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 þ     No o

 

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 o     No þ

 

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 þ     No o

 

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.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Portions of registrant’s proxy statement relating to registrant’s 2008 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 (U.K.) in the North Sea (North Sea), and onshore Argentina. In November 2007, we were high bidder on two exploration blocks on the Chilean side of the island of Tierra del Fuego. 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 2004. On May 24, 2007, 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, free of charge, 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 filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. 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 reasonably practicable after we file such material with, or furnish it to, 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. Our reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

 

We hold interests in many of our United States (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.

 

Growth Strategy

 

Apache’s mission is to grow a profitable upstream oil and gas company for the long-term benefit of our shareholders. Our strategy is to build a portfolio of core areas which provide long-term growth opportunities through grass-roots drilling supplemented by occasional acquisitions. Two decades ago, recognizing that the United States was a mature oil and gas province, we launched an international exploration component to our portfolio approach, which provides exposure to larger reserve targets with which to continue production and reserve growth. We have producing operations in six countries, comprised of seven regions — the United States (Gulf Coast and Central regions), Canada, Egypt, the North Sea, Australia and Argentina. We are finalizing contracts for two exploration blocks in Chile. We seek to grow profitably while building critical mass that supports sustainable, lower-risk, repeatable drilling opportunities. This enables us to pursue higher-risk, higher-reward exploration primarily in our international regions; particularly our growth areas of Australia, Canada and Egypt. We also seek a balance in terms of product mix and geologic and geographic risk, in order to achieve consistency in our results. As a testament to our balanced portfolio approach Apache increased production for the 28^th out of 29 years and reserves for the 22^nd consecutive year.

 

Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems motivate appropriate risk taking to reach or exceed targeted hurdle rates of return. These are measured monthly, reviewed quarterly with senior management and utilized in

determining annual performance rewards. Apache is also one of the leading acquirers of three-dimensional (3-D) seismic data in the industry today. Our geophysical personnel 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, generate drilling prospects on an accelerated timetable and lessen drilling risk.

 

In 2008, we are planning another active year of drilling and have set a preliminary exploration and development budget of approximately $4.6 billion, or nine percent more than 2007. Our 2008 plan also includes just under $400 million for gathering, transmission and processing (GTP) assets. As is our custom, we will review and revise our capital expenditure estimates throughout the year based on changing industry conditions and results-to-date. Additionally, we continually look for opportunities to acquire producing oil and gas properties where we believe we can add value and earn adequate rates of return and may take advantage of such acquisition opportunities should they arise.

 

North America

 

In the U.S., the Gulf Coast region consistently delivers high returns on invested capital and cash flow significantly in excess of its exploration and development spending. Occasional acquisitions have played an important role because with steep decline rates, offshore reserves are generally shorter-lived and difficult to replace on a cost effective basis through drilling alone. The Central region brings the balance of long-lived reserves and consistent drilling results to the portfolio in the areas of the Permian basin of West Texas and New Mexico, East Texas and the Anadarko basin of western Oklahoma. Apache’s future growth in the U.S. is more likely to be achieved through a combination of drilling and acquisitions, rather than through drilling activity alone. Our March 2007 $1 billion acquisition of properties in the Permian basin, for example, complimented our active drilling program in 2007, buttressed our growth in the U.S. and brought numerous opportunities to increase future production through workovers, recompletions and drilling.

 

In Canada, we have five million net acres across the provinces of British Columbia, Alberta and Saskatchewan. We have a significant inventory of low-risk drilling opportunities in and around a number of Apache fields in Alberta, including Provost, Hatton, Nevis, Kaybob and West 5. With significant increases in Canadian acquisition and land costs, our 2004 and 2005 agreements with Exxon Mobil Corporation (ExxonMobil) provide a way for Apache to earn acreage through drilling with no upfront costs, while ExxonMobil retains a royalty on fee lands and a convertible working interest on leasehold acreage. We also have emerging resource plays in the gas bearing shales of Northeast British Columbia (NEBC), where we have now acquired 200,000 highly prospective net acres, and in the Manville coals of central Alberta. A recent ill-conceived change in Alberta royalty rates will limit our investment there, primarily to shallow drilling activity and divert investments to Saskatchewan or British Columbia.

 

International

 

In Egypt’s Western Desert, Apache’s 18.9 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. The Qasr gas and condensate field, discovered in 2003, is the largest ever found by Apache with ultimate recoverable reserves of an estimated 2.25 Tcf of gas and 80 MMbbls of associated liquids. Apache’s gas production is restricted because Western Desert infrastructure is at capacity. Two new gas trains will add 100 MMcf/d of capacity each and are currently under construction with completion slated for around year-end 2008. Our historical growth in Egypt has been driven by drilling and Apache is the most active driller in Egypt.

 

In Australia, Apache’s recent expansion beyond our core holdings in the Carnarvon basin is beginning to pay off. In the Exmouth basin, development of prior-year discoveries at the Van Gogh and Pyrenees fields, sanctioned in 2007, is progressing. The Van Gogh development is operated by Apache and the Pyrenees development is operated by BHP Billiton. Production from each field is estimated at 20,000 b/d net to Apache. Van Gogh development drilling has commenced with first oil production expected in the first half of 2009. Pyrenees development drilling is expected to commence in 2009 with first oil production expected in 2010. In the Gippsland basin, we acquired nearly 1.5 million net acres over the past several years and have generated an inventory of high-risk, high-potential exploration prospects with drilling to commence in 2008. Development drilling at the Reindeer discovery and the construction of pipeline and processing infrastructure is scheduled to commence in 2008 with first production

anticipated in 2010. The Julimar gas discovery, which could potentially surpass the size of the Qasr field in Egypt, will be further appraised in 2008 in order to begin work on a development plan.

 

Apache is also the beneficiary of strong demand for Carnarvon basin natural gas where industry prices have recently risen to a multiple of Apache’s Australian $1.89 per Mcf average price in 2007. Apache is currently in the tender process for its gas from the Reindeer field and expects to complete negotiations during 2008 on initial contracts. Apache also anticipates tendering Julimar gas to market in 2008.

 

Apache entered the North Sea in 2003 acquiring an approximately 97 percent working interest in the Forties field (Forties), the largest field ever discovered in the U.K. Production decreased eight percent in 2007 but was still well ahead of our 28,800 b/d proved acquisition forecast. Production was impacted by suspension of drilling on the Alpha and Echo platforms for facility upgrades. We plan an active 15-well program in 2008 which is forecasted to increase production over 2007. We will also drill two exploration wells and one appraisal well on blocks outside Forties. 2008 will also mark the completion of a number of key facility projects such as installation of new gas lift compression equipment on both the Alpha and Delta platforms and new produced water handling and reinjection facility on Charlie, as well as an enhanced crude oil import-export header system designed to significantly impact the reliability and operating efficiency of the field.

 

For several years we held small interests in Argentina with a long-term view of expanding there through acquisitions. In April 2006, we purchased Pioneer Natural Resources’ (Pioneer) interests in Neuquén and the Austral basins and in September 2006 purchased our partner’s, Pan American Fueguina S.R.L. (Pan American), interests in Tierra del Fuego (TdF), gaining operatorship in the under-exploited, highly prospective Austral basin concessions. 2007 was a year of significant accomplishments. We increased production on the acquired properties through a successful drilling and development program and have established Argentina as Apache’s latest core area. We made the first significant oil discovery from our 3-D seismic work in TdF which came online producing approximately 1,600 b/d and 1.3 MMcf/d. We were able to increase our gas price over 20 percent from 2006 with the prospect of signing more spot contracts for around $3.00 per Mcf. 2007 was not without its challenges as the government placed a ceiling on oil prices in the fourth quarter that effectively caps our oil price at $42.00 per barrel when the WTI price is $60.90 or greater. In TdF, the price cap applies but Apache retains the 21 percent Value Added Tax collected from buyers, effectively increasing realized prices. While Argentina presents unique challenges with evolving governmental regulations, we are optimistic about our ability to find additional hydrocarbons with the drill bit and growing our reserves and production over the long-term.

 

Operating Highlights

 

We currently have production in six countries: the United States (Gulf Coast and Central regions), Canada, Egypt, Australia, offshore the United Kingdom in the North Sea and Argentina. We are finalizing contracts for two exploration blocks in Chile.

The following table sets out a brief comparative summary of certain key 2007 data for each area. Each country’s production and average sales prices for 2007, 2006, and 2005 are in this section under “Production, Pricing and Lease Operating Cost Data.” See also Item 7 — Management’s Discussion and Analysis of Financial Condition, Note 12 — Supplemental Oil and Gas Disclosures (Unaudited) and Note 11 — Business Segment Information of this Form 10-K.

 

 

The following discussions include references to our plans for 2008. These only represent initial estimates and could vary significantly from actual results. 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 has been the largest held-by-production acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep since 2004. For the ninth consecutive year, the Gulf Coast was our leading region for both production volumes and revenues. In 2007 the region contributed close to 25 percent of our production and 27 percent of our revenues. Gulf Coast activities in 2007 focused on an active drilling program, completing 65 out of 84 total wells drilled as producers, and restoring production impacted by the 2005 hurricanes. This region performed 233 workover and recompletion operations during 2007. At year-end 2007, the Gulf Coast region accounted for approximately 15 percent of our estimated proved reserves. Although actual annual capital expenditures may change considerably in 2008, we currently estimate investing approximately $900 million on drilling, recompletions, equipment upgrades, production enhancement projects and seismic. In addition, we plan to spend an estimated $400 million on plugging and abandonment work, including $250 million associated with damage caused by Hurricanes Katrina and Rita in 2005.

 

Central — The Central region includes assets in East Texas, the Permian basin of West Texas and New Mexico, and the Anadarko basin of western Oklahoma and the Texas Panhandle, where the Company got its start over 50 years ago. In early 2007, we acquired an additional $1 billion of producing properties in the Permian basin. At year-end 2007, the Central region accounted for approximately 26 percent of our estimated proved reserves, the largest concentration in the Company. During 2007, we participated in drilling 343 wells, 335 of which were completed as productive. Apache also performed 994 workovers and recompletions in the region during the year. We currently estimate spending approximately $660 million in 2008 on drilling, recompletions and production enhancement projects.

Marketing — In general, most of our U.S. gas is sold based on 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. Approximately five percent of our 2007 U.S. natural gas production was sold under long-term fixed-price physical contracts which expire in 2008. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk “Commodity Risk” in this Form 10-K.

 

Apache primarily markets 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 best markets and most economical transportation routes available to move the crude oil. Sales contracts are generally 30-day evergreen contracts and renew automatically until canceled by either party. These contracts provide for sales that are priced daily at market prevailing prices. In 2007, we entered several multi-month contracts in order to reduce the transportation cost component of these contracts.

 

We manage our credit risk by selling our oil and gas 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 minor degree the Northwest Territories. The region comprises 23 percent of our estimated proved reserves, the second largest in the Company. We hold five million net acres in Canada, the largest of our North American regions. This year we drilled 348 wells with 287 completed as producers. Exploration wells comprised 9 percent of the net wells drilled, up from six percent in 2006. We performed 478 workover and recompletion projects. We currently estimate spending approximately $600 million in 2008 to drill 394 wells. Our 2008 drilling program will include 358 low-risk development wells and 36 higher risk, higher potential exploration wells in NEBC and Alberta.

 

Apache continues to target shallow gas including coal bed methane (CBM) in fields such as Provost and Nevis and through these efforts 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. Also in 2008 we will continue our pursuit of the emerging shale gas play in NEBC, where we have now acquired over 200,000 highly prospective net acres, with a nine well winter drilling program.

 

Apache signed farm-in agreements in 2004 and 2005 with ExxonMobil covering over one million acres of undeveloped properties in the province of Alberta. Under the agreements, Apache drilled to earn an interest in the land while ExxonMobil retained a royalty on fee lands and a convertible working interest on leasehold acreage. Through the end of 2007, Apache had drilled a total of 751 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 creditworthy and diverse. Improved North American natural gas pipeline connectivity has triggered a closer correlation between Canadian and U.S. 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. In 2007, approximately two percent of our gas sales were subject to long-term fixed-price contracts, the longest of which expires in 2011.

 

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 oil and natural gas liquids (NGLs) on crude oil 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 Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is the largest acreage holder and the most active driller in Egypt. Egypt holds our largest acreage position with approximately 18.9 million gross acres in 23 separate concessions (19 producing concessions) as of December 31, 2007. 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 and third largest in all of Egypt. Egypt contributed 20 percent of Apache’s production revenues and 18 percent of total production in 2007 and approximately 12 percent of total estimated proved reserves. 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 2007, Apache had an active drilling program in Egypt, completing 161 of 192 wells, an 84 percent success rate, and conducted 450 workovers and recompletions. We currently plan to spend approximately $1 billion in 2008; $700 million on drilling nearly 300 wells, recompletions and production enhancement projects and $300 million on gathering, transmission and processing facility projects. In 2006 we received approval to expand our Western Desert gas processing capacity and infrastructure to process an additional 200 MMcf/d primarily from the Qasr field discovery. Work commenced in 2007 and we expect incremental production from the expansion to begin late in the fourth quarter of 2008.

 

Marketing — Our gas production is sold to EGPC under an industry pricing formula, 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 the industry pricing formula on a majority of gas sold, but retained the previous gas price formula (without a price cap) until 2013 for up to 100 MMcf/d gross.

 

Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is either sold directly to EGPC or other third-parties. 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 2007, we exported 32 cargoes (approximately 9.8 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 at or above our domestic sales to EGPC. Additionally, 28 cargoes representing 3.7 million barrels were sold in Egypt to other non-governmental purchasers at prevailing market prices. We expect export sales from both the Khalda and Qarun areas in the Western Desert will continue in 2008.

 

Australia

 

Overview — Our exploration activity in Australia is focused in the offshore Carnarvon, Gippsland and Browse basins where Apache holds 5.4 million net acres in 31 Exploration Permits, 10 Production Licenses, and 5 Retention Leases. Production operations are concentrated in the Carnarvon basin, the location of all 10 Production Licenses, all of which are operated by Apache. In 2007, the region generated $536 million of production revenues from 16.9 MMboe, approximately eight percent of our total production, and accounted for 11 percent of our year-end estimated proved reserves. During the year we participated in drilling 24 wells; generating eight productive gas wells and two productive oil wells.

 

During 2008, our Australian region plans to increase its exploration, appraisal and field development activities. Twenty-four exploration wells are expected to be drilled in 2008, targeting gas opportunities in the highly prospective Julimar-Brunello area, in the Carnarvon basin and prospects in the Gippsland basin, which targets both oil and gas opportunities. Two new development projects were sanctioned in 2007. Van Gogh, operated by Apache, is an oil discovery in the Exmouth basin that will be produced through a Floating Production Storage and Offloading tanker (FPSO) beginning in early 2009 with Apache’s share estimated at 20,000 b/d. We plan to drill 13 wells in the Van Gogh field in 2008 while work progresses on the FPSO and subsea components. Pyrenees, the second project and also in the Exmouth basin, is operated by BHP Billiton (BHP). This field will also be produced through an

FPSO and should commence production in 2010 at an estimated 20,000 b/d net to Apache. Work will continue on the Reindeer gas discovery in the Carnarvon basin, with gas to be piped to shore for processing at a new gas plant located at Devil’s Creek beginning in 2010. Two development wells are planned for the field in 2008.

 

In 2008, we currently estimate spending approximately $550 million on 48 wells and production enhancement projects and another $350 million on new development facilities at Van Gogh, Pyrenees and Reindeer.

 

Marketing — As of December 31, 2007, Apache had a total of 21 active gas contracts with expiration dates ranging from July 2008 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 international markets at prices indexed to Asian benchmark crudes which typically track at or above NYMEX WTI prices.

 

North Sea

 

Overview — In 2007, the North Sea region produced 19.7 MMboe, generating $1.4 billion of revenue. 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. In the Forties field, we commissioned a number of key facility projects, including new power generation and multi-platform gas and power distribution systems, export pumping, produced water handling and injection systems and drilling rig package upgrades.

 

These efforts have already shown to be successful as operating efficiencies improved 11 percent relative to 2006. Despite an improvement in topsides efficiency, 2007 production was down eight percent from 2006. Workovers to restore production on the Echo platform progressed slower than planned, and new drilling was postponed on the Alpha platform to complete facility upgrades. Production from each of the other three platforms in the field (Bravo, Charlie, and Delta) increased in 2007 compared to 2006.

 

In 2007 we invested $538 million of capital in the North Sea region, including investments in drilling, recompletion and facility upgrades. The region drilled 16 wells in 2007, five of which were productive. Three exploration wells were drilled outside Forties but did not find commercial hydrocarbon accumulations. Also during 2007, a seismic survey acquired over Forties in 2005 was reprocessed to identify bypassed oil in the main reservoir units and enabled us to update the inventory of future drilling targets.

 

North Sea capital expenditures for 2008 are currently estimated at $500 million. In Forties, we will continue the development drilling program with 15 new wells planned and completion of several platform facility upgrades initiated last year. The upgrades for 2008 include finalizing the installation of a produced water handling and re-injection system on the Charlie platform, new gas lift compression systems on Alpha and Delta, replacement of glycol dehydration systems and upgrades to lower voltage electrical systems. Outside Forties, at least one appraisal and two exploration wells are planned to be drilled during the year.

 

Marketing — In 2007, we entered into one new term contract for the physical sale of Forties crude at prevailing market prices, which are composed of base market indices, adjusted for the quality difference between the Forties crude and Brent and a premium to reflect the higher market value for term arrangements. In 2006, a new value adjustment formula (Quality Bank Adjustment) 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 new agreed upon formula better represents Apache’s crude value in the Forties Pipeline System.

 

Argentina

 

Argentina became our latest core area following two significant acquisitions in 2006 that substantially increased our presence in the country. In the second quarter of 2006, 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 of 2006, we acquired additional interests in (and now operate) seven concessions in Tierra del Fuego 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 2007, we recorded 17.4 MMboe of

production and at year end had 112.0 MMboe of estimated proved reserves, approximately eight percent and five percent, respectively, of Apache’s total production and reserves.

 

In 2007 Apache completed over 1,700 square kilometers of a nearly 2,500 square kilometer 3D seismic mega shoot in Tierra del Fuego. The program will be completed in 2008.

 

On the mainland, we established the commerciality of two gas areas in the Neuquén Basin, each operated by Apache with a 100 percent working interest. In the Anticlinal Campamento block, Apache completed five Pre Cuyo “Deep Gas” wells. In our Estacion Fernandez Oro block we completed four wells and established commerciality of the “Deep Lajas” gas play. We are encouraged by the results and foresee the potential of 150 new drilling locations.

 

In Tierra del Fuego, Apache made two significant discoveries on operated blocks in which we own a 70 percent working interest. In our Cabo Nombre Sur area, we drilled two wells directionally into a new reservoir structure. In our Seccion Banos area, we discovered a new field between two mature fields five miles apart. We believe we have sufficient drilling locations to utilize our shallow rig for the remainder of 2008 and are evaluating mobilizing another rig to the province.

 

In total, the region drilled 94 wells, 92 of which were productive. In 2008, Apache plans to invest $250 million drilling 100 wells and performing recompletion activities. The region also plans to invest an additional $40 million on waterfloods and expanded production facilities.

 

Marketing — In Argentina, we receive low government-regulated pricing on a substantial portion of our gas production. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. We extended our exisiting natural gas contracts to regulated markets through year-end 2011, per the Argentine Secretary of Energy’s request. We also entered into three new term gas contracts up to five years in duration for volume up to 35 MMcf/d. During the year, we realized an average price of $.76 per Mcf on government-regulated sales. The majority of the remaining volumes were sold at market-driven prices, in excess of $2.00 per Mcf at year-end.

 

In October 2006, the Argentine government removed the export tax exempt status previously afforded the province of Tierra del Fuego through a Special Customs area exemption. The government further assessed an export tax on all gas exports from Argentina based upon the price paid for natural gas imports from Bolivia. This tax reduced the value we receive under our contract with Methanex in Chile, however, we entered into an interim agreement with Methanex to mitigate the effects of this tax. Subsequent to the interim agreement, the Government of Argentina prohibited further gas exports to Methanex. Apache notified Methanex in June 2007 of the existence of force majeure, which continues to prevent deliveries of gas pursuant to the Methanex contract. The Methanex contract represents less than 10 percent of our gas sales in Argentina.

 

We are currently selling our oil in the domestic market. The government imposed a sliding-scale tax on oil exports which effectively limits the amount we are able to receive in the domestic market to a parity price equivalent to the price of exported crude oil after adjusting for the export taxes. Effective November 19, 2007, the export tax regulations were further modified and now include a cap of $42.00 per barrel when WTI is $60.90 or greater. In TdF, the price cap applies but Apache retains the 21 percent Value Added Tax collected from buyers, effectively increasing realized prices.

 

Chile

 

In November 2007, Apache was awarded the exploration rights on two blocks comprising one million net acres in Tierra del Fuego at a bid round. This acreage is adjacent to our 552,000 net acres on the Argentinean side of Tierra del Fuego and represents a natural extension of our expanding exploration and production operations. Apache is finalizing the contracts with the Chilean government and plans to shoot 3-D seismic in 2008.

 

Subsequent Events

 

In January 2008, Apache, BP plc and Chevron Corporation entered into a contract with Well Control, Inc. to decommission downed platforms and related well facilities located offshore Louisiana in the Gulf of Mexico for a fixed fee of $750 million. Apache’s portion is 37.5 percent.

On January 29, 2008, the Company completed the sale of its 50 percent interest in Ship Shoal blocks 349 and 359 on the Outer Continental Shelf of the Gulf of Mexico to W&T Offshore, Inc. for $116 million.

 

On January 31, 2008, the Company completed the sale of properties in the Permian basin of West Texas and New Mexico to Vanguard Permian, LLC for $78 million.

 

On February 14, 2008, Apache’s Board of Directors declared a special cash dividend of 10 cents per common share payable on March 18, 2008, to stockholders of record on February 26, 2008. The regular dividend on the common shares is payable on May 22, 2008, to stockholders of record on April 22, 2008, at the rate of 15 cents per share.

 

On February 28, 2008, nine days of the 10-day requirement for the $108 threshold of the Company’s 2005 Share Appreciation Plan have been met and 14 trading days remain in the current 30-day period. This plan provides incentives for employees to double Apache’s share price to $108 by the end of 2008. See Note 7 — Capital Stock of Item 15 in this Form 10-K.

 

Drilling Statistics

 

Worldwide, in 2007, we participated in drilling 1,101 gross wells, with 955 (87 percent) completed as producers. We also performed more than 4,048 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: 62 in the U.S. (28.49 net); 14 in Canada (13.69 net); 29 in Egypt (27.95 net); three in Australia (2.17 net); one in the North Sea (0.98 net); and 17 in Argentina (16.4 net).

The following table shows the results of the oil and gas wells drilled and completed 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, 2007, 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 expenses per boe (including severance and other taxes and transportation costs) 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, 2007, we had 4,294,752, 1,868,688 and 4,803,317 net acres scheduled to expire by December 31, 2008, 2009 and 2010, 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.

 

Estimated Proved Reserves and Future Net Cash Flows

 

As of December 31, 2007, Apache had total estimated proved reserves of 1,134 MMbbls of crude oil, condensate and NGLs and 7.9 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.4 billion barrels of oil equivalent or 14.7 Tcf of natural gas. During 2007, the Company’s reserves grew six percent, the 22nd consecutive annual increase.

 

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 productivity 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.

 

The estimate of reserves disclosed in this Annual Report on Form 10-K are prepared by the Company’s internal staff and the Company is responsible for the adequacy and accuracy of those estimates. However, we engage Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. We selected the properties for review by Ryder Scott and these properties represented all material fields, approximately 88 percent of international properties and over 80 percent of each country’s reserve value for new wells drilled during the year. During 2007, 2006 and 2005, Ryder Scott’s review covered 77, 75 and 74 percent of the Company’s worldwide estimated reserves value, respectively.

 

Ryder Scott opined that the overall proved reserves for the reviewed properties as estimated by the Company are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles, and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. Ryder Scott has informed the Company that their tests and procedures used during their reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information approved by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the

classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities.

 

The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2007, 2006 and 2005, 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 12 - Supplemental Oil and Gas Disclosures 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, 2007, we had 3,521 employees. Only 24 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 2007, 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 table in Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity,” and Note 9 — Commitments and Contingencies 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, and are likely to remain volatile in the future. A significant and extended 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. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices adversely affects our financial position.

 

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 declines, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

 

Hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or the counterparties to our future contracts fail to perform under the contracts. We cannot assure that our hedging transactions will reduce the risk or minimize the effect of any decline in crude oil or natural gas prices.

 

Acquisitions or discoveries of additional reserves are needed to avoid a material decline in reserves and production

 

The production rate from oil and gas properties generally declines as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery reserves, or acquire additional properties containing proved 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 on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.

 

Inherent risk in drilling

 

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. 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

 

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.

 

Our North American operations are subject to governmental risks that may impact our operations

 

Our North American 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 or gathering rate controls and environmental protection laws and regulations.

 

International operations have uncertain political, economic and other risks

 

Our operations outside North America are based primarily in Egypt, Australia, the United Kingdom and Argentina. On a barrel equivalent basis, approximately 44 percent of our 2007 production was outside North America and approximately 36 percent of our estimated proved oil and gas reserves on December 31, 2007 were located outside North America. As a result, we face political and economic risks and other uncertainties that are more prevalent than our North American operations. Such factors include, but are not limited to:

 

 

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests

could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.

 

The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

 

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.

 

The Company also purchases multi-year commercial political risk insurance contracts from highly rated international insurers covering portions of its investments in Egypt and Argentina. The insurance provides coverage for confiscation, nationalization, and expropriation risks and currency inconvertibility. Effective March 23, 2007, the Company entered into an additional multi-year insurance contract with OPIC to provide $200 million of coverage for Egypt in excess of the commercial insurance program.

 

We have limited control over the activities on properties we do not operate

 

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

 

Material differences between the estimated and actual timing of critical events may affect the completion and commencement of production from development projects

 

We are involved in several large development projects whose completion may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners; timely issuances of permits and licenses by governmental agencies; weather conditions; manufacturing and delivery schedules of critical equipment; and other unforeseen events. Delays and differences between estimate and actual timing of critical events may adversely affect our forward looking statements related to large development projects, and our ability to participate in large scale development projects in the future.

 

Our operations are sensitive to currency rate fluctuations

 

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar with the Canadian dollar, the Australian dollar and the British Pound. Our financial statements, presented in U.S. dollars, are affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchanges rates may adversely affect our results of operation, particularly by a weakening U.S. dollar relative to other currencies.

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 or cyclones offshore Australia, 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. Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. 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.

 

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 $300,000.

 

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 9 — Commitments and Contingencies of Item 15, in this Form 10-K, on December 31, 2007, we had an accrued liability of $28 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 the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than 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.

 

 

As of December 31, 2007, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

 

 

See the information set forth in Note 9 — Commitments and Contingencies of Item 15.

 

 

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

 

 

During 2007, 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 2007 and 2006. 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, 2008, was $95.36. On January 31, 2008, there were 332,991,134 shares of our common stock outstanding held by approximately 7,000 shareholders of record and approximately 363,000 beneficial owners.

 

We have paid cash dividends on our common stock for 43 consecutive years through December 31, 2007. 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 7 — Capital Stock of Item 15 in this Form 10-K.

 

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 2008 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 & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2002 through December 31, 2007.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Amont Apache Corporation, S&P 500 Index

and the Dow Jones US Exploration & Production Index

 

 

 

 

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2007, 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.

 

 

Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.

 

Executive Overview

 

Apache Corporation (Apache or the Company) is one of the largest independent (non-integrated) oil and natural gas upstream companies in the United States (U.S.). At Apache, we strive to generate competitive returns and build a profitable oil and gas company for the long-term benefit of our shareholders using the following strategy:

 

 

A key part of our strategy is balancing our portfolio through diversity of geological risk, political risk, hydrocarbon mix (crude oil versus natural gas) and reserve life in order to achieve consistency in results. Our portfolio of geographic locations provides variation of all of these factors and, additionally, in the case of Australia and Argentina, the potential for increasing the value of our investments through rising natural gas prices. We currently have operations in the United States (Central and Gulf Coast regions), Canada, Egypt, the United Kingdom sector of the North Sea, Australia and Argentina. We are finalizing contracts for two exploration blocks in Chile. Each region has a significant producing asset base as well as large undeveloped acreage positions which

provide room for growth. In 2007, no single region contributed more than 26 percent of our production or reserves. We seek to maintain diversity of reserve life, which translates into balance in the timing of returns on our investments. Reserve life (estimated reserves divided by annual production) in our regions ranges from as short as six years to as long as 20 years. By maintaining a balanced hydrocarbon mix, we are protecting against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. For example, in 2007, oil and liquids provided 47 percent of our production, but 65 percent of our total oil and gas revenues. We were well positioned to realize the benefit of higher oil prices, which significantly outpaced natural gas price increases. At year-end, our estimated proved reserves were also balanced at 54 percent natural gas and 46 percent crude oil and liquids. Additionally, in each region, we have attained a critical mass that supports sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. In 2007, we drilled, or participated in, 1,101 gross wells with an overall 87 percent success rate; 89 percent were developmental and 11 percent exploratory.

 

We believe our balanced portfolio strategy enhances our ability to deliver long-term production growth, increase proved reserves at a reasonable economic cost and achieve competitive investment rates of return for the benefit of our shareholders. Our management and incentive systems underscore high cash flow and appropriate risk taking to reach or exceed targeted hurdle rates of return on invested capital. These are measured monthly, reviewed with management quarterly and utilized to determine annual performance awards. We review capital allocations, at least quarterly, through a disciplined and focused process of reviewing internally generated drilling prospects, opportunities for tactical acquisitions, land positions with additional drilling prospects or, occasionally, new core areas which could enhance our portfolio. We continue to deliver strong results with 2007 return on capital employed and return on equity of 16 percent and 20 percent, respectively. Also in 2007, we increased reserves for the 22^nd consecutive year and production for the 28^th of the last 29 years, a testament to our balanced portfolio approach.

 

We periodically evaluate our properties to determine whether sales of certain assets could provide opportunities to redeploy our capital resources to rebalance our portfolio and enhance prospective returns. As a result of this process, in 2007 we sold non-strategic oil and gas properties located in northwest Louisiana for approximately $56 million and contracted to sell others for approximately $309 million. The assets under contract are expected to close in the first quarter of 2008.

 

Preserving financial flexibility is key to our overall business philosophy. We ended 2007 with a year-end debt-to-capitalization ratio of 22 percent, despite current year capital investments of $5.8 billion, excluding asset retirement costs. In tightening credit markets, Apache’s single-A debt ratings provide a competitive advantage in accessing capital.

 

The third critical component of our overall strategy is maximization of earnings and cash flow. Both are significantly impacted by commodity prices, our ability to economically add reserves through drilling and acquisitions, and controlling costs to add and produce reserves. Commodity prices fluctuate and are influenced by factors beyond our control, including worldwide supply and demand, political stability and governmental actions and regulations. While historically high prices have increased our oil and gas revenues in 2007, they also led to increased industry competition and consequently rising costs. Drilling, operating and administrative costs continue to increase from both inflationary pressures from higher commodity prices and the weakened U.S. dollar. We have experienced additional cost increases, particularly in the U.S., with higher demand resulting from activity to repair damage caused by the 2005 Gulf of Mexico hurricanes. Increased demand for producing oil and gas properties has also resulted in higher acquisition prices. We closely monitor drilling and acquisition cost trends in each of our core areas relative to product prices and, when appropriate, adjust our capital budgets accordingly. In addition, we

actively seek to identify and pursue alternatives to maintain efficient levels of costs and expenses. Despite pressure from rising costs, 2007 pre-tax margins were our second highest on record. We calculate pre-tax margins as follows:

 

 

Operating Highlights

 

We made considerable operational progress during the year which we believe adds to our platform for long-term profitable growth. Key operational highlights include:

 

U.S. Central

 

 

U.S. Gulf Coast

 

 

Canada

 

 

Egypt

 

 

Australia

 

 

 

North Sea

 

 

Argentina

 

 

Chile

 

 

Financial Highlights

 

In 2007, records were achieved in the key financial measures of earnings, cash flow, revenues, production and year-end estimated reserves. Financial highlights for 2007 relative to 2006 include:

 

 

Results of Operations

 

Revenues

 

 

Oil and Natural Gas Prices

 

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 market, small variations in either supply, 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.

 

While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market. Generally, price movements for all types and grades of crude oil move in the same direction. Apache manages a portion of its exposure to fluctuations in crude oil prices using financial instruments.

 

In Argentina, we are currently selling our oil in the domestic market. The government imposed a sliding-scale tax on oil exports which effectively limits the amount we are able to receive in the domestic market to a parity price equivalent to the price of exported crude oil after adjusting for export taxes. Effective November 19, 2007, the export tax regulations were further modified and now include a cap of $42.00 per barrel when WTI is $60.90 or greater. In TdF, the price cap applies but Apache retains the 21 percent Value Added Tax collected from buyers, effectively increasing realized prices.

 

Natural gas, which has a limited global transportation system, is more subject to local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices. Apache uses a variety of strategies to manage our exposure to fluctuations in natural gas prices including fixed-price contracts and derivatives.

 

Apache primarily sells natural gas into four markets:

 

1) North America, which has a common market and where supply and demand are currently tightly balanced; creating a volatile pricing environment where most of our gas is sold on a monthly or daily basis at either monthly or daily market prices.

 

2) Egypt, where the majority of our gas is sold to Egyptian General Petroleum Corporation (EGPC) under an industry pricing formula indexed to Dated-Brent crude oil with a maximum price of $2.65 per MMbtu. Apache has retained the previous gas price formula (without a price cap) until 2013 on up to 100 gross MMcf/d.

 

3) Australia, which has a local market with mostly long-term fixed-price contracts that are periodically adjusted for changes in Australia’s consumer price index.

 

4) Argentina, where we receive low government-regulated pricing on a substantial portion of our production. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. During the year, we realized an average price of $.76 per Mcf on government regulated sales. The majority of the remaining volumes were sold at market-driven prices, in excess of $2.00 per Mcf at year-end.

 

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

Production and Pricing