UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

Commission file number 1-4300

 

 

APACHE CORPORATION

(Exact name of registrant as specified in its charter)

 

 

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices)

 

Registrant’s telephone number, including area code (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.  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 2009 annual meeting of stockholders have been incorporated by reference in parts II and III hereof.

 

 

PART I

 

 

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. We also have exploration interests 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 23, 2008, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, 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 principal executive officer and our principal 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 free of charge 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. From time to time, we also post announcements, updates and investor information on our website in addition to copies of all recent press releases.

 

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 which we refer in this document may be held by those subsidiaries. We treat all operations as one line of business. References to “Apache” or the “Company” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.

 

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 includes building a balanced portfolio of assets, maintaining financial flexibility, and maximizing earnings and cash flows by controlling costs.

 

We have a portfolio of core areas that provide long-term growth opportunities through organic drilling supplemented by strategic 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. Our international locations provide additional diversity of geologic and geographic risk as well as exposure to larger reserve targets, which fuel production and reserve growth. We have exploration and production operations in six countries, comprising seven regions: the Gulf Coast and Central regions in the United States, Canada, Egypt, the North Sea, Australia and Argentina. We have exploration interests in Chile located adjacent to our Argentine operations in Tierra del Fuego. We have achieved a critical mass in each of our producing regions that support 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. Our acreage positions, which include 39 million gross acres across the globe, also bring ample growth opportunities.

In 2008, we drilled or participated in 1,418 gross wells with an overall 93 percent success rate; 90 percent were developmental and 10 percent were exploratory. We carefully spread our risk among our regions. For instance, no single region contributed more than 23 percent of our production or reserves in 2008. Our multiple geological locations also provide us a mixture in 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 seven years to as long as 27 years.

 

In addition, our goal is to balance our mix of hydrocarbons, which provides some measure of protection against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. In 2008, crude oil and liquids provided 50 percent of our production and 68 percent of our revenue. We were well-positioned to realize the benefit of higher oil prices, which significantly outpaced natural gas price increases for much of the year, despite falling 70 percent from their June 2008 peak. Our year-end estimated proved reserves were balanced at 55 percent natural gas and 45 percent crude oil and liquids.

 

Preserving financial flexibility and a strong balance sheet are also key to our overall business philosophy. We ended 2008 with a debt-to-capitalization ratio of 23 percent, after current year capital investments of $6.3 billion, excluding asset retirement costs. We also had over $1.5 billion of cash and short-term investments. In tightening credit markets, we believe Apache’s single-A debt ratings provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity of four percent and five percent, respectively, was negatively impacted by a non-cash write-down (discussed in Item 7 of this Form 10-K).

 

Another critical component of our overall strategy is maximization of earnings and cash flow. Both are significantly impacted by commodity prices, which fluctuate and are primarily influenced by factors beyond our control, including worldwide supply and demand, political stability and governmental actions and regulations. For example, demand for energy, once thought to be insatiable, waned, driving prices down. Prices began the year strong and soared to unprecedented levels in mid-2008, only to fall rapidly by year-end, as the financial markets and ultimately the world’s economies stalled.

 

We also strive to control costs of both adding and producing reserves. Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flows and motivate appropriate risk taking to reach or exceed targeted hurdle rates of return. Results are measured monthly, reviewed with management quarterly and utilized to determine annual performance awards. We monitor capital allocations, at least quarterly, through a disciplined and focused process of analyzing current economic conditions in each of our regions, internally generated drilling prospects, opportunities for tactical acquisitions or, occasionally, new core areas which could enhance our portfolio. We also 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.

 

The global economic slowdown and decline in oil and gas prices create a difficult operating environment for 2009. In preparation, we have substantially reduced our capital budget for 2009 in an effort to keep our expenditures in line with our cash flow. In 2009, we plan to invest $3.5 to $4.0 billion on capital expenditures, which is 50 percent less than in 2008. Our plan includes investments for drilling and recompleting wells, development projects, waterflood projects, equipment upgrades, production enhancement projects and seismic acquisition. Also included is $300 million for gathering, transmission and processing (GTP) assets and $500 million for plugging and abandonment work, of which $250 million is for damage caused by Hurricanes Katrina, Rita and Ike. 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 plan to step up our search for opportunities to acquire oil and gas properties where we believe we can add value and earn adequate rates of return.

 

During our 54 years in business and throughout the cycles of our industry, these strategies have underpinned 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. We increased reserves 22 out of 23 years and increased production 28 out of the past 30 years, a testament to our longevity. While the business environment in 2009 is likely to be challenging, we believe we are in a strong financial position and are well-positioned to take advantage of what could be some of the most attractive acquisition opportunities in years.

Region Overviews

 

We currently have exploration and production interests in six countries, divided into seven operating regions: the United States (Gulf Coast and Central regions), Canada, Egypt, Australia, offshore the United Kingdom in the North Sea and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego, which we acquired in the second quarter of 2008.

 

The following table sets out a brief comparative summary of certain key 2008 data for each of our operating areas. Additional data and discussion is provided in Item 7 of this Form 10-K.

 

 

United States

 

In the U.S., the Gulf Coast region historically generates high returns on invested capital and cash flow significantly in excess of its exploration and development spending. Occasional acquisitions have played an important role, as steep decline rates mean 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. Apache’s future growth in the U.S. is more likely to be achieved through a combination of drilling and acquisitions than through drilling activity alone.

 

Gulf Coast Region  The region comprises our interests in and along the Gulf of Mexico, in the areas on and offshore Louisiana and Texas. In waters less than 1,200 feet deep in the Gulf of Mexico, Apache is the largest producer and, since 2004, has been the largest held-by-production acreage holder. In 2008, the region contributed approximately 22 percent of our production and approximately 25 percent of our revenues and, at year-end, held approximately 14 percent of our estimated proved reserves.

 

The region had a productive year even though a considerable amount of effort was expended on evacuations and repair related to Hurricanes Gustav and Ike. We drilled 116 wells, 90 of which were completed as producers, and performed 358 workover and recompletions. In June 2008, we had a key discovery at the Geauxpher prospect located on Garden Banks Block 462 in deepwater Gulf of Mexico. Apache generated the prospect and has a 40 percent working interest. Mariner Energy, Inc. is the designated operator of the block with a 60 percent working interest. A delineation well was drilled in December 2008, extending the productive reservoir limits. We project the initial discovery to be online in the second quarter of 2009. Additional potential on the block is expected to be tested by further drilling. At Ewing Banks 826, we completed four wells during the first half of 2008 and increased

production to 6,315 b/d from 700 b/d at the beginning of the year. We own a 100 percent working interest in the field. In addition, significant progress was achieved toward wrapping up remaining abandonments associated with Hurricanes Katrina and Rita in 2005 and repairing damage and restoring shut-in production attributable to Hurricanes Gustav and Ike in 2008.

 

Central Region  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. At year-end 2008, the Central region accounted for approximately 25 percent of our estimated proved reserves, the largest concentration in the Company. During 2008, we participated in drilling 415 wells in the Central region, 404 of which were completed as producers. Apache also performed 1,210 workovers and recompletions in the region during the year.

 

Marketing  In general, most of our U.S. gas is sold 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. Approximately two percent of our 2008 U.S. natural gas production was sold under physical long-term fixed-price contracts, all of which expired 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 crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at market prevailing prices.

 

We manage our credit risk by selling our oil and gas to diverse counterparties and monitoring our exposure on a daily basis.

 

Canada

 

In our Canadian region, we have 4.9 million net acres across the provinces of British Columbia, Alberta and Saskatchewan, which provide a significant inventory of both low-risk development drilling opportunities in and around a number of Apache fields and higher-risk, higher-reward exploration opportunities. In 2008, we drilled 484 wells in Canada, with 471 completed as producers. Three percent of the wells drilled during the year were exploration wells, half of which were productive. We performed 531 workover and recompletion projects. The region comprises approximately 22 percent of our estimated proved reserves, the second largest concentration in the Company.

 

In 2009, we will continue our pursuit of the emerging shale-gas play in northeast British Columbia, where we have over 217,000 highly prospective net acres. Apache completed seven horizontal wells at the Ootla shale-gas play in the Horn River Basin during 2008. The last completed well utilized a 10-stage fracture stimulation. Apache plans to continue to develop the optimum strategy for Ootla well completions in 2009. In addition, we plan to drill exploratory wells to test other emerging plays in both Alberta and northeast British Columbia during 2009.

 

We will also continue to target shallow gas, including coal bed methane (CBM), in the Provost, North Grant Land and Nevis areas. As a result of these efforts, we believe Apache has emerged as one of Canada’s largest producers of CBM. We are also utilizing horizontal well technology to develop waterflood and enhanced oil recovery projects in the Midale field located in southeast Saskatchewan, and the Zama and House Mountain fields located in Alberta. Intermediate depth gas development drilling continues in the Kaybob, West 5 and South Grant Land areas of central and southern Alberta.

 

Marketing  Our Canadian natural gas marketing activities focus on sales to LDCs, utilities, end-users, integrated major oil companies, supply aggregators and marketers. Our composite client portfolio is diverse with the intent of reducing the concentration of credit risk in our portfolio. Improved North American natural gas pipeline connectivity over the years has led to 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. We sell the majority of our Canadian

production on a monthly basis, either into the first- of-the-month market or the daily market. In 2008, approximately two percent of our gas sales were subject to long-term fixed-price contracts with the latest expiration in 2011.

 

Our Canadian crude oil is primarily sold to refiners, integrated major oil companies and marketers. To increase the market value of our condensate and heavier crudes, our condensate is generally 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 oil on 12 pipelines to the major trading hubs within Alberta and Saskatchewan.

 

Egypt

 

Egypt holds our largest acreage position with more than 11 million gross acres, following relinquishments in January 2009, in 23 separate concessions (19 producing concessions) that provide a sizable resource in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from Lower Cretaceous to Jurassic. In addition to being the largest acreage holder in Egypt, we believe that Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert and the third largest in all of Egypt. In 2008, our Egypt region contributed 22 percent of Apache’s production revenue, 21 percent of total production, and 14 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 2008, Apache had an active drilling program in Egypt, completing 236 of 260 wells, a 91 percent success rate, and conducted 701 workovers and recompletions. Historically, our growth in Egypt has been driven by drilling; we are the most active driller in Egypt.

 

In the Khalda concession two additional Salam gas processing trains, three and four, and an associated Apache pipeline compression project on the Western Desert Northern Gas Pipeline are forecasted to add additional net production of 100 MMcf/d and 5,000 b/d when fully operational in the second quarter of 2009. The third processing train commenced operations on December 4, 2008. Commissioning with first gas from the fourth processing train is projected to commence during the first quarter of 2009.

 

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. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries or on a negotiated basis.

 

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 sold directly to EGPC or other third parties. Oil sales are made either directly into the Egyptian oil pipeline grid, exported or sold at one of two terminals on the northern coast of Egypt or sold to non-governmental third parties including the Middle East Oil Refinery located in northern Egypt. Oil production that is presently sold to EGPC is sold on a spot basis at the monthly EGPC quoted price (indexed to Brent). In 2008, we sold 34 cargoes (approximately 10.1 million barrels) of Western Desert crude oil from the El Hamra terminal located on the northern coast of Egypt into the export market. These export cargoes were sold to EGPC at market prices above our domestic sales. Additionally, Apache sold Qarun quality oil (approximately 7.6 million barrels) at the Sidi Kerir terminal, also located on the northern coast of Egypt. This Qarun oil was sold at prevailing market prices into the domestic market to non-governmental purchasers (three million barrels) or exported to buyers in the Mediterranean markets (11

cargoes for approximately 4.6 million barrels). We expect sales to the export market from both the Khalda and Qarun areas in the Western Desert to continue in 2009.

 

Australia

 

Overview — In Australia, our exploration activity is focused in the offshore Carnarvon, Gippsland and Browse basins, where Apache holds 5.2 million net acres in 34 exploration permits, 11 production licenses and five retention leases.

 

Production operations are concentrated in the Carnarvon and Exmouth basins, the location of Apache’s 11 production licenses, all of which are Apache operated. In 2008, the region generated $372 million of production revenues from the sale of 10.5 MMboe, approximately five percent of our total production. Australia held 12 percent of our year-end estimated proved reserves. During the year, the region participated in drilling 46 wells, which generated 25 productive oil wells and nine productive gas wells.

 

Our growth strategy includes development in the Carnarvon basin and in areas adjacent to this core area. As of the end of 2008, our Van Gogh and Pyrenees projects in the Exmouth basin were under active development. We had also initiated a development project related to our 2008 Halyard discovery (discussed below) and began appraising our large Julimar discovery (also discussed below). We completed planned development drilling at our Reindeer field.

 

Van Gogh is Apache-operated, while Pyrenees is operated by BHP Billiton. Van Gogh development drilling and sub-sea production equipment installation is well underway, with first oil production slated for mid-2009 through a floating production storage and offloading tanker. Additional development drilling is planned in 2009 prior to the start of production. Pyrenees development drilling is expected to commence in 2009 with first oil production expected in the first half of 2010. Production from each field is estimated at 20,000 b/d net to Apache.

 

In April 2008, we drilled the Halyard-1 well, which tested 68 MMcf/d of gas and was completed as a producer. The Halyard field is expected to be tied-in to the nearby East Spar gas facilities once a market for the gas is under contract. Apache holds a 55 percent interest in the field. Additional appraisal in 2009 is necessary on the Julimar gas discovery before proceeding with a development plan. Based on current geological mapping, we believe that Julimar could be a multi-Tcf discovery. Apache owns a 65 percent interest in and operates the Julimar-Brunello complex.

 

During the fourth quarter of 2008, Apache completed a three-well development drilling campaign at the Reindeer field. On January 6, 2009, we secured a 154 Bcf, 7-year gas sales contract that allowed us to reinstate our Reindeer development, which was suspended at the end of 2008 program because of a delay in gas sales contract negotiations. Negotiations were delayed by the onset of the global economic crisis and the resulting drop in metal prices. The gas will be supplied through a new 65-mile offshore pipeline and a new onshore gas processing facility at Devil Creek. This sales contract is discussed in more detail below under “Subsequent Events.” Construction of pipeline and processing infrastructure is scheduled to commence in 2009 with first production anticipated in 2011. Apache owns a 55-percent interest in the field.

 

We are currently evaluating the results of wells drilled in 2008 and seismic information to assess the future potential in the Gippsland basin. All six wells drilled in 2008 were either dry or non-commercial.

 

Varanus Island — On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia, which shut-in production from the John Brookes field and Harriet Joint Venture. When fully operational, the Island’s operations process approximately 195 MMcf/d and 5,400 b/d, net to Apache subsidiaries. On August 5, 2008, partial production was reestablished from the John Brookes field and by year-end was at greater than 80 percent pre-incident levels. The Harriet Joint Venture gas facilities are located adjacent to the pipeline explosion and required more significant repairs to restore operation. A portion of the gas production from the Harriet Joint Venture was restored in December 2008 and is projected to be fully restored in the first half of 2009. Harriet Joint Venture oil production is projected to be fully restored in the first quarter of 2009. The John Brookes field accounted for approximately 60 percent and 25 percent of the island’s pre-incident natural gas and oil production, respectively. Production from the Harriet Joint Venture accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production,

respectively. Company subsidiaries operate the facilities and own a 68.5 percent interest in the Harriet Joint Venture and a 55 percent interest in the John Brookes field. Company subsidiaries maintain replacement cost insurance, subject to a deductible of approximately $7 million, with adequate limits to cover fully their share of the estimated cost of restoring the Varanus Island facilities.

 

During 2009, our Australian region plans to focus on its major field development projects and, to a lesser extent, its exploration and appraisal activities.

 

Marketing  As of December 31, 2008, Apache had a total of 18 active gas contracts in Australia with expiration dates ranging from March 2010 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 crude oil prices, which typically track at or above New York Mercantile Exchange (NYMEX) oil prices.

 

North Sea

 

Apache entered the North Sea in 2003 upon acquiring an approximate 97 percent working interest in the Forties field (Forties). Our drilling program and continued improvements in plant efficiencies led to an 11 percent increase in 2008 production. We expect to increase our North Sea production in 2009 relative to 2008. We also have several targeted facilities projects planned for 2009 to further improve the efficiency of our operations in the North Sea.

 

In 2008, the North Sea region produced 21.9 MMboe, approximately 11 percent of our total production, generating slightly more than $2.1 billion of revenue and accounting for approximately eight percent of our year-end estimated proved reserves. In 2008, we invested $459 million in the North Sea on drilling and recompleting wells and facility enhancement programs. We drilled 14 wells in the North Sea during 2008, 12 of which were producers. We completed and commissioned a number of key projects in the North Sea region during 2008, including replacing the key import header on the Charlie platform that services the field export system, high-pressure gas-lift compression projects on the Alpha and Delta platforms, a large produced water reinjection system on the Charlie platform and replacement of the infield pipeline between the Bravo and Charlie platforms. Investments in facility upgrades and integrity-related projects over the past five years have continually increased the efficiency of our operations.

 

Drilling successes and improved platform operating efficiencies led to fourth-quarter 2008 production of 61,740 b/d. During 2008, production averaged 59,494 b/d. The 2008 annual maintenance shut down on the Charlie platform impacted the field by 1,330 b/d, which was an improvement compared to 2,270 b/d impact in 2007. The new import header on the Charlie platform enabled the platform to be shut in for planned maintenance activities without impacting production export operations from the other field platforms.

 

Marketing  In 2008, we entered into two new term contracts for the physical sale of Forties crude at prevailing market prices. These term sales are composed of base-market indices, adjusted for the quality difference between the Forties crude and Brent, with a premium to reflect the higher market value for term arrangements. In addition to the term sales, Apache sold 11 spot cargoes of approximately 600,000 barrels each and received value at or above the prevailing market prices.

 

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 (TdF) from Pan American for $429 million. With the addition of Mendoza CCyB Block 17B in 2008, our oil and gas assets are located in the Neuquén, Austral and Cuyo basins of Argentina. While Argentina presents unique challenges with evolving governmental regulations, we are optimistic about our ability to find additional hydrocarbons with the drill bit and to grow our reserves and production over the long-term.

In 2008, our Argentina region continued its broad drilling and recompletion programs. The region drilled 83 wells, 72 of which were productive. We produced 17.5 MMboe in 2008, which accounted for nine percent of Apache’s total production. Argentina holds approximately five percent of our total estimated proved reserves.

 

In December 2008, the Mendoza Province granted Apache an exploration permit for CCyB Block 17B in the Cuyo basin, increasing our Argentine acreage by 34 percent. The block is adjacent to and along a trend of existing producing fields.

 

We also completed a nearly 2,500 square kilometer three-dimensional (3-D) seismic mega shoot in Tierra del Fuego. which aided in the identification of prospects and increased Apache’s ability to drill productive wells. In the Austral Basin of Tierra del Fuego, Apache made discoveries on operated blocks in which we own a 70 percent working interest, including the San Sebastian area, where Apache successfully drilled three kilometers from the shore to test a new separate oil structure in the San Sebastian field. Apache also discovered a new field, Sección Veintinueve, and a field extension to the Sara Norte field. Apache believes that the new 3-D seismic survey will continue to generate an inventory of drilling prospects.

 

On the mainland, we continued our drilling and recompletion campaigns in our established gas areas in the Neuquén basin. We drilled 11 new wells in our Estacion Fernandez Oro field, 10 new wells in our Guanaco field including a new deeper gas pool and 9 new wells in our Ranquil Co field, with a success rate of 100 percent. Apache plans to continue drilling in each of these fields in 2009. We also drilled a successful exploratory well on our Collon Cura exploration lease, fulfilling our license obligations.

 

Marketing  In 2008, 52 percent of our natural gas portfolio was regulated based upon certain market segments. We realized an average price of $.92 per Mcf on sales to regulated market segments in 2008. The remaining free market volumes were sold either on a monthly or daily basis or under term contracts, some of which extend through 2009. The average price received for free market volumes during the fourth quarter 2008 was $2.28 per Mcf, versus a fourth-quarter 2007 price of $2.32, a decrease of two percent primarily because of lower spot price sales in Tierra del Fuego.

 

Taxes on exported oil effectively limits prices buyers are willing to pay for domestic sales. Domestic oil prices are currently based on $42 per barrel, plus quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, the price cap applies, but Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. In 2008, we received an average price of $49.46 per barrel for crude oil.

 

Chile

 

In November 2007, Apache was awarded exploration rights on two blocks comprising one million net acres in Tierra del Fuego, following a bid round. This acreage is adjacent to our 552,000 net acres on the Argentine side of the island of Tierra del Fuego, and the additional acreage represents a natural extension of our expanding exploration and production operations. In 2008, Apache finalized the contracts with the Chilean government in July and shot a 3-D seismic survey. In 2009, we plan to process and interpret this seismic data in order to validate prospects and identify initial drilling locations.

 

Major Customers

 

In 2008, purchases by Shell accounted for 17 percent of the company’s oil and gas production revenues.

 

Subsequent Events

 

Australian Gas Sales Contract  On January 6, 2009, Apache signed a contract to supply natural gas from its Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. Apache and its joint venture partner agreed to supply 154 billion cubic feet of gas over seven years, beginning in the second half of 2011. Apache owns a 55-percent interest in the field.

The gas will be supplied through a new, 65-mile offshore pipeline and a new onshore sales gas processing facility at Devil Creek, about 28 miles southwest of Dampier, with capacity to process 210 MMcf/d. Apache plans to sell additional production from the Reindeer field to other domestic customers in Western Australia.

 

The contract price for the first three years is a fixed price adjusted periodically for changes in the Australian consumer price index. Beginning in the fourth year, the price is indexed to international oil prices. At an oil price of $50 per barrel, Apache’s net share of the revenue over the seven years of the contract would be approximately $700 million.

 

The gas sales agreement will not take effect unless Apache and its joint venture partner sign contracts for engineering and procurement of the gas plant and pipeline by mid-March 2009 (or a later date if agreed by all parties).

 

Management Changes  On January 15, 2009, Raymond Plank retired as Chairman of the Board, a director, and an employee of Apache. Mr. Plank founded Apache in 1954 and had served as an officer of the Company since 1954 (President and/or Chief Executive Officer from 1954 to 2002 and Chairman of the Board since 1979). He had been a director of the Company since 1954. G. Steven Farris, Apache’s president, chief executive officer and chief operating officer since 2002, succeeded Mr. Plank as chairman.

 

Also on January 15, 2009, Apache and Mr. Plank entered into an amendment and restatement of his employment agreement dated December 5, 1990, pursuant to which he agreed to provide consulting services to the Company for the remainder of his life.

 

On February 12, 2009, Mr. Farris formed an office of the chief executive with three key executives reporting to him. Messrs. Roger B. Plank, John A. Crum and Rodney J. Eichler were appointed to new positions effective as of February 12, 2009. Mr. Roger Plank now serves as president, Mr. Crum serves as co-chief operating officer and president — North America, and Mr. Eichler serves as co-chief operating officer and president — International. Although Messrs. Roger Plank, Crum and Eichler have separate functional responsibilities, they have joint and equal roles in the daily decision-making and direction of Apache. Mr. Farris continues to serve as chairman and chief executive officer of Apache and has resigned from his positions of president and chief operating officer of Apache effective February 12, 2009. Mr. Farris continues to serve as Apache’s principal executive officer and, in his new role as president, Mr. Roger Plank continues to serve as Apache’s principal financial officer.

 

Canadian Gas Pipeline Contract  On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from northeastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.

 

The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. We expect to receive authority to construct the pipeline, and construction is expected to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment to ship 100 MMBtu/d for either a four-year period or a ten-year period, depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to CDN $90 million plus certain taxes.

 

Drilling Statistics

 

Worldwide, in 2008, we participated in drilling 1,418 gross wells, with 1,319 (93 percent) completed as producers. We also performed more than 2,800 workovers and recompletions during the year. Historically, our drilling activities in the U.S. have generally concentrated 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: 91 in the U.S. (56.3 net); 10 in Canada (9.7 net); 36 in Egypt (33.5 net); 2 in Australia (1.6 net); 2 in the North Sea (1.9 net); and 9 in Argentina (8.7 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, 2008, 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, 2008, we had 4,933,430, 3,270,055 and 8,474,094 net acres scheduled to expire by December 31, 2009, 2010 and 2011, respectively, if production is not established or we take no other action to extend the terms. Approximately two million net acres (four million gross acres) of the 2009 expiration total expired in Egypt in January 2009. 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, 2008, Apache had total estimated proved reserves of 1,081 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 14.4 Tcf of natural gas. As a result of prices in effect at the end of 2008, we experienced significant negative revisions to our reserves, causing 2008 to be the first year in the last 23 in which reserves did not grow.

 

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 that is 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. These properties represented all material fields, approximately 90 percent of international properties and over 80 percent of each country’s reserve value for new wells drilled during the year. During 2008, 2007 and 2006, Ryder Scott’s review covered 82, 77 and 75 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 the tests and procedures used during its 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. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his or her own.

 

The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2008, 2007 and 2006, 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 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.

 

In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting” (Modernization). The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements become effective for Apache’s Annual Report on Form 10-K for the year ended December 31, 2009.

 

Employees

 

On December 31, 2008, we had 3,639 employees.

 

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 2008, 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, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. 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 that 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 and the carrying value of our properties 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. These prices have historically 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.

 

Under the full-cost method of accounting as allowed by the SEC, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. The Company recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of the ceiling test limitations. If oil and gas prices deteriorate from the Company’s year-end realized prices, it is likely that additional write-downs will occur in 2009.

 

A downgrade in our credit rating could negatively impact our cost of and ability to access capital

 

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long-term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in

the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances.

 

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition

 

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.

 

These factors, combined with volatile oil, natural gas and NGLs prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors, suppliers and customers ability to continue operations, and ultimately, adversely impact our results of operations, liquidity and financial condition.

 

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks

 

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

 

The credit risk of financial institutions could adversely affect us

 

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Continued deterioration in the credit markets may continue to impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

 

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage

 

A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to

change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

 

Our ability to sell natural gas and/or receive market prices for our gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions

 

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

 

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 as a result of 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.

 

We may not realize an adequate return on wells that we drill

 

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:

 

 

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.

 

We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves

 

Although we perform a review of properties that we acquire 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 us as a buyer to become sufficiently familiar with the properties to assess fully and accurately 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 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. New political developments, laws and regulations may adversely impact our results on operations.

 

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 46 percent of our 2008 production was outside North America and approximately 39 percent of our estimated proved oil and gas reserves on December 31, 2008 were located outside North America. As a result, a significant portion of our production and resources are subject to increased political and economic risks and other factors including, but 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 in which we operate 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 investments such as ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our 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.

 

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 estimated and actual timing of critical events may adversely affect our 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 exchange rates may adversely affect our results of operation, particularly through the weakening of the U.S. dollar relative to other currencies.

 

Weather and climate may have a significant adverse impact on our revenues and productivity

 

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact 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. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather, and not all such effects can be predicted, eliminated or insured against.

 

We may incur significant costs related to environmental matters

 

As an owner or lessee and operator of oil and gas properties, we 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. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

 

We face strong industry competition that may have a significant negative impact on our result of operations

 

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 marketing of oil and natural gas production. Crude oil and natural gas prices impact 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 fluctuating worldwide commodity 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. These competitive pressures may have a significant negative impact on our results of operations.

 

Our insurance policies do 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. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

 

 

As of December 31, 2008, 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 of this Form 10-K which is incorporated herein by reference.

 

 

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

 

PART II

 

 

During 2008, 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 2008 and 2007. 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 of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 30, 2009 (last trading day of the month), was $75.00 per share. As of January 31, 2009, there were 334,753,638 shares of our common stock outstanding held by approximately 6,000 stockholders of record and approximately 448,000 beneficial owners.

 

We have paid cash dividends on our common stock for 44 consecutive years through December 31, 2008. 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, which 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 2009 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, 2003 through December 31, 2008.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among 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, 2008, 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. As discussed in more detail under Item 15, the 2008 numbers in the following table reflect a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of ceiling test limitations.

 

 

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

 

 

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 operations 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 operations onshore Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea), and onshore Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.

 

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Item 8 of this Form 10-K, and the Risk Factors information, which are set forth in Item 1A of this Form 10-K.

 

Overview

 

Apache’s 2008 results were significantly impacted by several events:

 

 

 

 

Crude Oil and Natural Gas Prices

 

The oil and gas industry as a whole experienced a year of extremes during 2008. Crude oil and natural gas prices climbed precipitously in the first half of the year, only to pull back in the third quarter before collapsing in the fourth quarter. Apache monthly average realized prices during the summer reached $118.38 per barrel and $9.12 per thousand cubic feet (Mcf). Our December average realized prices were $36.45 per barrel and $4.75 per Mcf. February 2009 indices indicate that prices are trending below December’s averages as the global economy and demand continue to weaken.

 

Crude Oil and Natural Gas Production

 

Apache’s 2008 consolidated production declined five percent from 2007 on a barrel of oil equivalent (boe) basis. Our production would have increased over 2007 levels had it not been for the impact of the following:

 

 

Earnings and Cash Flow

 

From an earnings perspective, we had our historical best and worst quarters ever, just one quarter apart. The fourth-quarter price collapse and associated $3.6 billion non-cash after-tax write-down nearly eliminated 2008 nine-month earnings that totaled $3.7 billion dollars or $10.84 per common diluted share. The write-down reduced earnings for the year to $706 million, or $2.09 per share.

Record commodity prices in the first half of 2008 drove record cash provided by operating activities of $7.1 billion and record oil and gas revenues of $12.4 billion, both of which were unaffected by the write-down. They were, however, affected by falling commodity prices, most notably in the fourth quarter of 2008. Key financial indicators for each quarter and the year of 2008 are noted below:

 

 

 

 

Operating and Drilling Costs

 

Costs were a challenge for Apache and our industry in 2008 and are expected to remain so in 2009. Drilling, service and acquisition costs, which have increased steadily since the industry’s last downturn in 2001, reached unprecedented levels in 2008. Also, in the U.S., activity to repair damage caused by Gulf of Mexico hurricanes over the last few years has contributed to increased demand and costs. Even though we have seen a sharp drop in commodity prices, costs have fallen less rapidly pressuring operating margins. We believe costs will ultimately adjust to the current oil and gas price environment, but until they do, our operating margins and drilling costs will continue to be pressured.

 

Financial Position and 2009

 

We believe we are well positioned to take advantage of opportunities that will invariably present themselves in the current business environment. We enter 2009 with a debt-to-capitalization ratio of 23 percent, after consideration of the non-cash write-down. We had over $1.5 billion in cash and short-term investments and $2.3 billion availability on our lines of credit at the close of the year. In a tightening credit market, we believe Apache’s single-A debt ratings will provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity were four percent and five percent, respectively, after taking into effect the $5.3 million non-cash write-down.

 

In 2009, we are projecting production growth driven by multi-year projects coming on-line during the year (discussed below in Operational Highlights). We plan to hold our capital expenditures, currently planned at 50 percent below 2008 spending levels, in line with our operating cash flows. We will continue to monitor capital spending closely based on actual and projected cash flow estimates and intend to scale back spending further should commodity prices remain at current levels or fall further.

 

For an in-depth discussion of Apache’s long-term growth strategy, please refer to Part 1, Items 1 and 2. Business and Properties of this Form 10-K.

 

Full-Cost Accounting and 2008 Write-down in Net Oil and Gas Property Assets

 

The Company follows the full-cost method of accounting as allowed by the Securities and Exchange Commission (SEC). Under the full-cost method of accounting, a ceiling test must be performed each quarter, for each country. The test establishes a limit (ceiling), on the carrying value of proved oil and gas properties. This carrying value (net book value and the related deferred income taxes) may not exceed the ceiling. The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, excluding future

expected cash outflows associated with settling asset retirement obligations accrued on the balance sheet. The estimate of after-tax future net cash flows is discounted at 10 percent per annum and calculated using both commodity prices and costs in effect at the end of the period, held flat for the life of the properties, except where future oil and gas sales are covered by physical contract terms or by derivative instruments that qualify, and are accounted for, as cash flow hedges. If capitalized costs (carrying value) exceed this limit, the excess is charged to expense and reflected as additional Depletion, Depreciation and Amortization (DD&A) during the period.

 

In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting,” which will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new rule becomes effective for the quarter ended December 31, 2009. See Note 1— Summary of Significant Accounting Policies in this Form 10-K.

 

Despite record realized prices and record revenues for 2008, the low oil and gas prices in effect at the end of the year resulted in an aggregate $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties. If oil and gas prices fall below year-end levels, additional write-downs of oil and gas properties may occur. See Note 1 — Summary of Significant Accounting Policies in this Form 10-K.

 

Operating Highlights

 

We made considerable operational progress during the year, which we believe adds to our platform for long-term profitable growth in spite of hurricanes in the Gulf of Mexico and a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia. Key operational highlights include:

 

U.S. Gulf Coast

 

Gulf Coast focused on an active drilling program and restoring production impacted by the 2005 and 2008 hurricanes. In addition to drilling wells, the region also performed 358 workover and recompletion operations during 2008. Significant events affecting Gulf Coast operations include:

 

Development Projects

 

 

Exploration Projects

 

 

Hurricanes

 

 

Production — Wells shut-in as a result of the hurricanes reduced 2008 production by an estimated 54.6 MMcf/d and 6,941 b/d. A substantial part of Apache’s net production shut-in by the storm was restored by the end of 2008, with only 7,700 b/d and 83 MMcf/d remaining offline. While we plan to restore nearly all of the production by mid-year 2009, the timing in many instances is beyond our control since we

are awaiting repairs to third-party pipelines and facilities. All but approximately 1,100 boe per day of production will ultimately be restored.

 

Financial Results — The impact of the hurricanes on our 2008 financial results was an estimated $410 million of lower crude oil and natural gas revenues. We also incurred approximately $75 million of expenditures for repair, redevelopment and abandonment of properties damaged by the hurricanes. The Company anticipates an additional $170 to $190 million of costs, most of which are likely to occur in 2009. A majority of these costs will be recovered through insurance, as discussed below.

 

Insurance Coverage — The Company carries property damage insurance through Oil Insurance Limited (OIL) for windstorm damage in the Gulf of Mexico of $250 million after reaching a $100 million deductible per event. The deductible will be scaled down based on the Company’s working interest in the damaged properties and is anticipated to be $80 million. The $250 million in coverage will be prorated downward if total claims received by OIL for Hurricane Ike exceed their aggregate limit per event of $750 million. In December 2008, OIL indicated that losses for Hurricane Ike will likely exceed the aggregate limit by an amount that would cause insurance payments to be 80 percent of amounts claimed; however, the final percentage will not be known until all claims have been submitted to OIL. In addition, Apache has $150 million of property damage and business interruption insurance through the London market subject to a $350 million deductible that can be met with property damage and qualifying business interruption losses.

 

Egypt

 

In Egypt, we had a steady stream of significant discoveries during the year across basins and plays, completing 236 of 260 wells for a 91-percent success rate. The region also conducted 701 workovers and recompletions and made significant progress on the completion of several major growth projects that will underpin future production growth. Notable successes during the year include:

 

Development Projects

 

 

Exploration Discoveries

 

 

 

Australia

 

In Australia, we had two notable discoveries, the Halyard-1 and Brulimar-1 as well as continued appraisal success at Julimar and Bambra. We also progressed on several major long lead-time development growth projects, including the Van Gogh and Pyrenees developments. In the Julimar-Brunello area on Australia’s Northwest Shelf, we drilled three successful appraisal wells that will allow us to pursue a development strategy after completing our assessment of commercial options. Also, our subsidiaries made considerable progress in restoring operations at the Varanus Island gas processing and transportation hub, which sustained damage from a gas pipeline explosion in June 2008. Lastly, on January 6, 2009, we secured a 154 Bcf, seven-year gas sales contract that enabled us to reinstate our Reindeer development program. These discoveries and developments are discussed in more detail below.

 

Development and Appraisal Projects

 

 

Exploration Discoveries

 

 

Varanus Island

 

 

Canada

 

During 2008, the Canadian region had an active development drilling program and commenced pursuit of an emerging shale-gas play in northeast British Columbia. Notable activities during the year include:

 

Exploration Projects

 

 

Development Projects

 

 

North Sea

 

Throughout 2008, the North Sea region invested in drilling and recompleting wells and facility enhancement programs. Key activities include:

 

Development Projects

 

 

Argentina

 

During 2008, the Argentina region pursued active drilling and recompletion programs. In total, the region drilled 83 wells, 72 of which were productive. Significant activities include:

 

Development Projects

 

 

Exploration Projects

 

 

Chile

 

 

Results of Operations

 

Revenues

 

 

Oil and Natural Gas Prices

 

Crude Oil Prices — A substantial portion of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Apache’s oil realizations climbed precipitously in the first half of the year reaching a record $118.38 per barrel in June, before collapsing in the fourth quarter. Our realized oil price in December averaged nearly 70 percent lower than June’s peak, as demand for energy dropped following the onset of the global financial crisis. Apache manages a portion of its exposure to fluctuations in crude oil prices, primarily in North America, using financial instruments. In 2008, the 19 percent of our oil production that was subject to financial derivative hedges reduced revenues by $451 million, which comprised a $472 million loss in the first nine months and a $21 million gain in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.

 

While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market. With the exception of Argentina, price movements for all types and grades of crude oil generally move in the same direction. In Argentina, we are currently selling our oil in the domestic market. The Argentine government previously imposed a sliding-scale tax on oil exports, which effectively limits prices buyers are wiling to pay. Domestic oil prices are currently based on a $42 per barrel price, subject to quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar price formulas exist, but producers retain value-added tax collected from buyers, effectively increasing price realizations by 21 percent.

 

Natural Gas Prices — Natural gas, which has a limited global transportation system, is subject to price variances stemming from 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 its exposure to fluctuations in natural gas prices, primarily in North America, including fixed-price contracts and derivatives. In 2008, the 20 percent of our gas production that was subject to financial derivative hedges reduced revenues by $8 million, which comprised a $29 million loss for the first nine months and a gain of $21 million in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.

 

Apache primarily sells natural gas into four markets:

 

1) North America, which has a common market and 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 gas price of $2.65 per MMbtu. On up to 100 MMcf/d gross, there is no price cap for our gas under a legacy contract which expires in 2013.

 

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. Subsequent to year-end, however, Apache signed a contract on 85 bcf (net) that is indexed to oil prices following an initial period of fixed prices.

 

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 $.92 per Mcf on government regulated sales. The majority of the remaining volumes were sold at market-driven prices, which exceeded $2.00 per Mcf at year-end. Our average price for 2008 was $1.61 per Mcf.

 

For specific more information on marketing arrangements by country, please refer to Item 1 and 2, “Business and Properties” of this Form 10-K.

 

Production and Pricing