desert crude oil from the El Hamra and Sidi Kerir terminals located on the northern coast of Egypt. These export cargoes were sold at market prices comparable to domestic sales to EGPC. Additionally, 24 cargoes representing 3.5 million barrels were sold in Egypt to other non-governmental purchasers at prevailing market prices. Export sales from both the Khalda and Qarun areas in the Western Desert have continued in 2007.

 

Australia

 

Overview — Our exploration activity in Australia is focused in the offshore Carnarvon, Gippsland, Browse, and Perth basins where Apache holds 6.8 million net acres in 35 Exploration Permits, 10 Production Licenses, and six Retention Leases. Production operations are concentrated in the Carnarvon basin which is the location of all 10 Production Licenses, nine of which are operated by Apache. In 2006, the region generated $408 million of production revenues producing 15.7 MMboe (8.6 percent of our total production) and accounted for 8.8 percent of our year-end estimated proved reserves. During the year we participated in drilling 23 wells; 18 exploration and five development wells. Four of the exploration wells and three of the development wells were productive for a 30 percent success rate.

 

Exploration successes in 2006 included the Theo and West Cycad oil discoveries and the Gnu and Bambra East gas finds. The West Cycad oil discovery was drilled in the Harriet Joint Venture (HJV) area and is slated to begin production in the first quarter of 2007. The successful Theo well was drilled in the Exmouth sub-basin and is scheduled to begin production in 2009. The Gnu well was drilled in the Reindeer/Caribou field and added significant new reserves. First production from the Reindeer/Caribou field is targeted for late 2008 or early 2009. The Bambra East well was a successful gas well in the HJV, which more than doubled the volume of gas attributed to the Bambra field area. Gas production from this asset will begin in 2007 subject to augmentation of existing infrastructure.

 

During 2007, our Australian region plans to expand the HJV oil and gas production through development of the 2006 discoveries and drilling three additional wells: Bambra 8, Doric 2 and Lee 3. We will monitor the effects of the increased water injection at Stag and possibly drill an additional producer. We will also begin the initial phase of development drilling at the Van Gogh field. A key factor for success in 2007 will be increasing gas production and

reserves to fulfill the requirements of our sales contracts, exploration success and initiating the Theo field development and final sanctions thereof. We currently estimate spending approximately $460 million in 2007 to drill 30 exploration, appraisal and development wells and another $50 million for new facilities.

 

Marketing — In 2006, we executed three new gas sales contracts in Australia. As of December 31, 2006, Apache had a total of 22 active gas contracts with expiration dates ranging from April 2007 to July 2030. Generally, natural gas is sold in Western Australia under long-term, fixed-price contracts, many of which contain price escalation clauses based on the Australian consumer price index.

 

We continue to export all of our crude oil production into the international market at prices which fluctuate with world market conditions.

 

North Sea

 

Overview — In 2006, the North Sea region generated $1.35 billion of revenue, producing 21.5 million barrels of oil equivalent. We continued to develop our North Sea core area around the Forties field, including investments in upgrades to improve the operating efficiency of our platforms. Despite this, 2006 production was down 11 percent from 2005 primarily because of production interruptions associated with commissioning of major facility projects, and temporary shutdown of the Forties Pipeline System during the third quarter of 2006. Our focus in 2006 on infrastructure projects also displaced drilling operations needed to mitigate natural decline.

 

In 2006, we invested $329 million of capital in the North Sea region, including investments on drilling, recompletion and facility upgrades.

 

At Forties we commissioned a number of key facility projects to improve production efficiency and lower operating costs, including new power generation, a multi-platform distribution system, water injection upgrades and drilling rig modification. Also during 2006, seismic survey data acquired over Forties in 2005 was processed for inversion to identify bypassed oil in the main reservoir units and update the inventory of future drilling targets. We also drilled one appraisal well outside Forties, and had a second appraisal well and an exploration well in progress at the end of 2006.

 

There were no significant additions to North Sea acreage in 2006; however, in early 2007 Apache was awarded 62,320 acres from four licenses applied for in the UK 24th Licensing Round. In block 22/6a (Bacchus), Apache increased equity from 60 percent to 70 percent and became Operator (purchasing ExxonMobil’s 20 percent share and farming out 10 percent). A further 652 square kilometers of 3D seismic was acquired over six blocks of our acreage.

 

North Sea capital expenditures for 2007 are currently estimated at $480 million. After a year with minimal drilling, activity will significantly increase. In Forties, we will continue the development drilling program, with 15 new wells planned, and complete platform upgrades begun last year. Upgrades for 2007 include finalizing installation of additional produced water re-injection pumps and deep gas lift compressors, and commissioning of direct fluid export from Forties Bravo to Forties Charlie. These projects will enable Forties to meet stringent new environmental targets for produced water discharge to sea as well as enhance reservoir management capabilities, and should enhance runtime efficiency. Outside Forties, four exploration and appraisal wells are scheduled to be drilled in the first half of the year.

 

Marketing — In 2006, we entered into two new term contracts for the physical sale of Forties crude at prevailing market prices, which are composed of base market indices, adjusted for the higher quality of Forties crude relative to Brent and a premium to reflect the higher market value for term arrangements. Also in 2006, a new value adjustment formula (Quality Bank Adjustor) was implemented in BP’s Forties Pipeline System, through which Forties crude is shipped and commingled with crudes from other central North Sea fields. The original formula was challenged by Apache in June 2005, as it did not accurately value the Forties crude quality relative to the other crudes shipped on the Forties Pipeline System. The new agreed upon comingled stream on the formula better represents Forties crude value and effectively increases the volume allocated to Apache from the Forties Pipeline System.

 

Argentina

 

Argentina became our newest core area following two significant acquisitions in 2006 that substantially increased our presence in the country. In the second quarter, we completed our purchase of Pioneer’s operations in Argentina for $675 million with estimated proved reserves of 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas. In the third quarter, we acquired additional interests in (and now operate) seven concessions in the Tierra del Fuego Province from Pan American for total consideration of $429 million. Our oil and gas assets are located in the Neuquén, San Jorge and Austral basins of Argentina. In 2006, we had 9.9 MMboe of production and 110.6 MMboe of estimated proved reserves, approximately 5.4 percent and 4.8 percent, respectively, of Apache’s total production and reserves.

 

We plan to invest approximately $180 million drilling over 100 wells and spend an additional $60 million on production enhancement projects in 2007.

 

Marketing — In Argentina we extended our existing natural gas contracts to regulated markets through April 2007, per the Argentine Secretary of Energy’s request. We expect to reach a new agreement during the first-quarter of 2007 with the Argentine government, which will set the volumes to be delivered to the regulated market for the period 2007 through 2011. We also entered into four new term contracts up to two years in duration for a total of 22 MMcf/d. These four contracts enabled Apache to lock in higher priced contracts while awaiting a new agreement to cover the internal demand of Argentina for 2007 onward.

 

In October 2006, the Argentina government removed the export tax exempt status previously afforded the province of Tierra del Fuego through a Special Customs area exemption. The government has further assessed an export tax on all exports from Argentina based upon the price paid for natural gas imports from Bolivia. This tax reduces the value we are receiving under our contract with Methanex in Chile. We have entered into an interim agreement with Methanex to mitigate the effects of this tax and are working to reach an economically suitable final agreement. The Methanex contract represents less than 10 percent of our gas sales in Argentina.

 

Other International

 

China.  On August 8, 2006, the Company completed the sale of our 24.5 percent interest in the Zhao Dong block offshore the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The transaction was effective July 1, 2006, and the Company recorded a gain of approximately $174 million in the third-quarter of 2006.

 

Subsequent Events

 

On January 18, 2007, the Company announced that it is acquiring controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko Petroleum Corporation (Anadarko) for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of yearend 2006. The transaction will be effective the earlier of closing or March 31, 2007. Approximately 10 percent of the Permian basin properties are subject to third-party preferential purchase rights which, if exercised, would reduce the interests we purchase in those properties and the purchase price we would pay. The Company intends to fund the acquisition with debt. Apache and Anadarko are entering into a joint-venture arrangement to effect the transaction. In connection with the acquisition, the Company entered into cash flow hedges to protect against commodity price volatility. For the period of July 2007 through June 2010, the Company entered into hedges for a portion of both the oil and the natural gas with NYMEX based costless collars.

 

In anticipation of closing the Anadarko transaction, we completed a public offering in January 2007 of $500 million of 5.625-percent notes due 2017 and $1 billion of 6.0-percent notes due 2037. The net proceeds from the offering ($1.48 billion, net of original issue discounts and underwriting commissions) were used to repay a portion of our outstanding commercial paper, which was incurred to finance acquisitions we made in 2006 and for general corporate purposes.

 

Drilling Statistics

 

Worldwide, in 2006, we participated in drilling 1,611 gross wells, with 1,399 (87 percent) completed as producers. We also performed more than 1,700 workovers and recompletions during the year. Historically, our drilling activities in the U.S. generally concentrate on exploitation and extension of existing, producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and exploitation wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 76 in the U.S. (40.27 net); 10 in Canada (10 net); 18 in Egypt (17.12 net); three in Australia (2.06 net); and two in the North Sea (1.94 net).

 

The following table shows the results of the oil and gas wells drilled and tested for each of the last three fiscal years:

 

Productive Oil and Gas Wells

 

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2006, is set forth below:

 

 

Production, Pricing and Lease Operating Cost Data

 

The following table describes, for each of the last three fiscal years, oil, NGLs and gas production, average lease operating costs per boe (including severance and other taxes) and average sales prices for each of the countries where we have operations.

 

Gross and Net Undeveloped and Developed Acreage

 

The following table sets out our gross and net acreage position in each country where we have operations.

 

 

As of December 31, 2006, we had 736,497, 2,918,890, and 1,802,281 net acres scheduled to expire by December 31, 2007, 2008 and 2009, respectively, if production is not established or we take no other action to extend the terms. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.

 

The other international drilling statistics on the preceding page and the Production, Pricing and Lease Operating Cost Data above include activity in China, where Apache ceased operations in August 2006.

 

Estimated Proved Reserves and Future Net Cash Flows

 

As of December 31, 2006, Apache had total estimated proved reserves of 1,061 MMbbls of crude oil, condensate and NGLs and 7.5 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.3 billion barrels of oil equivalent or 13.9 Tcf of natural gas. During 2006, the Company’s reserves grew nine percent with increases in all our countries. The Company’s reserves have increased for 21 consecutive years.

 

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company reports all estimated proved reserves held under production sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. Reserve estimates are considered proved if economical producibility is supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.

 

Apache emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed throughout the year, and revised either upward or downward, as warranted by additional performance data.

 

Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers who are independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas, and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Reserves are reviewed internally with senior management and presented to Apache’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable.

 

We engage Ryder Scott Company, L.P. Petroleum Consultants as independent petroleum engineers to review our estimates of proved hydrocarbon liquid and gas reserves and provide an opinion letter on the reasonableness of Apache’s internal projections. Ryder Scott opined that they were in acceptable agreement with the Company’s overall reserve estimates and that the reserves they reviewed conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2006, 2005 and 2004, their review covered 75, 74 and 79 percent of Apache’s worldwide estimated reserve value, respectively.

 

The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2006, 2005 and 2004, changes in estimated proved reserves during the last three years, and estimates of future net cash flows and discounted future net cash flows from estimated proved reserves are contained in Note 13, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K. These estimated future net cash flows are based on prices on the last day of the year and are calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10.

 

Employees

 

On December 31, 2006, we had 3,150 employees. Only 25 of these employees are subject to collective bargaining agreements, all of whom are in Argentina.

 

Offices

 

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2006, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2013. For information regarding the Company’s obligations under its office leases, see the information appearing in the table in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity, Contractual Obligations” and Note 10, Commitments and Contingencies, “Other Commitments and Contingencies, Contractual Obligations” of Item 15 in this Form 10-K.

 

Title to Interests

 

As is customary in our industry, a preliminary review of title records is made at the time we acquire properties, which may include opinions or reports of appropriate professionals or counsel. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions which do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, and other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

 

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.

 

Our Profitability is Highly Dependent on the Prices of Crude Oil, Natural Gas and Natural Gas Liquids, Which Have Historically Been Very Volatile

 

Our estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control. Historically, these prices have been very volatile. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow, and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves.

 

Our Commodity Hedging May Prevent Us From Benefiting Fully From Price Increases and May Expose Us to Other Risks

 

To the extent that we engage in hedging activities to protect ourselves from commodity price volatility, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

 

Acquisitions or Discoveries of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production

 

The rate of production from oil and gas properties generally declines as reserves are depleted. Except to the extent that we find or acquire additional properties containing estimated proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

 

Our Drilling Activities May Not Be Productive

 

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

 

 

Certain future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

 

Risks Arising From the Failure to Fully Identify Potential Problems Related to Acquired Reserves or to Properly Estimate Those Reserves

 

One of our primary growth strategies is the acquisition of oil and gas properties. Although we perform a review of the acquired properties that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it

permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.

 

We Are Subject to Governmental Risks That May Impact Our Operations

 

Our operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price controls and environmental protection laws and regulations.

 

Global Political and Economic Developments May Impact Our Operations

 

Political and economic factors in international markets may have a material adverse effect on our operations. On an equivalent-barrel basis, approximately 63 percent of our oil, NGLs and natural gas production in 2006 was outside the United States, and approximately 59 percent of our estimated proved oil and gas reserves on December 31, 2006 were located outside of the United States.

 

There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, NGLs, and natural gas pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include: political and economic instability or war; the possibility that a foreign government may seize our property with or without compensation; confiscatory taxation; legal proceedings and claims arising from our foreign investments or operations; a foreign government attempting to renegotiate or revoke existing contractual arrangements, or failing to extend or renew such arrangements; fluctuating currency values and currency controls; and constrained natural gas markets dependent on demand in a single or limited geographical area.

 

On December 23, 2004, Apache entered into a 20-year insurance contract with the Overseas Private Investment Corporation (OPIC) which provides $300 million of political risk insurance for the Company’s Egyptian operations. This policy insures us against (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the Government of Egypt prevent Apache from exporting our share of production. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for additional discussion of our Egyptian receivables.

 

In addition to the contract with OPIC, the Company has acquired commercial political risk insurance covering significant portions of its investments in Egypt and Argentina. The insurance provides coverage for confiscation, nationalization, and expropriation risks and currency inconvertibility, and is written on multi-year contracts with highly rated international insurers.

 

Actions of the United States government through tax and other legislation, executive order and commercial restrictions can adversely affect our operating profitability in the U.S. as well as other countries. Various agencies of the United States and other governments have, from time to time, imposed restrictions which have limited our ability to gain attractive opportunities or even operate in various countries. These restrictions have in the past limited our foreign opportunities and may continue to do so in the future.

 

Weather and Climate May Have a Significant Impact on Our Revenues and Productivity

 

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impacts the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.

 

Costs Incurred Related to Environmental Matters

 

We, as an owner or lessee and operator of oil and gas properties, are subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages, and require suspension or cessation of operations in affected areas.

 

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We also have established operational procedures and training programs designed to minimize the environmental impact of our field facilities. The costs incurred by these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate the expenses related to environmental matters; however, we do not believe any such additional expenses are material to our financial position or results of operations.

 

Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of our employees who are expected to devote a significant amount of time to any possible remediation effort. Our general policy is to limit any reserve additions to incidents or sites that are considered probable to result in an expected remediation cost exceeding $100,000.

 

We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. As described in Note 10, Commitments and Contingencies of Item 15, in this Form 10-K, on December 31, 2006, we had an accrued liability of $17 million for environmental remediation. We have not incurred any material environmental remediation costs in any of the periods presented and we are not aware of any future environmental remediation matters that would be material to our financial position or results of operations.

 

Although environmental requirements have a substantial impact upon the energy industry, generally these requirements do not appear to affect us any differently, or to any greater or lesser extent, than other upstream companies in the industry. We do not believe that compliance with federal, provincial, state, local or foreign country provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of Apache or its subsidiaries; however, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact.

 

Industry Competition

 

Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and reserves, equipment and labor required to explore, develop and operate those properties and the marketing of oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties

available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than those we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geo-physicists, engineers and other specialists.

 

Insurance Does Not Cover All Risks

 

Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance is not available to us against all operational risks.

 

In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange insurance to cover fully its Gulf of Mexico exposures at a reasonable cost when the current policies expire.

 

As of December 31, 2006, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to yearend. We responded to comments from the SEC staff that we received in December 2006, and are awaiting final resolution. We do not believe the comments or our responses thereto materially impact any previous or prospective disclosures.

 

See the information set forth in Note 10, Commitments and Contingencies of Item 15 and Item 1A, Risk Factors, “Costs Incurred Related to Environmental Matters” in this Form 10-K.

 

No matters were submitted to a vote of our security holders during the most recently ended fiscal quarter.

 

During 2006, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock exchanges, and the NASDAQ National Market under the symbol APA. The table below provides certain information regarding our common stock for 2006 and 2005. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per share prices and quarterly dividends shown below have been rounded to the indicated decimal place.

 

 

The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2007, was $72.97. On January 31, 2007, there were 330,958,433 shares of our common stock outstanding held by approximately 7,000 shareholders of record and approximately 319,000 beneficial owners.

 

We have paid cash dividends on our common stock for 42 consecutive years through December 31, 2006. When, and if, declared by our board of directors, future dividend payments will depend upon our level of earnings, financial requirements and other relevant factors.

 

In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one “preferred stock purchase right (a “right”)” for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the rights were reset to one right per share of common stock and the expiration was extended to January 31, 2016. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights and, the rights trade automatically with our shares of common stock. For a description of the rights, please refer to Note 8, Capital Stock of Item 15 in this Form 10-K.

 

In 2003, our board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to holders of record on December 31, 2003. In connection with the stock split, the Company issued 166,254,667 shares.

 

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2007 annual meeting of stockholders, which is incorporated herein by reference.

 

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500

Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2001 through December 31, 2006.

 

Comparison of Five Year Cumulative Total Return
For the Year Ended December 31, 2006

 

 

 

 

 

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2006, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by the more detailed information in the Company’s financial statements of Item 15 in this Form 10-K.

 

 

For a discussion of significant acquisitions and divestitures, see Note 2 of Item 15 in this Form 10-K.

 

Overview

 

Apache Corporation (Apache or the Company) is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. We operate in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom in the North Sea, and Argentina.

 

In 2006, we earned $2.5 billion, within three percent of last year’s record earnings, despite a 19 percent decline in gas price realizations. Cash provided by operating activities totaled $4.3 billion, flat to 2005. We also set records for production and reserves with worldwide equivalent production increasing 10 percent, making 2006 the 27th out of the last 28 years that we have reported production growth. Reserves grew nine percent, increasing in every core area, marking the 21st consecutive year of reserve growth at Apache.

 

Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on, among other things, costs levels, potential rates of return and the availability of acquisition opportunities. We utilize a portfolio approach to provide diversity in terms of geologic risk, geographic location, hydrocarbon mix (crude oil and natural gas) and reserve life. This strategy provides multiple avenues for growth. We took several steps in 2006 to balance and grow our asset base. Outside of North America, we divested two assets: the undeveloped deepwater section of Egypt’s West Mediterranean Concession and our interest in the Zhao Dong block offshore the People’s Republic of China. To rebalance our international portfolio, we bolstered our position in Argentina purchasing an estimated 109 MMboe of reserves in two separate transactions. After increasing our production on these properties through active operations, Argentina is now our newest core area and we operate an

attractive property base that we believe has significant upside. In the U.S., we completed two strategic purchases strengthening our Permian basin and Gulf of Mexico positions. In January 2006, we purchased an estimated 31 MMboe of proved reserves in long life producing properties in the Permian basin of West Texas. The acquisition was balanced by purchasing 44 MMboe of shorter life, but higher rate-of-return reserves in the Gulf of Mexico. Worldwide, we purchased an estimated 196.5 MMboe of proved reserves. On the exploration and development side, we drilled 1,611 wells with an 87 percent success rate with active drilling programs in all core areas. We invested $3.7 billion in exploration and development activities, excluding asset retirement costs and capitalized interest, adding 224 MMboe in of estimated proved reserves. Our reserve life across our core areas spans from eight to twenty years, with a 46 percent oil and 54 percent natural gas mix, consistent with yearend 2005.

 

Apache’s profitability is a function of commodity prices, the cost to add reserves through drilling and acquisitions and the cost to produce our reserves. Trends in commodity prices directly impact oil and gas revenues and demand for services and thus, have a significant impact on drilling and operating costs. We closely monitor trends in drilling costs in each of our core areas and the prices paid to acquire producing properties and, when appropriate, adjust our capital budgets.

 

Commodity prices are driven by the prevailing worldwide price for crude oil, spot prices applicable to our United States and Canadian natural gas production and many other factors beyond our control. Historically, these prices have been volatile and unpredictable, and 2006 was no exception. Our 2006 crude oil price realizations averaged $59.92 per barrel, up 16 percent from 2005, ranging from an average monthly high of $68.59 per barrel in July to a low of $52.64 per barrel in October as demand waned in the U.S. with a delay in the onset of seasonal temperatures. Natural gas realizations were 19 percent lower than last year, averaging $5.17 per thousand cubic feet (Mcf), with a high of $8.05 per Mcf in January, and a low of $3.85 per Mcf in October.

 

A high drilling and operating cost environment once again challenged us in 2006, continuing the trend seen over the past few years. This upward trend is a reflection of increased demand driven by historically high commodity prices. In addition, repair activity from the 2005 Gulf of Mexico hurricanes also increased demand for services in the U.S., and accordingly, costs. Cost increases were reflected in nearly all of our drilling and lease operating cost components, including: rig rates, drill pipe costs, labor costs, chemical costs and the costs of power and fuel. The Company reviews costs for each core area on a routine basis and pursues alternatives in maintaining efficient levels of costs and expenses. Despite pressure from rising costs, 2006 margins, while down slightly from record 2005 levels, were the second highest in our 50-plus-year history. For purposes of this discussion, margins are calculated as follows:

 

 

While the Company has made considerable progress recovering from the damage caused by Hurricanes Katrina and Rita, which struck in late August and late September 2005, the hurricanes had considerable impact on both 2006 and 2005 operations and results, and will impact 2007 operations. In addition to extensive damage to Apache’s onshore and offshore Gulf of Mexico production and transportation facilities, third-party pipelines, terminals and processing facilities, which the Company relies upon to transport and process its crude oil and natural gas also sustained substantial damage. For a discussion of the impact on 2006 and 2005 operations and results refer to Results of Operations and Oil and Gas Capital Expenditures in this Item 7.

 

Results of Operations

 

This section includes a discussion of our 2006 and 2005 results of operations and provides insight into unique events and circumstances for each of the Company’s six reportable segments. Please refer to Note 12, Business Segment Information of Item 15 in this Form 10-K for segment information.

 

Acquisitions and Divestitures

 

2006 Acquisitions

 

U.S. Permian Basin

 

On January 5, 2006, the Company purchased Amerada Hess’s interest in eight fields located in the Permian basin of West Texas and New Mexico. The original purchase price was reduced from $404 million to $269 million because other interest owners exercised their preferential rights to purchase a number of the properties. The settlement price at closing of $239 million was adjusted for revenues and expenditures occurring between the effective date and the closing date of the acquisition. The acquired fields had estimated proved reserves of 27 MMbbls of liquid hydrocarbons and 27 Bcf of natural gas as of yearend 2005.

 

Argentina

 

On April 25, 2006, the Company acquired the operations of Pioneer Natural Resources (Pioneer) in Argentina for $675 million. The settlement price at closing, of $703 million, was adjusted for revenues and expenditures occurring between the effective date and closing date of the acquisition. The properties are located in the Neuquén, San Jorge and Austral basins of Argentina and had estimated net proved reserves of approximately 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas as of December 31, 2005. Eight gas processing plants (five operated and three non-operated), 112 miles of operated pipelines in the Neuquén basin and 2,200 square miles of three-dimensional (3-D) seismic data were also included in the transactions. Apache financed the purchase with cash on hand and commercial paper.

 

The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

 

 

On September 19, 2006, Apache acquired additional interests in (and now operates) seven concessions in the Tierra del Fuego Province from Pan American Fueguina S.R.L. (Pan American) for total consideration of $429 million. The settlement price at closing of $396 million was adjusted for normal closing items, including revenues and expenses between the effective date and the closing date of the acquisition. Apache financed the purchase with cash on hand and commercial paper.

 

The total cash consideration allocated below includes working capital balances purchased, asset retirement obligations assumed and an obligation to deliver specific gas volumes in the future. The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

 

Offshore Gulf of Mexico

 

In June 2006, the Company acquired the remaining producing properties of BP plc (BP) on the Outer Continental Shelf of the Gulf of Mexico. The original purchase price was reduced from $1.3 billion for 18 producing fields to $845 million because other interest owners exercised their preferential rights to purchase five of the 18 fields. The purchase price consisted of $747 million of proved property, $42 million of unproved property and $56 million of facilities. The settlement price on the date of closing of $821 million was adjusted primarily for revenues and expenditures occurring between the April 1, 2006 effective date and the closing date of the acquisition. The acquired properties include 13 producing fields (nine of which are operated) with estimated proved reserves of 19.5 MMbbls of liquid hydrocarbons and 148 Bcf of natural gas. Apache financed the purchase with cash on hand and commercial paper.

 

Pending Acquisition — U.S. Permian Basin

 

On January 18, 2007, the Company announced that it is acquiring controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko Petroleum Corporation (Anadarko) for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of yearend 2006. The transaction will be effective the earlier of closing or March 31, 2007. Approximately 10 percent of the Permian basin properties are subject to third-party preferential purchase rights which, if exercised, would reduce the interests we purchase in those properties and the purchase price we would pay. The Company intends to fund the acquisition with debt. Apache and Anadarko are entering into a joint-venture arrangement to effect the transaction. In connection with the acquisition, the Company entered into cash flow hedges to protect against commodity price volatility. For the period of July 2007 through June 2010, the Company entered into hedges for a portion of both the oil and the natural gas with NYMEX based costless collars.

 

2006 Divestitures

 

On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache did not have any proved reserves booked for these properties.

 

On August 8, 2006, the Company completed the sale of its 24.5 percent interest in the Zhao Dong block offshore, the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The effective date of the transaction was July 1, 2006. The Company recorded a gain of $174 million in the third quarter of 2006.

 

2005 Acquisitions

 

In May 2005, Apache signed a farm-in agreement with Exxon Mobil Corporation (ExxonMobil) covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a royalty on fee lands and a convertible working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in a 2004 farm-in agreement with ExxonMobil.

 

Revenues

 

Our revenues are sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.

 

Oil and Natural Gas Prices

 

While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market, whereas natural gas, which has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements generally follow local market conditions.

 

Apache primarily sells its natural gas into four markets:

 

 

For specific marketing arrangements by segment, please refer to Item 1 and 2. Business and Properties of this Form 10-K.

Revenues

 

The table below presents oil and gas production revenues, production and average prices received from sales of natural gas, oil and natural gas liquids for the most recent three years.

 

Contributions to Oil and Natural Gas Revenues

 

As with production and reserves, a consequence of geographic diversification is a shifting geographic mix of our oil revenues and natural gas revenues. For the reasons discussed in the Oil and Natural Gas Prices section above, contributions to oil revenues and gas revenues should be viewed separately.

 

The following table presents each segment’s oil revenues and gas revenues as a percentage of total oil revenues and gas revenues, respectively.

 

 

Crude Oil Contribution

 

In 2006, oil revenue contributions outside of North America were 64 percent of our total consolidated oil revenues, equal to 2005 contributions. Except for Australia, all core regions saw oil revenue growth in 2006 when compared to 2005. Egypt and the United States saw their contributions rise as their 2006 revenue gains, relative to 2005, outpaced gains in our other regions, benefiting from both higher relative oil prices and production. Argentina’s contribution increase in 2006, compared to 2005, was virtually all attributable to the 2006 acquisitions discussed above, although the region also benefited from price improvement. The North Sea and Canada’s 2006 contributions fell because higher prices were somewhat neutralized by lower relative production and higher oil revenue in other core areas.

 

In 2005, oil revenue contributions from outside the U.S. rose six percent to 74 percent of our total consolidated oil revenues. Production growth and significantly higher price realizations drove the North Sea’s oil revenue contributions to 29 percent of consolidated oil revenues from 16 percent the prior year and were largely responsible for the growth of non-U.S. oil revenues. U.S. oil revenues made up 26 percent of 2005 oil revenues, down six percent from 2004, a consequence of the 2005 hurricane activity and the significant growth in North Sea production. Australia’s contribution to 2005 consolidated oil revenues fell to seven percent from 13 percent on a 39 percent decrease in production compared to 2004.

 

Crude Oil Revenues

 

Crude oil revenues in 2006 increased $498 million from 2005 to $4.9 billion. Price gains across all regions, which averaged $8.26 more per barrel than 2005, generated an additional $706 million of revenues. These additional revenues were partially offset by the effect on revenues from a four percent decline in production. All segments reported a significant increase in realized crude oil price, with Argentina, Egypt, and the U.S. also benefiting from production growth compared to 2005.

 

Egypt generated an additional $233 million of crude oil revenue in 2006 when compared to 2005. An 18 percent increase in crude oil price realizations, generated $200 million of the additional revenues, with the remainder coming from a three percent increase in production. While Egypt experienced production growth in many areas, the predominate contributor was the Khalda Concession which benefited from a full year of associated condensate related to increased Qasr field gas production.

 

U.S. crude oil revenues for 2006 increased $162 million compared to 2005, with a 13 percent increase in crude oil price realizations contributing $151 million of the additional revenues. A small increase in 2006 oil production, relative to 2005, contributed the remaining $11 million. The third-quarter 2005 hurricanes reduced Apache’s 2006 average annual daily crude oil production 13,100 barrels per day (b/d), compared to 10,813 b/d in 2005. Shut-in production reduced the Company’s 2006 and 2005 crude oil revenues by approximately $297 million and $186 million, respectively. Central region production rose 18 percent, reflecting drilling and recompletion activity in the Permian basin and Southeast New Mexico, and the Amerada Hess acquired properties. Gulf Coast production was 10 percent below 2005 levels with downtime, hurricane production shut-ins and natural decline outpacing growth attributed to drilling and recompletion activity and the BP acquired properties. The Gulf Coast region’s fourth-quarter 2006 production averaged 43,995 b/d compared to 23,487 b/d in the comparable 2005 quarter, a testament to the progress in returning hurricane damaged properties to production during 2006, as well as the benefit of the BP acquired properties.

 

Argentina’s 2006 oil revenues increased $91 million over 2005 with $89 million of the increase associated with production growth, driven primarily by acquired properties and subsequent exploitation activities. Higher oil price realizations generated the other $2 million.

 

The North Sea’s 2006 crude oil revenues were $80 million higher than 2005 with $240 million of additional revenues generated from a 19 percent increase in price realizations, partially offset by lower production, which was down 11 percent on a comparative basis. Production was lower in 2006 primarily because of production interruptions associated with commissioning of major infrastructure projects and temporary unplanned shutdown of the third-party Forties Pipeline System during the third quarter of 2006. The focus in 2006 on upgrades also displaced drilling operations necessary to mitigate natural decline.

 

Canada’s 2006 oil revenues increased $17 million over 2005, with $56 million of additional revenues associated with higher price realizations, partially offset by lower production, which was down eight percent. Canada production was down in most areas as natural decline exceeded drilling and production enhancement activities.

 

Australia’s 2006 crude oil revenues were $27 million less than 2005, reflecting a 23 percent decline in production and an 18 percent increase in realized price. The production decrease resulted from normal field decline which offset a full year of associated condensate production from the John Brookes field and other development activities, mainly in the Bambra, Zephyrus and Stag areas.

 

China’s 2006 oil revenues were $59 million less than 2005, a consequence of the August 2006 divestiture.

 

Apache manages a small portion of its exposure to fluctuations in crude oil prices using financial derivatives. Approximately nine percent of our worldwide crude oil production was subject to financial derivative hedges in 2006, compared to six percent in 2005. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K for a summary of the current derivative positions and terms.) These financial derivative instruments reduced our 2006 and 2005 worldwide realized prices $1.37 and $.68 per barrel, respectively.

 

Natural Gas Contribution

 

Our North American operations contributed 83 percent of 2006 consolidated natural gas revenues, down five percent from 2005. All core gas producing regions generated additional revenues in 2006 on production growth. However, these incremental production revenues were all but eliminated by the effect of lower prices, especially in our North American regions, where prices are typically higher, but more volatile, than our other regions. Revenues in the U.S. and Canada dropped in 2006 on a comparative basis, while all other core gas producing regions experienced an increase in revenue. Egypt’s contribution to 2006 consolidated gas revenues rose three percent in 2006, compared to 2005, while Australia’s contribution increased one percent. Argentina contributed one percent of consolidated gas revenues.

 

In 2005, 88 percent of Apache’s natural gas revenues came from North America, 54 percent from the U.S. and 34 percent from Canada. The U.S. contribution decreased four percent from 2004, primarily because of production declines, the impact Hurricanes Katrina and Rita had on U.S. Gulf of Mexico revenues, and the additional revenues generated by Canada and Egypt. Our U.S. Gulf Coast region, which contributed 63 percent of Apache’s U.S. 2005

production, down six percent from 2004, is characterized by reservoirs which demonstrate high initial production rates followed by steep declines when compared to most other U.S. producing areas. Canada’s contribution was up five percent from 2004 resulting from 14 percent production growth and higher price gains, relative to other areas. Egypt’s contribution to total gas revenues decreased slightly to nine percent from 10 percent in 2004. Australia’s contribution to 2005 natural gas revenues remained the same as 2004 at three percent.

 

Natural Gas Revenues

 

Our 2006 consolidated natural gas revenues increased $73 million from the prior year with $614 million of additional revenues generated from production growth mostly offset by the effect of a 19 percent decline in realized prices. All core gas producing regions generated additional revenues in 2006 from production growth; however they were mostly offset by lower relative natural gas prices.

 

Egypt contributed $73 million more to 2006 consolidated natural gas revenues compared to 2005 on a 31 percent increase in production and a four percent decrease in realized gas prices. The year-over-year production growth came primarily from the Khalda concession, mostly attributable to a full year of production from the Qasr field.

 

Argentina’s 2006 natural gas revenues increased $38 million compared to 2005, with all of the additional revenues associated with production growth. As with oil, the production growth primarily came from acquired properties and subsequent exploitation activities.