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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-K
 
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
    For the fiscal year ended December 31, 2010
     
    OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number 1-4300
 
APACHE CORPORATION
(Exact name of registrant as specified in its charter)
 
     
Delaware
(State or other jurisdiction of incorporation or organization)
  41-0747868
(I.R.S. Employer Identification No.)
 
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:
 
     
    Name of Each Exchange
Title of Each Class   On Which Registered
 
Common Stock, $0.625 par value
  New York Stock Exchange,
Chicago Stock Exchange and
    NASDAQ National Market
Preferred Stock Purchase Rights
  New York Stock Exchange and
Chicago Stock Exchange
Apache Finance Canada Corporation
  New York Stock Exchange
7.75% Notes Due 2029
   
Irrevocably and Unconditionally
Guaranteed by Apache Corporation
   
Depositary Shares Representing a 1/20th
   
Interest in a Share of 6.00% Mandatory
  New York Stock Exchange
Convertible Preferred Stock, Series D
   
 
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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  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.  þ
 
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):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
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
 
         
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2010
  $ 28,439,311,280  
Number of shares of registrant’s common stock outstanding as of January 31, 2011
    382,752,217  
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of registrant’s proxy statement relating to registrant’s 2011 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.
 


 

 
TABLE OF CONTENTS
 
DESCRIPTION
 
                 
Item       Page
 
 
PART I
  1.     BUSINESS     1  
  1A.     RISK FACTORS     21  
  1B.     UNRESOLVED STAFF COMMENTS     32  
  2.     PROPERTIES     1  
  3.     LEGAL PROCEEDINGS     32  
  4.     [REMOVED AND RESERVED]     32  
 
PART II
  5.     MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS     33  
  6.     SELECTED FINANCIAL DATA     35  
  7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     36  
  7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     67  
  8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     70  
  9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     70  
  9A.     CONTROLS AND PROCEDURES     70  
  9B.     OTHER INFORMATION     70  
 
PART III
  10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT     71  
  11.     EXECUTIVE COMPENSATION     71  
  12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT     71  
  13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS     71  
  14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES     71  
 
PART IV
  15.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K     72  
 EX-10.14
 EX-10.15
 EX-12.1
 EX-14.1
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-99.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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DEFINITIONS
 
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document:
 
“3-D” means three-dimensional.
 
“4-D” means four-dimensional.
 
“b/d” means barrels of oil or natural gas liquids per day.
 
“bbl” or “bbls” means barrel or barrels of oil.
 
“bcf” means billion cubic feet.
 
“boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
“boe/d” means boe per day.
 
“Btu” means a British thermal unit, a measure of heating value, which is approximately equal to one Mcf.
 
“LIBOR” means London Interbank Offered Rate.
 
“LNG” means liquefied natural gas.
 
“Mb/d” means Mbbls per day.
 
“Mbbls” means thousand barrels of oil.
 
“Mboe” means thousand boe.
 
“Mboe/d” means Mboe per day.
 
“Mcf” means thousand cubic feet of natural gas.
 
“Mcf/d” means Mcf per day.
 
“MMbbls” means million barrels of oil.
 
“MMboe” means million boe.
 
“MMBtu” means million Btu.
 
“MMBtu/d” means MMBtu per day.
 
“MMcf” means million cubic feet of natural gas.
 
“MMcf/d” means MMcf per day.
 
“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.
 
“NYMEX” means New York Mercantile Exchange.
 
“Oil” includes crude oil and condensate.
 
“PUD” means proved undeveloped.
 
“SEC” means United States Securities and Exchange Commission.
 
“Tcf” means trillion cubic feet.
 
“U.K.” means United Kingdom.
 
“U.S.” means United States.
 
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.


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PART I
 
ITEMS 1 AND 2.   BUSINESS AND PROPERTIES
 
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Part II, Item 7A — Forward-Looking Statements and Risk of this Form 10-K.
 
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. We currently have exploration and production interests in seven countries: the U.S., Canada, Egypt, Australia, offshore the United Kingdom in the North Sea, Argentina, and Chile.
 
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 25, 2010, 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 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 U.S., Canadian and other international properties through subsidiaries. Properties to 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 global exploration and production company in a safe and environmentally responsible manner for the long-term benefit of our stockholders. Apache’s long-term perspective has many dimensions, with the following core strategic components:
 
  •  balanced portfolio of core assets;
 
  •  conservative capital structure; and
 
  •  rate of return focus.
 
Throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production and reserve growth and achieve competitive investment rates of return for the benefit of our shareholders. We have increased reserves 22 out of the last 25 years and production 30 out of the past 32 years, a testament to our consistency over the long-term.


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Apache pursues opportunities for growth through exploration and development drilling, supplemented by occasional strategic acquisitions. In the years immediately prior to 2010, we were relatively absent from the acquisition market. We believed the market was overheated as oil and gas prices spiked, and the opportunities we identified did not meet our criteria for risk, reward, rate of return and/or growth potential. We built our cash position while drilling from our existing inventory of prospects and waiting for the right transactions to add to our portfolio. During 2010 we completed more than $11 billion in acquisitions and made significant progress with exploitation on existing core properties.
 
The current-year acquisitions fit well with our long-term strategy of maintaining a balanced portfolio of core assets. They included high-quality assets with a diversity of geologic and geographic risk, product mix and reserve life. The properties are strategically positioned with our existing infrastructure and play to the strengths that come with our experience operating in the Permian Basin, Canada and Gulf of Mexico (GOM). The Mariner merger also provided a strategic position in the deepwater GOM, which is relatively under explored and oil prone and gives Apache exposure to significant domestic oil reserves. The transactions drove a 42 percent, or 10 million acre, year-over-year increase in our undeveloped gross acres, adding to our inventory of future drilling and exploration opportunities.
 
2010 Acquisitions
 
North America
 
Shelf acquisition  On June 9, 2010, Apache completed the acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation for $1.05 billion.
 
Mariner merger  On November 10, 2010, Apache completed the acquisition of Mariner Energy, Inc. for stock and cash consideration totaling $2.7 billion. We also assumed approximately $1.7 billion of Mariner’s debt with the merger.
 
Permian acquisition  On August 10, 2010, we completed the acquisition of BP plc’s (BP) oil and gas operations, acreage and infrastructure in the Permian Basin for $2.5 billion, net of preferential rights to purchase.
 
Canadian acquisition  On October 8, 2010, we completed the acquisition of substantially all of BP’s upstream natural gas business in western Alberta and British Columbia for $3.25 billion.
 
International
 
Egyptian acquisition  On November 4, 2010, we completed the acquisition of BP’s assets in Egypt’s Western Desert for $650 million.
 
Balanced Portfolio of Core Assets
 
A cornerstone of our long-term strategy is balancing our portfolio of assets through diversity of geologic risk, geographic risk, hydrocarbon mix (crude oil versus natural gas), and reserve life in order to achieve consistency in results. Our portfolio of geographic locations provides variation of all of these factors. We have exploration and production operations in seven countries, spanning five continents: the Gulf Coast, Permian and Central regions of the U.S., Canada, Egypt, the U.K. North Sea, Australia, Argentina and on the Chilean side of the island of Tierra del Fuego. Our 2010 acquisitions added to our asset base in the United States, Canada, and Egypt.
 
In addition, each of our producing regions has achieved an economy of scale providing a vehicle for cost-effective base production and a combination of lower- and medium-risk drilling opportunities. The net cash provided by operating activities (cash flows) generated by our current production base funds our drilling and development capital program, giving us the ability to pursue new exploration targets over our 35 million gross undeveloped acres across the globe and develop our pipeline of exploration discoveries. Those developments will fund the next round of exploration activities and development programs.
 
In 2010:
 
  •  No single region contributed more than 28 percent of our equivalent production or revenue.
 
  •  No single region held more than 26 percent of our year-end estimated proved reserves.


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  •  The mixture of reserve life (estimated reserves divided by annual production) in our countries, which translates into balance in the timing of returns on our investments, ranges from as short as five years to as long as 25 years.
 
Our balanced product mix provides a measure of protection against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. In 2010 crude oil and liquids provided 52 percent of our production and 77 percent of our revenue.
 
  •  At year-end our estimated proved reserves were 44 percent crude oil and liquids and 56 percent natural gas.
 
  •  Our international gas portfolio, which accounted for 19 percent of our 2010 worldwide equivalent production, positions us to take advantage of increasing prices in Argentina and Australia.
 
Conservative Capital Structure
 
Maintaining a strong balance sheet and financial flexibility is a core strategic component of our long-term strategy. We believe our balance sheet, and the financial flexibility it provides, is one of our most important strategic assets. Maintaining a strong balance sheet underpins our ability to weather commodity price volatility and has enabled us to deliver long-term production and reserves growth throughout the cycles of our industry. It is also key in positioning us to pursue value-creating acquisitions when opportunities arise, as they did in 2010.
 
We exited 2010 with a debt-to-capitalization ratio of 25 percent, an increase of only one percent despite current year capital investments of $17 billion, and $2.4 billion of available committed borrowing capacity.
 
Rate of Return Focus
 
Another core component to our long-term strategy is focusing on rate-of-return. We do so through centralized management and incentive systems, decentralized decision making, strict cost control, and the creative application of technology.
 
Our centralized management and incentive systems provide a uniform process of measuring success across Apache. They incentivize high rate-of-return activities but allow for appropriate risk-taking to drive future growth. Results of operations and rates of return on invested capital are measured monthly, reviewed with management quarterly, and utilized to determine annual performance awards. We review capital allocations, at least quarterly, utilizing estimates of internally-generated cash flow. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rates of return on internally-generated drilling prospects, opportunities for tactical acquisitions, land positions with additional drilling prospects or, occasionally, new core areas that could enhance our portfolio.
 
We also use technology to reduce risk, decrease time and costs and maximize recoveries from reservoirs. Apache scientists and engineers have been granted numerous patents for a range of inventions, from systems used for interpreting seismic data and processing well logs to improvements in drilling and completion techniques.
 
One such example is a manifold developed for our Horn River Shale gas play in northeast British Columbia, where Apache is employing pad-drilling technology. Apache engineers developed and applied for a patent on a manifold that can connect all horizontal wells on a single pad, driving down costs by reducing non-productive time on our 24-hour-a-day hydraulic fracturing operations. This technology will reduce costs and increase Apache’s rate of return on potentially thousands of future wells across our leasehold.
 
At our Forties field in the North Sea, Apache is using techniques that bring together many sources of data to give an accurate view of the current state of the field and identify likely places to find unswept oil deposits. Four-dimensional modeling, which uses reservoir engineering data and a series of 3-D seismic surveys, is utilized by Apache to create a time-lapse picture that shows where oil remains after more than 35 years of production. The latest model of the reservoir highlights the potential for stranded oil accumulations and enhances the success of the ongoing drilling program as well as identifies new potential drilling locations.
 
For a more in-depth discussion of our 2010 results and the Company’s capital resources and liquidity, please see Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.


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Geographic Area Overviews
 
We currently have exploration and production interests in seven countries: the U.S., Canada, Egypt, Australia, offshore the United Kingdom in the North Sea, Argentina, and Chile.
 
The following table sets out a brief comparative summary of certain key 2010 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.
 
                                                         
                            Percentage
    2010
    2010 Gross
 
          Percentage
          12/31/10
    of Total
    Gross
    New
 
          of Total
    2010
    Estimated
    Estimated
    New
    Productive
 
    2010
    2010
    Production
    Proved
    Proved
    Wells
    Wells
 
    Production     Production     Revenue     Reserves     Reserves     Drilled     Drilled  
    (In MMboe)           (In millions)     (In MMboe)                    
 
United States
    84.7       35 %   $ 4,300       1,304       44 %     410       388  
Canada
    30.5       13       1,074       757       26       182       173  
                                                         
Total North America
    115.2       48       5,374       2,061       70       592       561  
                                                         
Egypt
    59.0       24       3,372       307       10       204       177  
Australia
    28.9       12       1,459       314       11       31       23  
North Sea
    20.9       9       1,606       155       5       20       12  
Argentina
    16.0       7       372       116       4       56       52  
Other International
                                  1       1  
                                                         
Total International
    124.8       52       6,809       892       30       312       265  
                                                         
Total
    240.0       100 %   $ 12,183       2,953       100 %     904       826  
                                                         
 
North America
 
Apache’s North American asset base comprises the Gulf Coast, Permian and Central regions of the U.S. and its operations in Canada. In 2010 our North America assets contributed 48 percent of our production and 44 percent of our oil and gas production revenues. At year-end 70 percent of our estimated proved reserves were located in North America.
 
United States
 
Overview  We have 9.7 million gross acres across the U.S., approximately half of which is undeveloped. Approximately 30 percent of the undeveloped acreage is held-by-production. Our U.S. assets are located in the Gulf Coast, Permian and Central regions. The three regions provide our U.S. asset base with a balance of hydrocarbon mix and reserve life. In 2010 48 percent of our U.S. production and 58 percent of our U.S. year-end reserves were oil and liquids. In addition, the reserve life of our U.S. regions ranged from nine to 30 years with the Gulf Coast region’s shorter-lived reserves balancing longer-lived reserves in the Central and Permian regions. In 2010 35 percent of Apache’s equivalent production and 44 percent of Apache’s total year-end reserves were in the U.S.
 
Gulf Coast Region  Our Gulf Coast assets are primarily located in and along the Gulf of Mexico, in the areas on- and offshore Texas and Louisiana. In 2010 the Gulf Coast region contributed approximately 19 percent of our worldwide production and revenues, predominately from offshore properties. Apache’s Gulf Coast operations grew significantly during the year with the June acquisition of Devon’s Gulf of Mexico shelf properties and the addition of properties with the Mariner merger in November 2010. These transactions were aligned with our long-term core strategy of maintaining a balanced portfolio of assets. The region accounted for nearly 13 percent of our estimated proved reserves at year-end compared to 13 percent the previous year.
 
Apache has been the largest offshore held-by-production acreage owner since 2004 and is now the largest producer in waters less than 500 feet deep (shelf). The Devon acquisition and Mariner merger brought significant development and exploration opportunities with high-quality assets complementary to our existing assets, as well as a strategic presence in the deepwater Gulf of Mexico (waters greater than 500 feet deep). The deepwater Gulf of Mexico is relatively underexplored and oil prone and provides exposure to significant reserve and production


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potential. Acreage increased 76 percent to 5.3 million gross acres: 2.5 million deepwater, 1.4 million shelf, and 1.4 million onshore. Over 50 percent of the region’s acreage was undeveloped.
 
In 2010 the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) announced a series of moratoria, which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the Outer Continental Shelf (OCS), and put oil and gas lessees and operators on notice that, with certain exceptions, the BOEMRE would not consider drilling permits for deepwater wells and related activities. While the moratoria have been formally lifted, no new permits for deepwater drilling have been issued as of the date of this filing.
 
In addition, the BOEMRE issued new regulations in 2010 requiring additional information, documentation and analysis for all new wells on the OCS. The effect of these new regulations was to significantly slow down issuance of permits for shallow wells. Apache continues to operate under these new regulations and, through February 2011, has received 25 drilling permits for shallow wells. Current permitting activity has been slowed compared to prior-year levels, and the Company has budgeted its exploration and development activity accordingly.
 
Despite the curtailment of activity in the region stemming from new regulations, the region had a productive year, drilling or participating in 63 wells (36 in the Gulf of Mexico), up from 26 wells (20 in the Gulf of Mexico) in 2009, and performing 365 workovers and recompletions.
 
As a result of 2010 acquisitions and the differing growth and opportunity profiles, we have divided the assets into three regions beginning in 2011: Gulf of Mexico shelf, Gulf of Mexico deepwater and Gulf Coast onshore. In 2011 the Company plans to invest approximately $200 million, $1 billion and $500 million in the Gulf Coast onshore, Gulf of Mexico shelf and Gulf of Mexico deepwater assets, respectively, subject to receipt of permits from BOEMRE. The capital will be spent on drilling, recompletion and development projects, equipment upgrades, production enhancement projects, lease acquisition, seismic acquisition and abandonment activities.
 
On September 16, 2010, the BOEMRE and the Department of the Interior issued a Notice to Lessees and Operators (NTL) updating the procedures and timing for decommissioning offshore wells and platforms. While the so called “Idle Iron” NTL may result in an acceleration of timing to abandon certain wells and remove certain platforms in the Gulf of Mexico, our ongoing active well and equipment abandonment program mitigated the impact of the new regulations on Apache. The Company spent approximately $260 million to plug offshore wells and remove platforms in 2010. With the addition of the Devon and Mariner offshore properties, we currently plan to spend approximately $350 million in 2011.
 
Central Region  The Central region includes nearly 2,000 wells and controls over one million gross acres primarily in western Oklahoma, the Texas panhandle and east Texas. Most of the region’s acreage is held-by-production. Although the reserves and production are primarily natural gas, given the price disparity between oil and gas, the region successfully targeted oil and liquids rich gas plays in 2010. Oil-and liquids-production increased by 54 percent and 90 percent, respectively, over the prior year. In 2010 Apache drilled or participated in the drilling of 84 wells, 99 percent of which were completed as producers. The region also performed 144 workovers and recompletions. The region’s year-end estimated proved reserves, which were 90 percent natural gas, were six percent of Apache’s total.
 
In the Anadarko basin, the Granite Wash play has long been a core stacked-pay target for the region, where we have drilled many vertical wells over the past several decades. As a result, we control approximately 200,000 gross acres in this liquid-rich play, mostly held-by-production. Despite the numerous vertical wells drilled, the Granite Wash is re-emerging as a horizontal play that is capitalizing on advances in horizontal drilling and fracturing technology and high oil prices given the rich liquids yield of the wells. In 2009 we drilled our first operated horizontal well in the Granite Wash. In 2010 we ramped up activity to 10 rigs, drilling 31 horizontal Granite Wash wells and testing six additional horizons including the Hogshooter interval, which is shallower, younger and oilier than previously tested Granite Wash targets. We have completed two wells in the Hogshooter interval, which are separated by over fifteen miles of what appears to be very prolific acreage, primarily owned and operated by Apache. We have identified hundreds of additional Granite Wash horizontal well locations across our acreage. In 2011 we plan to keep a minimum of eight rigs running in this play and drill in excess of 40 horizontal wells, targeting several horizons.


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We have had success on the Anadarko shelf drilling relatively shallow horizontal wells into the Cherokee formation. In 2010 we completed four horizontal wells in the Cherokee play with vertical depths of 6,500 feet and horizontal penetrations of nearly one mile. These wells had average 30-day rates of 520 b/d and 850 Mcf/d and an average Apache working interest of 78 percent. The wells are currently producing an average of 150 b/d and 560 Mcf/d. We plan to drill 13 horizontal wells in the Cherokee in 2011. In addition, we have had success with our program targeting oil in Ochiltree County, Texas. During the year we drilled four wells in the Cleveland formation at a vertical depth of 7,500 feet and participated in one horizontal well in the Marmaton formation at a depth of 11,000 feet. Two of the Cleveland wells and the Marmaton well commenced production in late 2010 at an average initial rate of approximately 500 b/d. Apache’s average working interest in the five wells is 90 percent. The two remaining Cleveland wells are awaiting completion, and we intend to keep at least one drilling rig running in the area throughout the year.
 
We are also employing horizontal drilling and multistage fracture technology in east Texas. In 2010 we drilled seven horizontal Bossier wells in Freestone County, Texas, where we own 45,000 gross acres. The wells produced an aggregate 7.34 Bcf during the year and are currently producing 37 MMcf/d, 33 MMcf/d net to Apache.
 
In 2011 the Central region plans to invest approximately $430 million in drilling, recompletions, equipment upgrades, production enhancement projects and lease acquisitions, primarily in the Anadarko basin. We currently plan to keep 12 rigs running all year, with more than 95 percent of the wells drilled horizontally and 89 percent of the wells drilled targeting oil or high liquid yield gas.
 
Permian Region  Our Permian region, carved out of our Central region, grew significantly in 2010. In July we opened a new regional office in Midland. The region’s property and acreage base increased substantially upon completion of the BP acquisition in July and the Mariner merger in November. These two transactions combined added approximately 35 Mboe/d of new production and more than doubled our acreage to over three million gross acres with exposure to every known play in the Permian Basin. The drilling rig count has increased from five operating at the beginning of 2010 to more than 20 at the end of the year. The workover and completion rig count has increased from 56 to 80, and the employee headcount in Midland and the field has increased by more than 200 during this same time period. The region drilled or participated in 263 wells and completed approximately 1,100 workovers and recompletions in 2010.
 
Apache is one of the largest operators in the Permian Basin, operating more than 11,000 wells in 152 fields, including 45 waterfloods and six CO2 floods. Fourth-quarter net production was 59 Mb/d and 162 MMcf/d and included only six weeks of production from the properties acquired in the Mariner merger. The Permian region’s year-end estimated proved reserves, which were 76 percent oil and liquids, were 25 percent of Apache’s total.
 
During 2010 the Permian region tested horizontal drilling opportunities in four mature waterflood fields, the North McElroy, Shafter Lake, TXL South, and Dean Units, all of which resulted in commercial successes. The region ultimately drilled and completed a total of 17 horizontal wells in the units. The Midland team has developed a significant inventory of potential horizontal drilling applications on existing Apache acreage across the Permian Basin. In 2011 we plan to drill 41 horizontal wells across a number of the region’s assets.
 
In 2010 the region signed a 20-year CO2 supply contract to develop approximately 8.4 MMboe of estimated proved reserves at Roberts Unit. Our 2010 drilling results at Roberts Unit include 15 production and CO2 injection wells that resulted in higher than predicted production rates. The CO2 development at Roberts Unit will continue during 2011 with 43 new production and injection wells planned.
 
In 2011 the Permian Region plans to invest approximately $930 million in drilling, recompletion projects, equipment upgrades, expansion of existing facilities and equipment and leasing new acreage. We plan to keep more than 20 rigs running all year drilling an estimated 368 wells. The region’s 2011 drilling activity will focus on a combination of Apache legacy assets and the newly acquired Mariner and BP properties. On the BP properties alone, the region has identified more than 2,000 drilling locations. Current plans include 130 wells in the Deadwood area (acquired from Mariner) where we hold 63,000 net acres subject to continuous drilling clauses and in the Empire Yeso area (acquired from BP), where we plan to drill approximately 55 wells.
 
U.S. 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 and integrated major oil companies.


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Apache primarily markets its U.S. crude oil to integrated major oil companies, marketing and transportation companies 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 prevailing market prices.
 
Canada
 
Overview  Apache has 6.3 million net acres across the provinces of British Columbia, Alberta and Saskatchewan, including approximately 1.3 million net mineral and leasehold acres in Western Alberta and British Columbia acquired from BP in 2010. Our acreage base provides 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. At year-end 2010 our Canadian region held approximately 26 percent of our estimated proved reserves. In 2010 we drilled or participated in 182 wells in Canada, eight of which were exploratory wells. The region’s 2010 natural gas production increased ten percent, while liquids production was one percent higher.
 
On our conventional assets, we are focused on oil projects located primarily in Alberta and Saskatchewan, enabling us to take advantage of the current strong oil prices. We will utilize our drilling technology and reservoir modeling expertise to identify and exploit unswept oil in our waterflood projects in the House Mountain, Leduc and Snipe Lake fields. Additional drilling for oil will continue on our enhanced oil recovery projects in Midale and Provost with long-term plans to develop and expand waterfloods and CO2 projects. We will also continue intermediate-depth gas development drilling in Kaybob and West 5 areas.
 
Apache’s near-term natural gas production growth will likely be driven by our activity in two large growth plays in British Colombia: shale gas in the Horn River basin and tight sands in the Noel area. In the Horn River basin, Apache has a 50-percent interest and 210,000 net acres. During 2010 Apache reached a peak of 100 MMcf/d net, drilled 29 new wells and completed 30 wells. In 2011 we plan to drill 10 and complete 28 wells in the Horn River basin. Apache acquired its 100-percent working interest in the Noel area from BP in October 2010. Gas production from Noel reached an exit rate of 100 MMcf/d in December 2010. In 2011 we are currently planning a horizontal drilling program of approximately 11 wells in the Noel Area. Apache has identified many years of drilling activity in both plays.
 
During the first quarter of 2010 Apache Canada Ltd. (Apache Canada), through its subsidiaries, purchased a 51 percent interest in a planned LNG export terminal (Kitimat LNG facility) and a 25.5-percent interest in a partnership that owns a related proposed pipeline. In the second quarter of 2010 EOG Resources Canada, Inc. (EOG Canada), through its wholly-owned subsidiaries, acquired the remaining 49 percent of the Kitimat LNG facility and a 24.5-percent interest in the pipeline partnership. In February 2011 Apache Canada and EOG Canada entered into an agreement to purchase the remaining 50-percent interest in the pipeline partnership from Pacific Northern Gas Ltd. (PNG). Under the terms of the agreement, PNG will operate and maintain the planned pipeline under a seven-year agreement with Apache Canada and EOG Canada with provisions for five-year renewals. It also includes a 20-year transportation service arrangement which may require Apache Canada and EOG Canada, under certain circumstances, to use a portion of PNG’s current pipeline capacity. Upon close of the transaction, expected in the second quarter of 2011, Apache Canada and EOG Canada will own 51 percent and 49 percent, respectively, of the pipeline partnership and proposed pipeline.
 
Apache Canada and EOG Canada plan to build the Kitimat LNG facility on Bish Cove near the Port of Kitimat, 400 miles north of Vancouver, British Columbia. The facility is planned for an initial minimum capacity of 700 MMcf/d, or five million metric tons of LNG per year, of which Apache Canada has reserved 51 percent. The proposed 287-mile pipeline will originate in Summit Lake, British Columbia, and is designed to link the Kitimat LNG facility to the pipeline system currently servicing western Canada’s natural gas producing regions. Apache Canada will have rights to 51-percent of the capacity in the proposed pipeline. Completion of the front-end engineering and design (FEED) study and a final investment decision are targeted for late 2011. Construction is expected to commence in 2012, with commercial operations projected to begin in 2015.
 
Our plans for 2011 are to drill or participate in a total of 149 wells in Canada, including 129 development wells and 20 exploratory wells. The planned development includes nine drills and 28 completions in the Horn River basin.


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During 2011 the region plans to invest approximately $800 million for drilling and development projects, equipment upgrades, production enhancement projects and seismic acquisition. Approximately $25 million is allocated for Gathering, Transmission and Processing (GTP) assets.
 
Marketing  Our Canadian natural gas marketing activities focus on sales to LDCs, utilities, end-users, integrated major oil companies, supply aggregators and marketers. We maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk in our portfolio. To diversify our market exposure, we transport natural gas via our firm transportation contracts to California, the Chicago area and eastern Canada. We sell the majority of our Canadian gas on a monthly basis at either first-of-the-month or daily prices. In 2010 approximately two percent of our gas sales were subject to long-term fixed-price contracts, with the latest expiration in 2011.
 
Our Canadian crude is sold primarily to integrated major oil companies and marketers. We sell our oil based on West Texas Intermediate (WTI) and sell our NGLs based on postings or a percentage of WTI. Prices are adjusted for quality, transportation and a market-reflective negotiated differential. We maximize the value of our condensate and heavier crudes by determining whether to blend the condensate into our own crude production or sell it in the market as a segregated product. We transport crude oil on 12 pipelines to the major trading hubs within Alberta and Saskatchewan, which enables us to achieve a higher netback for the production and to diversify our purchasers.
 
International
 
Apache’s international assets are located in Egypt, Australia, offshore the U.K. in the North Sea, Argentina and Chile. In 2010 international assets contributed 52 percent of our production and 56 percent of our oil and gas production revenues. At year-end 30 percent of our estimated proved reserves were located outside North America.
 
Egypt
 
Overview  Our commitment to Egypt began in 1994 with our first Qarun discovery well. Today we control 11.3 million gross acres making Apache the largest acreage holder in Egypt’s Western Desert. Only 15 percent of our gross acreage in Egypt has been developed. That 15 percent produced an average of 189 Mb/d and 799 MMcf/d in 2010, 99 Mb/d and 375 MMcf/d net to Apache, which we believe makes Apache the largest producer of liquid hydrocarbons and natural gas in the Western Desert and the third largest in all of Egypt. The remaining 85 percent of our acreage is undeveloped, providing us with considerable exploration and development opportunities for the future. We have 3-D seismic covering over 12,000 square miles, or 68 percent of our acreage. In 2010 the region contributed 28 percent of our production revenue, 24 percent of our production and 10 percent of our year-end estimated proved reserves. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country share reserves.
 
Our operations in Egypt are conducted pursuant to production-sharing agreements, in 24 separate concessions, 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, with the balance generally allocated between the contractor partners and Egyptian General Petroleum Corporation (EGPC) on a contractually-defined basis. In 2010, Apache retained approximately 52 percent and 47 percent, respectively, of the gross oil and gas produced from our Egyptian concessions. Development leases within concessions generally have a 25-year life, with extensions possible for additional commercial discoveries or on a negotiated basis, and currently have expiration dates ranging from 10 to 25 years.
 
Apache’s Egyptian operations had another year of growth in 2010: gross daily production increased 16 percent, and net daily production increased six percent. We maintained an active drilling and development program, drilling 204 wells, including 10 new field discoveries, and conducted 662 workovers and recompletions. In addition, we achieved a goal we set in 2005 to double gross equivalent production from our operated concessions by the end of 2010. In November we closed on the purchase of BP assets in Egypt’s Western Desert, acquiring four development leases and one exploration concession as well as strategically-positioned infrastructure that will enable Apache to increase production from existing fields in the Western Desert.


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During 2011 the region plans to invest approximately $1.1 billion for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects and seismic acquisition. Our drilling program includes a combination of development and exploration wells with current plans to drill 65 gross exploration wells, 50 percent more than 2010. We will also drill our first horizontal well in the Western Desert.
 
Egypt political unrest  As a result of political unrest, protests, riots, street demonstrations and acts of civil disobedience in the Egyptian capital of Cairo that began on January 25, 2011, Egyptian president Hosni Mubarak stepped down, effective February 11, 2011. The Egyptian Supreme Council of the Armed Forces is now in power. On February 13, 2011, the Council announced that the constitution would be suspended, both houses of parliament would be dissolved, and that the military would rule for six months until elections can be held. Following the advice of the U.S. State Department, Apache initially evacuated all non-essential personnel from Egypt. As conditions stabilized recently, approximately one-third of the evacuated employees returned. Apache’s production, located in remote locations in the Western Desert, has continued uninterrupted; however, further changes in the political, economic and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition and results of operations.
 
Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and highly rated international insurers covering its investments in Egypt. In the aggregate, these policies, subject to the policy terms and conditions, provide approximately $1 billion of coverage to Apache covering losses arising from confiscation, nationalization, and expropriation risks and currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the Government of Egypt prevent Apache form exporting our share of production.
 
Marketing  Our gas production is sold to EGPC primarily 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, this 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. This region averaged $3.62 per Mcf in 2010.
 
Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is sold primarily to third parties in the Mediterranean market or to EGPC when called upon to supply domestic demand. Oil sales are made either directly into the Egyptian oil pipeline grid, sold to non-governmental third parties including those supplying the Middle East Oil Refinery located in northern Egypt, or exported from or sold at one of two terminals on the northern coast of Egypt. Oil production that is presently sold to EGPC is sold on a spot basis priced at Brent with a monthly EGPC official differential applied. In 2010 we sold 32 cargoes (approximately 10.1 MMbbls) of Western Desert crude oil into the export market from the El Hamra terminal located on the northern coast of Egypt. These export cargoes were sold to third parties at market prices above our domestic prices received from EGPC. Additionally, Apache sold Qarun oil (approximately 10.7 MMbbls) 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 (1.3 MMbbls) or exported primarily to refiners in the Mediterranean region (15 cargoes for approximately 9.4 MMbbls).
 
Australia
 
Overview  Apache’s holdings in Australia are focused offshore Western Australia in the Carnarvon basin, where we have operated since acquiring the gas processing facilities on Varanus Island and adjacent producing properties in 1993, the Exmouth basin and the Browse basin. We also have exploration acreage in the Gippsland basin offshore southeastern Australia. Production operations are concentrated in the Carnarvon and Exmouth basins. In total, we control approximately 12.2 million gross acres in Australia through 35 exploration permits, 14


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production licenses and six retention leases. In addition, we have one production license and four retention leases pending confirmation.
 
During the year the region participated in drilling 31 wells, of which 23 were productive. In addition, we expanded our exploration opportunities in the Carnarvon and Exmouth basins via farm-ins to seven permits. The transactions resulted in a 58-percent increase in our net undeveloped acreage in the Carnarvon basin and added 1.9 million net acres for exploration in the Exmouth basin. Oil production increased by 369 percent on initial production from the development of our 2007 Van Gogh and Pyrenees oil field discoveries, while gas production increased by nine percent. Production from Australia accounted for approximately 12 percent of our total 2010 production, and year-end estimated proved reserves were 11 percent of Apache’s total.
 
The region has a pipeline of projects that are expected to contribute to production growth as they are brought on-stream over coming years.
 
In 2011, development of our Reindeer field discovery should be complete with first production expected late in the year upon completion of our Devil Creek Gas Plant. The plant will be Western Australia’s third domestic natural gas processing hub and the first new one in more than 15 years. The two-train plant is designed to process 200 million cubic feet of gas per day from the Apache-operated Reindeer field. In 2009, we entered into a gas sales contract covering a portion of the field’s future production. Under the contract, Apache and its joint venture partner agreed to supply 154 Bcf of gas over seven years (approximately 60 MMcf/d beginning in the fourth quarter of 2011) at prices substantially higher than we have historically received in Western Australia. Apache owns a 55-percent interest in the field. Also in 2011, initial production is projected from the Halyard-1 discovery well which is a subsea completion tied back to the existing gas facilities on Varanus Island.
 
In 2012, the 2010 Spar-2 discovery is projected to commence production through an extension of the Halyard sub sea infrastructure which will also allow for the tie-in of future wells.
 
In 2013, first production is projected from four gas wells completed in 2010 in the Macedon gas field. We have a 28 percent non-operating working interest in the field. Gas will be delivered via a 60-mile pipeline to a 200 MMcf/d gas plant to be built at Ashburton North in Western Australia. The project, approved in 2010, is currently underway; with first production projected in 2013.
 
Also in 2013 first production is projected from the Coniston oil field which lies just north of the Van Gogh field. The project was sanctioned for development in 2010. Current plans call for the field to be produced from subsea completions tied back to the Van Gogh field floating, production, storage and offloading (FPSO) Ningaloo Vision.
 
In 2014 first production from the Balnaves field is projected, should the project proceed past Final Investment Decision (FID) stage. The Balnaves field is an oil accumulation in the Brunello gas field, where Apache drilled three successful development wells which we plan to produce through a FPSO. The project is currently in the Front End FEED stage with FID currently projected for the second half of 2011.
 
In 2016 we are projecting to begin production from our operated Julimar and Brunello field gas discoveries through the Chevron operated Wheatstone LNG hub, in which we own a foundation equity partner interest of 13 percent. Apache’s projected net gas sales from the fields are 160 MMcf/d and 3,250 b/d with a projected 15-year production plateau when the multi-year project is fully operational. The project, which is currently in FEED, will convert the gas into LNG for sale on the world market. World LNG prices are typically oil-linked prices and are currently higher than the historical gas prices in Western Australia. The project FID is scheduled for 2011, with first LNG projected in 2016.
 
During 2011 the region plans to invest approximately $1.2 billion for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects and seismic acquisition. Approximately half of the 2011 investment will be for development and processing facilities in connection with the projects discussed above.
 
Marketing  Western Australia has historically had a local market for natural gas with a limited number of buyers and sellers resulting in sales under mostly long-term, fixed-price contracts, many of which contain periodic price escalation clauses based on either the Australian consumer price index or a commodity linkage. As of


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December 31, 2010, Apache had a total of 18 active gas contracts in Australia with expiration dates ranging from November 2012 to July 2030. Recent increases in demand and higher development costs have increased the supply prices required from the local market in order to support the development of new supplies. As a result, market prices received on recent contracts, including our Reindeer field, are substantially higher than historical levels.
 
We anticipate selling LNG from our Julimar and Brunello field gas discoveries at prices tied to oil and sold into international markets.
 
We directly market all of our Australian crude oil production into Australian domestic and international markets at prices generally indexed to Dated Brent benchmark crude oil prices plus a premium, which are typically above NYMEX oil prices.
 
North Sea
 
Overview  Apache entered the North Sea in 2003 after acquiring an approximate 97-percent working interest in the Forties field (Forties). In 2010 the North Sea region produced 20.9 MMboe (99 percent oil), approximately nine percent of our total worldwide production and 13 percent of Apache’s oil and gas production revenues. During 2010 production from Forties decreased seven percent compared to 2009 as natural well decline and unplanned maintenance downtime exceeded gains from drilling. At year-end 2010, Apache had total estimated proved reserves of 155 MMbbls of crude oil in this region, approximately five percent of our year-end estimated proved reserves. Apache acquired Forties with 45 producing wells. Today, there are 77 producing wells with an inventory of future locations. By the end of the first quarter of 2010, Apache had produced and sold, net to its interest, oil volumes in excess of the proved reserves booked when we acquired this interest in 2003.
 
During the summer of 2010 a new 3-D seismic survey was acquired in Forties. Comparison of this data with 3-D seismic shot in prior years has highlighted many areas of bypassed oil in the reservoir and provided better definition of existing targets. In 2010, 20 wells were drilled into the Forties reservoir, of which 12 were productive. We project that this Forties success rate of 60 percent will increase in the future, as drilling results from late December 2010 and early January 2011 have validated the new 4-D evaluation and geological interpretation. We also drilled three exploration wells and one development well outside Forties. The development well and one of the exploration wells were successful.
 
In 2011 the region will invest approximately $850 million on a diverse set of capital projects. Forties will see another year of active drilling with two platform rigs and a jack-up in operation. Construction of the Forties Alpha Satellite Platform is underway and is projected to be complete by mid-year 2012. This platform will sit adjacent to the main Alpha Platform and provide an additional 18 drilling slots along with power generation, fluid separation, gas lift compression and oil export pumping. Also, during the third quarter of 2011 drilling will commence on the Bacchus field, Apache’s first North Sea subsea field development. First production is projected by year-end of 2011. The region also expects to participate in at least two exploration wells outside Forties.
 
In January 2011 a subsea pipeline connecting our Forties Bravo platform to our Charlie platform was shut-in because of corrosion. A project is underway to re-route the production through a smaller line until a new flexible pipeline is installed. This intermediate solution should be completed by the first of March 2011 and will allow us to produce approximately half of the 11,600 b/d that flowed through the main pipeline. The new main subsea pipeline will be completed by September 2011.
 
Marketing  In 2010 we sold our Forties crude under both term contracts (70 percent) and spot cargoes (30 percent). The term sales are composed of a market-based index plus a premium, which reflects the higher market value for term arrangements. The prices received for spot cargoes are market driven and can trade at a premium or discount to the market based index.
 
All 2011 production will be sold under a term contract with a per-barrel premium to the Dated Brent index. A separate physical sales contract within the term sale for 20,000 b/d was entered into with a floor price of $70.00 per barrel and an average ceiling price of $98.56 per barrel. This contract will be settled against Dated Brent.


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Argentina
 
Overview  We have had a continuous presence in Argentina since 2001, which was expanded substantially by two acquisitions in 2006. We currently have operations in the Provinces of Neuquén, Rio Negro, Tierra del Fuego and Mendoza. We have interests in 24 concessions, exploration permits and other interests totaling over 3.4 million gross acres (2.9 million net). Apache now holds oil and gas assets in three of the main Argentine hydrocarbon basins: Neuquén, Austral and Cuyo. Our concessions have varying expiration dates ranging from four years to over fifteen years remaining, subject to potential additional extensions. In 2010 Argentina produced seven percent of our worldwide production and held four percent of our estimated proved reserves at year-end.
 
In 2010 the region had its most successful development drilling program in its history, drilling 56 gross wells:; 43 in the Neuquén basin and 13 in the Austral basin of Tierra del Fuego. Drilling focused on shallow development targets, 93 percent of the wells were successful. In addition, the region completed 106 capital projects consisting of recompletions, increasing lifting capacity, and facility projects.
 
Also during 2010 Apache acquired approximately 567 square kilometers of 3-D seismic on two blocks located in the Cuyo basin. Apache employed new cable-less technology intended to minimize environmental impact in the area, the first time this technology has been used in Argentina. We are currently analyzing the results from the seismic shoot and expect to commence a drilling campaign in the Cuyo basin in the first quarter of 2011.
 
In 2011 we will begin negotiations for extensions of three concessions each in the Tierra del Fuego and Rio Negro Provinces, which are scheduled to expire in 2016 and 2017. Future investment by Apache in the Tierra del Fuego Province will be significantly influenced by the probability of obtaining the Province’s agreement to an extension of the present concession expirations. In March 2009 Apache reached an agreement with the Province of Neuquén to extend eight federal oil and gas concessions for 10 additional years. The concessions, which were scheduled to expire between 2015 and 2017, encompass approximately 590,000 net acres, including exploratory areas totaling 514,000 net acres. Neuquén operations generate about half of Apache’s total output in Argentina.
 
During 2011 the region plans to invest approximately $300 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition.
 
Marketing
 
Natural Gas  Apache sells its natural gas through three avenues:
 
  •  Gas Plus program: This program was instituted by the Argentine government to encourage new gas supplies through the development of tight sands and unconventional reserves. Under this program, qualifying projects are allowed to sell gas at prices that are above the regulated rates. During 2010 Apache signed three Gas Plus contracts totaling 63 MMcf/d of gross production from fields in the Neuquén and Rio Negro Provinces. The first contract, for 10 MMcf/d at $4.10 per MMBtu for 2010, has been extended through 2011 for 11 MMcf/d at the $4.10 per MMBtu. The other two contracts, which together totaled 53 MMcf/d at $5.00 per MMBtu, are expected to commence in the first quarter of 2011. The gas supply is required to come from wells drilled in the projects’ approved fields and formations. We believe this program, reflects changing market conditions, which point to improving markets and price realizations going forward.
 
  •  Government-regulated pricing: The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. During 2010 we realized an average price of $1.20 per Mcf on government-regulated sales.
 
  •  Unregulated market: The majority of our remaining volumes are sold into the unregulated market. In 2010 realizations averaged $2.65 per Mcf.
 
Crude Oil  Our crude oil is subject to an export tax, which effectively limits the prices buyers are willing to pay for domestic sales. Domestic oil prices are currently based on $42 per barrel, plus quality adjustments and local premiums, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar pricing formulas exist; however, Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. As a result, 2010 oil prices realized from Tierra del


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Fuego oil production averaged $65.03 per barrel as compared to our Neuquén basin production, which averaged $53.68 per barrel.
 
Chile
 
In November 2007 Apache was awarded exploration rights on two blocks comprising approximately one million net acres on the Chilean side of Tierra del Fuego. This acreage is adjacent to our 552,000 net acres on the Argentine side of the island of Tierra del Fuego and represents a natural extension of our expanding exploration and production operations. The Lenga and Rusfin Blocks were ratified by the Chilean government on July 24, 2008. In January 2009 a 3-D seismic survey totaling 1,000 square kilometers was completed, and in November 2009 the first of a three-well exploration program commenced drilling. The three wells have now been drilled, and we are currently evaluating results.
 
Major Customers
 
In 2010 purchases by Shell accounted for 15 percent of the Company’s worldwide oil and gas production revenues.
 
Drilling Statistics
 
Worldwide in 2010 we participated in drilling 904 gross wells, with 826 (91 percent) completed as producers. We also performed nearly 2,500 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: 51 in the U.S. (25.04 net); 7 in Canada (6.18 net); 22 in Egypt (20 net); 2 in Australia (0.64 net); 3 in the North Sea (2.91 net); and 7 in Argentina (5.15 net).


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The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:
 
                                                                         
    Net Exploratory     Net Development     Total Net Wells  
    Productive     Dry     Total     Productive     Dry     Total     Productive     Dry     Total  
 
2010
                                                                       
United States
    3.7       2.2       5.9       309.2       12.7       321.9       312.9       14.9       327.8  
Canada
    6.5       1.5       8.0       122.3       5.7       128.0       128.8       7.2       136.0  
Egypt
    19.4       18.5       37.9       144.8       5.5       150.3       164.2       24.0       188.2  
Australia
    5.5       3.4       8.9       4.5       1.3       5.8       10.0       4.7       14.7  
North Sea
    1.0       1.2       2.2       10.7       5.8       16.5       11.7       7.0       18.7  
Argentina
    1.8       2.7       4.5       43.3       0.3       43.6       45.1       3.0       48.1  
                                                                         
Total
    37.9       29.5       67.4       634.8       31.3       666.1       672.7       60.8       733.5  
                                                                         
2009
                                                                       
United States
    5.6       2.5       8.1       107.6       8.5       116.1       113.2       11.0       124.2  
Canada
    3.0             3.0       136.8       12.8       149.6       139.8       12.8       152.6  
Egypt
    8.6       10.4       19.0       126.4       4.0       130.4       135.0       14.4       149.4  
Australia
    6.9       3.8       10.7       4.7             4.7       11.6       3.8       15.4  
North Sea
    1.0             1.0       12.6       2.9       15.5       13.6       2.9       16.5  
Argentina
    3.4       0.7       4.1       25.5             25.5       28.9       0.7       29.6  
Other International
    2.0             2.0                         2.0             2.0  
                                                                         
Total
    30.5       17.4       47.9       413.6       28.2       441.8       444.1       45.6       489.7  
                                                                         
2008
                                                                       
United States
    4.5       6.6       11.1       334.8       25.3       360.1       339.3       31.9       371.2  
Canada
    3.9       5.0       8.9       328.0       10.1       338.1       331.9       15.1       347.0  
Egypt
    18.7       11.5       30.2       193.2       5.8       199.0       211.9       17.3       229.2  
Australia
    6.4       9.0       15.4       12.5             12.5       18.9       9.0       27.9  
North Sea
                      11.7             11.7       11.7             11.7  
Argentina
    7.5       2.0       9.5       54.4       6.2       60.6       61.9       8.2       70.1  
                                                                         
Total
    41.0       34.1       75.1       934.6       47.4       982.0       975.6       81.5       1,057.1  
                                                                         
 
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, 2010, is set forth below:
 
                                                 
    Gas     Oil     Total  
    Gross     Net     Gross     Net     Gross     Net  
 
United States
    5,165       3,040       2,370       7,995       17,535       11,035  
Canada
    10,100       8,405       2,500       1,100       12,600       9,505  
Egypt
    52       51       722       694       774       745  
Australia
    22       9       20       12       42       21  
North Sea
                77       75       77       75  
Argentina
    425       390       520       445       945       835  
                                                 
Total
    15,764       11,895       16,209       10,321       31,973       22,216  
                                                 
 
Gross natural gas and crude oil wells include 1,600 wells with multiple completions.


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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 transportation costs but excluding severance and other taxes) and average sales prices for each of the countries where we have operations:
 
                                                         
                      Average Lease
                   
    Production     Operatinge Cost per
    Average Sales Price  
Year Ended December 31,   Oil     NGLs     Gas     Boe     Oil     NGLs     Gas  
    (MMbbls)     (MMbbls)     (Bcf)           (Per bbl)     (Per bbl)     (Per Mcf)  
 
2010
                                                       
United States
    35.3       5.0       266.8     $ 11.40     $ 76.13     $ 41.45     $ 5.28  
Canada
    5.3       1.1       144.5       13.46       72.83       36.61       4.48  
Egypt
    36.2             136.8       5.56       79.45       69.75       3.62  
Australia
    16.7             72.9       6.41       77.32             2.24  
North Sea
    20.8             0.9       9.23       76.66             18.64  
Argentina
    3.6       1.2       67.5       7.97       57.47       27.08       1.96  
                                                         
Total
    117.9       7.3       689.4       9.20       76.69       38.58       4.15  
                                                         
2009
                                                       
United States
    32.5       2.2       243.1     $ 10.59     $ 59.06     $ 33.02       4.34  
Canada
    5.5       0.8       131.1       11.46       56.16       25.54       4.17  
Egypt
    33.6             132.3       5.17       61.34             3.70  
Australia
    3.6             67.0       6.84       64.42             1.99  
North Sea
    22.3             1.0       8.19       60.91             13.15  
Argentina
    4.2       1.2       67.4       6.78       49.42       18.76       1.96  
                                                         
Total
    101.7       4.2       641.9       8.48       59.85       27.63       3.69  
                                                         
2008
                                                       
United States
    32.9       2.2       248.8     $ 12.62     $ 83.70     $ 58.62     $ 8.86  
Canada
    6.3       0.7       129.1       14.00       93.53       49.33       7.94  
Egypt
    24.4             96.5       6.47       91.37             5.25  
Australia
    3.0             45.0       9.85       91.78             2.10  
North Sea
    21.8             1.0       10.00       95.76             18.78  
Argentina
    4.5       1.1       71.6       6.58       49.46       37.83       1.61  
                                                         
Total
    92.9       4.0       592.0       10.56       87.80       51.38       6.70  
                                                         
 
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:
 
                                 
    Undeveloped Acreage     Developed Acreage  
    Gross Acres     Net Acres     Gross Acres     Net Acres  
 
United States
    4,809,425       2,846,337       4,955,265       2,848,363  
Canada
    3,834,513       2,960,531       4,527,542       3,334,602  
Egypt
    9,572,015       6,192,027       1,741,102       1,624,780  
Australia
    11,456,850       6,587,180       744,900       402,500  
North Sea
    780,811       406,157       41,019       39,846  
Argentina
    3,149,882       2,701,182       220,840       188,226  
Chile
    1,205,403       1,036,626              
                                 
Total
    34,808,899       22,730,730       12,230,668       8,438,317  
                                 


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As of December 31, 2010, we had 3,284,814, 1,588,390, and 3,552,045 net acres scheduled to expire by December 31, 2011, 2012, and 2013, respectively, if production is not established or we take no other action to extend the terms. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not project a significant portion of our net acreage position to expire before such actions occur.
 
As of December 31, 2010, 30 percent of U.S. net undeveloped acreage and 36 percent of Canadian undeveloped acreage was held by production.
 
Estimated Proved Reserves and Future Net Cash Flows
 
Effective December 31, 2009, Apache adopted revised oil and gas disclosure requirements set forth by the SEC in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries — Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
 
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGL’s that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. 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 they are economically producible and are 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 using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
 
PUD reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.


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The following table shows proved oil, NGL and gas reserves as of December 31, 2010, based on average commodity prices in effect on the first day of each month in 2010, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. The table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.
 
                                 
    Oil
    NGL
    Gas
    Total
 
    (MMbbls)     (MMbbls)     (Bcf)     (MMboe)  
 
Proved Developed:
                               
United States
    423       92       2,284       895  
Canada
    90       24       2,182       478  
Egypt
    110             748       234  
Australia
    48             683       162  
North Sea
    116             4       116  
Argentina
    16       6       462       100  
Proved Undeveloped:
                               
United States
    214       30       989       409  
Canada
    57       4       1,310       280  
Egypt
    17             329       72  
Australia
    18             805       152  
North Sea
    39                   39  
Argentina
    4       1       71       16  
                                 
TOTAL PROVED
    1,152       157       9,867       2,953  
                                 
 
As of December 31, 2010, Apache had total estimated proved reserves of 1,309 MMbbls of crude oil, condensate and NGLs and 9.9 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 3.0 billion barrels of oil or 17.7 Tcf of natural gas, of which oil represents 39 percent. As of December 31, 2010, the Company’s proved developed reserves totaled 1,985 MMboe and estimated PUD reserves totaled 968 MMboe, or approximately 33 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.
 
The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of December 31, 2010, 2009, 2008 and 2007, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 12 — Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows as of December 31, 2010, were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each month in 2010 and 2009, held flat for the life of the production, except where prices are defined by contractual arrangements. Future net cash flows as of December 31, 2008, were estimated using commodity prices in effect at the end of that year, in accordance with the SEC guidelines in effect prior to the issuance of the Modernization Rules.
 
Proved Undeveloped Reserves
 
The Company’s total estimated PUD reserves of 968 MMboe as of December 31, 2010, increased by 237 MMboe over the 731 MMboe of PUD reserves estimated at the end of 2009. This increase was, in part, due to our 2010 acquisitions described above. During the year, Apache converted 64 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America we converted 31 MMboe, with the remaining 33 MMboe in our international areas.
 
During the year a total of approximately $1.1 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2009. A portion of our costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. We spent $517 million on PUD reserve development activity in North America and $574 million in the international areas. At year-end 2010, no material amounts of PUD reserves remain undeveloped for five years or more after they were initially disclosed as PUD reserves.


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Preparation of Oil and Gas Reserve Information
 
Apache emphasizes that its reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.
 
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. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. 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.
 
Apache’s Executive Vice President of Corporate Reservoir Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 30 years of industry experience with positions of increasing responsibility within Apache’s corporate reservoir engineering department. The Executive Vice President of Corporate Reservoir Engineering reports directly to our Chairman and Chief Executive Officer.
 
The estimate of reserves disclosed in this annual report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, the Company engages 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. Apache selects the properties for review by Ryder Scott based primarily on relative reserve value. We also consider other factors such as geographic location, new wells drilled during the year and reserves volume. During 2010 the properties selected for each country ranged from 63 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 85 percent of the reserves value of our international proved reserves and of the new wells drilled in each country. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 63 percent of total proved reserves; 72 percent of proved developed reserves and 45 percent of proved undeveloped reserves. Properties with proved undeveloped reserves generally have an associated capital expenditure required to develop those reserves included in their net present value calculation, reducing their value relative to proved developed reserves. For this reason those properties are less likely to be selected for the audit, resulting in a higher percentage of proved developed reserves selected for review.
 
During 2010, 2009, and 2008, Ryder Scott’s review covered 72, 79 and 82 percent of the Company’s worldwide estimated proved reserves value and 63, 69, and 73 percent of the Company’s total proved reserves, respectively. Ryder Scott’s review of 2010 covered 59 percent of U.S., 42 percent of Canada, 64 percent of Argentina, 99 percent of Australia, 83 percent of Egypt and 83 percent of the United Kingdom’s total proved reserves. Ryder Scott’s review of 2009 covered 66 percent of U.S., 48 percent of Canada, 63 percent of Argentina, 96 percent of Australia, 86 percent of Egypt and 80 percent of the United Kingdom’s total proved reserves. Ryder Scott’s review of 2008 covered 70 percent of U.S., 51 percent of Canada, 58 percent of Argentina, 100 percent of Australia, 87 percent of Egypt and 89 percent of the United Kingdom’s total proved reserves. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.
 
According to Ryder Scott’s opinion, based on their review, including the data, technical processes and interpretations presented by Apache, the overall procedures and methodologies utilized by Apache in determining the proved reserves comply with the current SEC regulations and the overall proved reserves for the reviewed properties as estimated by Apache are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.


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Employees
 
On December 31, 2010, we had 4,449 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 2010 we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Midland, 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, please see Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Contractual Obligations and Note 8 — Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of 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, or 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.
 
Additional Information about Apache
 
In this section, references to “we,” “us,” “our,” and “Apache” include Apache Corporation and its consolidated subsidiaries, unless otherwise specifically stated.
 
Remediation Plans and Procedures
 
Apache adopted a Region Spill Response Plan (the Plan) for its Gulf of Mexico operations to ensure a rapid and effective response to spill events that may occur on Apache-operated properties. Periodically, drills are conducted to measure and maintain the effectiveness of the Plan. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache in the event of a spill is CGA. Apache has received approval for the Plan from the BOEMRE. Apache personnel review the Plan annually and update where necessary.
 
Apache is a member of, and has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered (an arrangement for the hiring of a boat with no crew or provisions included) its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine Preservation Association. MSRC maintains CGA’s equipment (currently including 13 shallow water skimmers, four fast response vessels with skimming capabilities, nine fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. In addition, CGA maintains a contract


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with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies. In 2010 we paid CGA approximately $312,000: $12,800 per capita and a fee based on annual production.
 
In the event that CGA resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. Oil Spill Response Limited has equipment stockpiles in Bahrain, Singapore and Southampton that currently include approximately 153 skimmers, booms (of approximately 12,000 meters), two Hercules aircraft for equipment deployment and aerial dispersant spraying, two additional aircraft, dispersant spray systems and dispersant, floating storage tanks, all-terrain vehicles and various other equipment. If necessary, Oil Spill Response Limited’s resources may be, and have been, deployed to areas across the globe, such as the Gulf of Mexico. In addition, resources of other organizations are available to Apache as a non-member, such as those of MSRC and National Response Corporation (NRC), albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels and dispersant aircraft. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland work boats, vacuum transfer units and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time-to-time and current information is generally available on each of the companies’ websites.
 
Apache participates in a number of industry-wide task forces that are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force. In 2011, Apache’s wholly-owned subsidiary Apache Deepwater LLC, retained the Helix Energy Solution Group in conjunction with its CGA membership, and will become a member of the Marine Well Containment Company to fulfill the government permit requirements for containment and oil spill response plans in Deepwater operations.
 
Competitive Conditions
 
The oil and gas business is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, gas and natural gas liquids. Our competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies and participants in other industries supplying energy and fuel to industrial, commercial and individual consumers.
 
Certain of our competitors may possess financial or other resources substantially larger than we possess or 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 leases or drilling rights.
 
However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across six countries, and our balanced production mix between oil and gas, our management and incentive systems, and our experienced personnel give us a strong competitive position relative to many of our competitors who do not possess similar political, geographic and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the six countries in which we have producing operations to which we can reallocate capital investments in response to changes in local business environments and markets. It also reduces the risk that we will be materially impacted by an event in a specific area or country.


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Environmental Compliance
 
As an owner or lessee and operator of oil and gas properties, we are subject to numerous 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. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.
 
We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, we do not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on our capital expenditures, earnings or competitive position. In November 2010 Apache entered into an agreed order with the Texas Commission on Environmental Quality and paid a total of $111,000 in administrative penalties to settle allegations regarding operations of two natural gas processing plants.
 
Changes to existing, or additions of, laws, regulations, enforcement policies or requirements in one or more of the countries or regions in which we operate could require us to make additional capital expenditures. While the events in the U.S. Gulf of Mexico in 2010 have resulted in the enactment of, and may result in the enactment of additional, laws or requirements regulating the discharge of materials into the environment, we do not believe that any such regulations or laws enacted or adopted as of this date will have a material adverse impact on our cost of operations, earnings or competitive position.
 
ITEM 1A.   RISK FACTORS
 
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.
 
Future economic conditions in the U.S. and key international markets may materially adversely impact our operating results.
 
The U.S. and other world economies are slowly recovering from a global financial crisis and recession that began in 2008. Growth has resumed but is modest and at an unsteady rate. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.
 
In addition, the Organisation for Economic Co-operation and Development (OECD) has encouraged countries with large federal budget deficits to initiate deficit reduction measures. Such measures, if they are undertaken too rapidly, could further undermine economic recovery and slow growth by reducing demand.


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Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.
 
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2010 ranged from a high of $92.89 per barrel to a low of $68.01 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:
 
  •  worldwide and domestic supplies of crude oil and natural gas;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;
 
  •  the level of global crude oil and natural gas inventories;
 
  •  the price and level of imported foreign crude oil and natural gas;
 
  •  the price and availability of alternative fuels, including coal and biofuels;
 
  •  the availability of pipeline capacity and infrastructure;
 
  •  the availability of crude oil transportation and refining capacity;
 
  •  weather conditions;
 
  •  electricity generation;
 
  •  domestic and foreign governmental regulations and taxes; and
 
  •  the overall economic environment.
 
Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:
 
  •  limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;
 
  •  reducing the amount of crude oil and natural gas that we can produce economically;
 
  •  causing us to delay or postpone some of our capital projects;
 
  •  reducing our revenues, operating income and cash flows;
 
  •  limiting our access to sources of capital, such as equity and long-term debt;
 
  •  a reduction in the carrying value of our crude oil and natural gas properties; or
 
  •  a reduction in the carrying value of goodwill.
 
We recorded asset impairment charges during 2008 and 2009. No impairment charges were recorded during 2010. If commodity prices decline, there could be additional impairments of our oil and gas assets or other investments or an impairment of goodwill.
 
Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil 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


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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.
 
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.
 
Our operations involve a high degree of operational risk, particularly risk of personal injury, damage or loss of equipment and environmental accidents.
 
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:
 
  •  drilling well blowouts, explosions and cratering;
 
  •  pipeline ruptures and spills;
 
  •  fires;
 
  •  formations with abnormal pressures;
 
  •  equipment malfunctions; and
 
  •  hurricanes and/or cyclones, which could affect our operations in areas such as on- and offshore the Gulf Coast and Australia, and other natural disasters.
 
Failure or loss of equipment, as the result of equipment malfunctions or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flow and, in turn, our results of operations could be materially and adversely affected.
 
The Devon and Mariner transactions have increased our exposure to Gulf of Mexico operations.
 
Our recent acquisitions of oil and gas assets in offshore Gulf of Mexico from Devon Energy Corporation and Mariner Energy, Inc. have increased our exposure to offshore Gulf of Mexico operations. Greater offshore concentration proportionately increases risks from delays or higher costs common to offshore activity, including severe weather, availability of specialized equipment and compliance with environmental and other laws and regulations.
 
In addition, as a result of the current lack of drilling activity in the deepwater Gulf of Mexico and slowdown of drilling activity on the Gulf of Mexico shelf caused by the regulatory response to the Deepwater Horizon incident, drilling equipment and oil field services companies may decide to exit the Gulf of Mexico, making such services less available and/or more expensive once drilling activities are allowed to fully resume.


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Any additional deepwater drilling laws and regulations, delays in the processing and approval of permits and other related developments in the Gulf of Mexico as well as our other locations resulting from the Deepwater Horizon incident could adversely affect Apache’s business.
 
As has been widely reported, on April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, which lead to a significant oil spill that affected the Gulf of Mexico. In response to this incident, the BOEMRE ceased issuing drilling permits pursuant to a series of moratoria, and all deepwater drilling activities in progress were suspended. Although the moratoria have been lifted, the DOI has not issued any permits related to the drilling of new exploratory wells in the deepwater Gulf of Mexico as of January 31, 2011. In 2010 the DOI issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to regulate drilling activities and increase liability.
 
In January 2011 the President’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government require additional regulation and an increase in liability caps. The European Commission has recommended that new legislation be enacted to enhance the safety of offshore oil and gas activities. Additional legislation or regulation is being discussed which could require companies operating in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility, a certificate required by the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual insurance fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.
 
The BOEMRE is expected to continue to issue new safety and environmental guidelines or regulations for drilling in the Gulf of Mexico, and other regulatory agencies could potentially issue new safety and environmental guidelines or regulations in other geographic regions, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. We are monitoring legislation and regulatory developments; however, it is difficult to predict the ultimate impact of any new guidelines, regulations or legislation. A prolonged suspension of drilling activity in the U.S. and abroad and new regulations and increased liability for companies operating in this sector could adversely affect Apache’s operations in the U.S. Gulf of Mexico as well as in our other locations.
 
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:
 
  •  our production falls short of the hedged volumes;
 
  •  there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
 
  •  the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or
 
  •  a sudden unexpected event materially impacts oil and natural gas prices.
 
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. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and


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affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. 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.
 
We are exposed to counterparty credit risk as a result of our receivables.
 
We are exposed to risk of financial loss from trade, joint venture, joint interest billing and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. Some of our purchasers and non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.
 
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, product mix and commodity pricing levels and others are also considered by the rating agencies. 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 for certain obligations.
 
Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.
 
During 2010 credit markets recovered but remain vulnerable to unpredictable shocks. We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and/or our partners may need to seek financing in order to fund these or other future activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.
 
Our ability to declare and pay dividends is subject to limitations.
 
The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends.
 
Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including common stock. In the event that any of our indentures or other financing agreements in the future restrict our ability to pay dividends in cash on the mandatory convertible preferred stock, we may be unable to pay dividends in cash on the common stock unless we can refinance amounts outstanding under those agreements. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is defined as the amount by which our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid from our net profits for the then current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.
 
Discoveries or acquisitions 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,


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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:
 
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in formations;
 
  •  equipment failures or accidents;
 
  •  fires, explosions, blowouts and surface cratering;
 
  •  marine risks such as capsizing, collisions and hurricanes;
 
  •  other adverse weather conditions; and
 
  •  increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.
 
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.
 
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.
 
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 groundwater 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 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


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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.
 
The Mariner and BP transactions have exposed us to additional risks and uncertainties with respect to the acquired businesses and their operations.
 
Although the acquired Mariner and BP businesses are generally subject to risks similar to those to which we are subject in our existing businesses, the Mariner and BP transactions may increase these risks. For example, the increase in the scale of our operations may increase our operational risks. The publicity associated with the oil spill in the Gulf of Mexico resulting from the fire and explosion onboard the Deepwater Horizon, which was under contract to BP, may cause regulatory agencies to scrutinize our operations more closely. This additional scrutiny may adversely affect our operations.
 
We may have difficulty combining the operations of both Mariner and the BP properties, and the anticipated benefits of these transactions may not be achieved.
 
Achieving the anticipated benefits of the Mariner and BP transactions will depend in part upon whether we can successfully integrate the operations of Mariner and the BP properties with ours. Our ability to integrate the operations of Mariner and the BP properties successfully will depend on our ability to monitor operations, coordinate exploration and development activities, control costs, attract, retain and assimilate qualified personnel and maintain compliance with regulatory requirements. The difficulties of integrating the operations of Mariner and the BP properties may be increased by the necessity of combining organizations with distinct cultures and widely dispersed operations. The integration of operations following these transactions will require the dedication of management and other personnel, which may distract their attention from the day-to-day business of the combined enterprise and prevent us from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transactions will be achieved.
 
Several significant matters in the BP Acquisition were not resolved before closing.
 
Because of the relatively short time period between signing the BP Purchase Agreements and the closing of the acquisition of the BP properties, several significant matters commonly resolved prior to closing such an acquisition have been reserved for after closing. We did not have sufficient time before closing on the BP Properties to conduct a full title review and environmental assessment. Although remedies are limited for title, we may discover adverse environmental or other conditions after closing and after the time periods specified in the BP Purchase Agreements during which we may be able to seek, in certain cases, indemnification from or cure of the defect or adverse condition by BP for such matters. For example, Apache Canada Ltd. has asserted a claim against BP Canada arising from the acquisition of certain Canadian properties under the BP Purchase Agreements. The dispute centers on Apache Canada Ltd.’s identification of Alleged Adverse Conditions, as that term is defined in the BP Purchase Agreements, and more specifically, the contention that liabilities associated with such conditions were retained by BP Canada as seller. There can be no assurance that we will prevail on this or any future claim against BP.
 
The BP Acquisition and/or our liabilities could be adversely affected in the event one or more of the BP entities become the subject of a bankruptcy case.
 
In light of the extensive costs and liabilities related to the oil spill in the Gulf of Mexico in 2010, there was public speculation as to whether one or more of the BP entities could become the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which we collectively refer to as “Insolvency Laws”). In the event that one or more of the BP entities were to become the subject of such a case or proceeding, a court may find that the BP Purchase Agreements are executory contracts, in which case such BP entities may, subject to relevant Insolvency Laws, have the right to reject the agreements and refuse to perform their future obligations under them. In this event, our ability to enforce our rights under the BP Purchase Agreements could be adversely affected.


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Additionally, in a case or proceeding under relevant Insolvency Laws, a court may find that the sale of the BP Properties constitutes a constructive fraudulent conveyance that should be set aside. While the tests for determining whether a transfer of assets constitutes a constructive fraudulent conveyance vary among jurisdictions, such a determination generally requires that the seller received less than a reasonably equivalent value in exchange for such transfer or obligation and the seller was insolvent at the time of the transaction, or was rendered insolvent or left with unreasonably small capital to meet its anticipated business needs as a result of the transaction. The applicable time periods for such a finding also vary among jurisdictions, but generally range from two to six years. If a court were to make such a determination in a proceeding under relevant Insolvency Laws, our rights under the BP Purchase Agreements, and our rights to the BP Properties, could be adversely affected.
 
Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly.
 
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we adopted effective December 31, 2009, our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
 
  •  historical production from the area compared with production from other areas;
 
  •  the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reserves reporting requirements;
 
  •  future operating costs;
 
  •  severance and excise taxes;
 
  •  development costs; and
 
  •  workover and remediation costs.
 
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
 
Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
 
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.


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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 effect 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.
 
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.
 
Pending regulations related to emissions and the impact of any changes in climate could adversely impact our business.
 
Legislation is pending in a number of countries where Apache operates including Australia, and Canada, the United Kingdom, that, if enacted, could tax or assess some form of greenhouse gas (GHG) related fees on Company operations and could lead to increased operating expenses. Such legislation, if enacted, could also potentially cause the Company to make significant capital investments for infrastructure modifications. Through 2011, three of the jurisdictions in which the Company has operations, Alberta and British Columbia, Canada and the United Kingdom (European Union), have enacted legislation which exposes the Company to financial payments related to GHG emissions from production facilities. This exposure has not been material to date.
 
Furthermore, various governmental entities in countries where Apache operates have discussed regulatory initiatives that could, if adopted, require the Company to modify existing or planned infrastructure to meet GHG emissions performance standards and necessitate significant capital expenditures. At some level, the cost of performance standards may force the early retirement of smaller production facilities, which in aggregate may have a material adverse effect on Apache’s business.
 
Several of the countries we operate in are signatories to current international accords related to climate change, such as the Kyoto Protocol to the United Nations Framework Convention on Climate Change. Given the current implementation of the Kyoto Protocol, we do not expect it to have a material impact on the Company.
 
Several indirect consequences of regulation and business trends have potential to impact us. Taxes or fees on carbon emissions could lead to decreased demand for fossil fuels. Consumers may prefer alternative products and unknown technological innovations may make oil and gas less significant energy sources.
 
In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact the Company’s assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.
 
The proposed U.S. federal budget for fiscal year 2012 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.
 
On February 14, 2011, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2012. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include: elimination of the ability to fully


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deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and natural gas companies; and an increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.
 
Proposed federal regulation regarding hydraulic fracturing could increase our operating and capital costs.
 
Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. We routinely use fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the well-bore. It is typically done at substantial depths in very tight formations.
 
Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.
 
A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on our business.
 
In 2010 our operations in Egypt contributed 28 percent of our production revenue, 25 percent of total production and 10 percent of total estimated proved reserves. In 2010 we sold all of our Egyptian gas production and 34 percent of our Egyptian oil production to the Egyptian General Petroleum Company (EGPC), the Egyptian state-owned oil company, and sold the remainder in the export market. As a result of political unrest, protests, riots, street demonstrations and acts of civil disobedience that began on January 25, 2011, in the Egyptian capital of Cairo, former Egyptian president Hosni Mubarak has stepped down, effective February 11, 2011. The Egyptian Supreme Council of the Armed Forces is now in power. On February 13, 2011, the Council announced that the constitution would be suspended, both houses of parliament would be dissolved, and that the military would rule for six months until elections can be held. Further changes in the political, economic and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition and results of 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 52 percent of our 2010 production was outside North America and approximately 30 percent of our estimated proved oil and gas reserves on December 31, 2010 were located outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:
 
  •  general strikes and civil unrest;
 
  •  the risk of war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts;
 
  •  import and export regulations;
 
  •  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
 
  •  price control;
 
  •  transportation regulations and tariffs;
 
  •  constrained natural gas markets dependent on demand in a single or limited geographical area;


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  •  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;
 
  •  laws and policies of the United States affecting foreign trade, including trade sanctions;
 
  •  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;
 
  •  the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and
 
  •  difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
 
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.
 
In recent weeks civil unrest, which started in Tunisia, has spread to the Middle East. Prolonged and/or widespread regional conflict in the Middle East could have the following results, among others:
 
  •  volatility in the global crude prices, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
 
  •  negative impact on the world’s crude oil supply if transportation avenues are disrupted, leading to further commodity price volatility;
 
  •  damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
 
  •  inability of our service equipment providers to deliver items necessary for us to conduct our operations in the Middle East;
 
  •  lack of availability of drilling rigs, oil field equipment or services if third party providers decide to exit the region.
 
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 and 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.
 
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


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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, geophysicists, 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 of the risks we face, which could result in significant financial exposure.
 
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other events such as blowouts, cratering, fire and explosion 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 and the environment. Our international operations are also subject to political risk. 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.
 
ITEM 1B.   UNRESOLVED SEC STAFF COMMENTS
 
As of December 31, 2010, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.
 
ITEM 3.   LEGAL PROCEEDINGS
 
The information set forth under “Legal Matters” and “Environmental Matters” in Note 8 — Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.
 
ITEM 4.   [REMOVED AND RESERVED]


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PART II
 
ITEM 5.   MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
During 2010 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 2010 and 2009. 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.
 
                                                                 
    2010     2009  
    Price Range     Dividends Per Share     Price Range     Dividends Per Share  
    High     Low     Declared     Paid     High     Low     Declared     Paid  
 
First Quarter
  $ 108.92     $ 95.15     $ .15     $ .15     $ 88.07     $ 51.03     $ .15     $ .15  
Second Quarter
    111.00       83.55       .15       .15       87.04       61.60       .15       .15  
Third Quarter
    99.09       81.94       .15       .15       95.77       65.02       .15       .15  
Fourth Quarter
    120.80       96.51       .15       .15       106.46       88.06       .15       .15  
 
The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2011 (last trading day of the month), was $119.36 per share. As of January 31, 2011, there were 382,752,217 shares of our common stock outstanding held by approximately 5,700 stockholders of record and approximately 440,000 beneficial owners.
 
We have paid cash dividends on our common stock for 46 consecutive years through December 31, 2010. 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 in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of 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 2010 annual meeting of stockholders, which is incorporated herein by reference.


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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, 2005, through December 31, 2010.
 
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, S&P 500 Index
and the Dow Jones US Exploration & Production Index
 
(PERFORMANCE GRAPH)
 
                                                             
      2005     2006     2007     2008     2009     2010
Apache Corporation
    $ 100.00       $ 97.70       $ 159.16       $ 111.05       $ 154.93       $ 180.12  
S & P’s Composite 500 Stock Index
      100.00         115.79         122.16         76.96         97.33         111.99  
DJ US Expl& Prod Index
      100.00         105.37         151.39         90.65         127.42         148.14  
                                                             
 
* $100 invested on 12/31/05 in stock including reinvestment of dividends.
Fiscal year ending December 31.


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2010, 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 set forth in Part IV, Item 15 of this Form 10-K. As discussed in more detail under Item 15, the 2009 numbers in the following table reflect a $2.82 billion ($1.98 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S. and Canadian proved oil and gas properties as of March 31, 2009, as a result of ceiling test limitations. The 2008 numbers 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 of or for the Year Ended December 31,  
    2010     2009     2008     2007     2006  
    (In millions, except per share amounts)  
 
Income Statement Data
                                       
Total revenues
  $ 12,092     $ 8,615     $ 12,390     $ 9,999     $ 8,309  
Income (loss) attributable to common stock
    3,000       (292 )     706       2,807       2,547  
Net income (loss) per common share:
                                       
Basic
    8.53       (.87 )     2.11       8.45       7.72  
Diluted
    8.46       (.87 )     2.09       8.39       7.64  
Cash dividends declared per common share
    .60       .60       .70       .60       .50  
Balance Sheet Data
                                       
Total assets
  $ 43,425     $ 28,186     $ 29,186     $ 28,635     $ 24,308  
Long-term debt
    8,095       4,950       4,809       4,012       2,020  
Shareholders’ equity
    24,377       15,779       16,509       15,378       13,191  
Common shares outstanding
    382       336       335       333       331  
 
For a discussion of significant acquisitions and divestitures, see Note 2 — Significant Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
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. We currently have exploration and production interests in seven countries: the U.S., Egypt, Australia, offshore the U.K. in the North Sea (North Sea), Argentina and Chile.
 
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, and the Risk Factors information set forth in Part I, Item 1A of this Form 10-K.
 
Executive Overview
 
Strategy
 
Apache’s mission is to grow a profitable global exploration and production company in a safe and environmentally responsible manner for the long-term benefit of our shareholders. Apache’s long-term perspective has many dimensions, with the following core strategic components:
 
  •  balanced portfolio of core assets;
 
  •  conservative capital structure; and
 
  •  rate of return focus.
 
A cornerstone of our strategy is balancing our portfolio through diversity of geologic risk, geographic risk, hydrocarbon mix (crude oil versus natural gas) and reserve life in order to achieve consistency in results. Our portfolio of geographic locations provides variation of all of these factors and, additionally, in the case of Australia and Argentina, the potential for increasing the value of our investments through rising natural gas prices. By maintaining a balanced hydrocarbon mix, we are protecting against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. For example, in 2010 oil and liquids provided 52 percent of our production but 77 percent of our total oil and gas revenues. We were well positioned to realize the benefit of higher oil prices, enabling record financial results despite North America natural gas prices that were under pressure most of the year.
 
Each operating region has a significant producing asset base as well as large undeveloped acreage positions which provide room for growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We closely monitor drilling and acquisition cost trends in each of our core areas relative to product prices and, when appropriate, adjust our budgets accordingly. We review capital allocations, at least quarterly, through a disciplined and focused process of reviewing internally-generated drilling prospects, opportunities for tactical acquisitions, land positions with additional drilling prospects or, occasionally, new core areas which could enhance our portfolio. In addition, we actively seek to identify and pursue ways to maintain efficient levels of costs and expenses. Our overall approach to managing cash expenditures has enabled us to consistently deliver strong results with 2010 return on average capital employed and return on equity of 12 percent and 15 percent, respectively.
 
Preserving financial flexibility is also important to our overall business philosophy. We ended 2010 with a year-end debt-to-capitalization ratio of 25 percent, an increase of only one percent from the prior year despite current-year capital investments of $17 billion, including acquisitions totaling more than $11 billion.
 
Throughout the cycles of our industry, these strategic principles have underpinned our ability to deliver production, reserve growth and competitive investment rates of return for the benefit of our shareholders. Delivering successful results under this strategy is bolstered by Apache’s unique culture. A strong sense of urgency, empowerment of our employees, effective incentive systems and an independent mindset are at the heart of how we build value.


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Financial and Operating Results
 
While Apache has grown into a much larger company than it was a year ago, we have stayed true to our business model, focusing on rate of return and cash-generating assets. Although the year 2010 will be remembered for the level of acquisition activity, the record financial results reflected continued growth and positive returns. For the 12-month period ending December 31, 2010, Apache reported record performances in several key metrics. Highlights for the year include:
 
  •  Annual daily production of oil, natural gas, and natural gas liquids averaged a record 658,000 boe/d, up 13 percent compared with 2009. Production in fourth-quarter 2010 averaged 729,000 boe/d, an increase of 24 percent from the 590,000 boe/d averaged in the fourth quarter of 2009.
 
  •  Oil and gas production revenues for 2010 increased 42 percent to $12.1 billion, up from $8.6 billion in 2009, and just shy of the record $12.3 billion in 2008 when prices reached record levels.
 
  •  Apache reported a record $3 billion in net income, or $8.46 per common diluted share, compared to a net loss of $292 million, or $.87 per share in the 2009 period. Apache’s 2009 results were impacted by a $1.98 billion after-tax write-down of the carrying value of proved property. Apaches 2010 reported adjusted earnings(1), which exclude certain items impacting the comparability of results, were approximately $3.17 billion or $8.94 per common diluted share, up from $1.89 billion or $5.59 per common diluted share in the prior year.
 
  •  Net cash provided by operating activities (operating cash flows or cash flows) totaled $6.7 billion, up 60 percent from $4.2 billion in 2009.
 
  •  Estimated proved reserves at year-end 2010 were a record 2,953 MMboe, up 25 percent from 2009 estimated proved reserves of 2,367 MMboe.
 
(1) See Non-GAAP Measures — Adjusted Earnings for a description of Adjusted Earnings, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation to this measure from Income (Loss) Attributable to Common Stock, which is presented in accordance with GAAP.
 
2011 Outlook
 
As we head into 2011, we project Apache’s financial position will remain strong, given our debt-to-capitalization ratio of 25 percent, $2.4 billion of available committed borrowing capacity, projections of higher cash flows than 2010 levels and determination to hold exploration and development spending within our internally-generated cash flows. Given the present price disparity between oil and natural gas, our near-term focus is exploiting the oily and more liquids-rich properties in our portfolio and development of our gas resources in Australia and Canada, which we plan to convert to LNG and sell in the worldwide LNG market. As is the Apache way, rates of return will drive our decision making while we continue our focus on costs, operational efficiency and integrating the acquired assets. In 2011 we find ourselves with more opportunities than we can fund through internally-generated cash flow, and our challenge will be to optimize capital spending across our worldwide portfolio.
 
Our current 2011 capital budget includes exploration and development capital of approximately $7.5 billion. Nearly $4.0 billion is expected to be spent on projects in North America, with the remaining amount allocated across our international regions. An estimated one-third of our global capital budget is allocated to seismic and leasehold, GTP facilities and plugging and abandonment activities. While funds have been committed for certain 2011 exploration drilling, long-lead development projects and FEED studies, the majority of our drilling and development projects are discretionary and subject to acceleration, deferral or cancellation as conditions warrant. We closely monitor commodity prices, service cost levels, regulatory impacts and other numerous industry factors and will adjust our exploration and development budgets based on changes to predicted operating cash flow. We typically review and revise our exploration and development capital budgets on a quarterly basis.
 
Based on the current capital spending budget and the acquisitions completed during 2010, Apache expects to increase overall production in 2011 between 13 percent and 17 percent from full-year 2010 production levels. These projections exclude the impact from any potential acquisitions or divestitures.


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The Company is currently planning to divest approximately $1.0 billion of properties to optimize and high-grade our existing portfolio of assets. The divestiture package will most likely include legacy conventional properties in Canada. However, as of the date of this filing we have not entered into any binding contracts to sell these assets. We generally do not budget for acquisitions because they are specific, discrete events whose occurrence and timing is unpredictable. Acquisitions may be funded from operating cash flows, credit facilities, new equity, debt issuances or a combination thereof.
 
Operating Highlights
 
Current Year
 
During 2010 we completed more than $11 billion of acquisitions, continued progress on developing existing core properties and expanded into new geographic areas. Through these steps, we added significantly to drilling inventory in our core areas and established a footprint in two new areas: deepwater exploration and LNG, which for us means the monetization of large gas resources at oil-linked prices.
 
Merger and Acquisitions of Property and Acreage
 
From 2007 to 2009 we were relatively absent from the acquisition market. We believed the market was overheated as oil and gas prices spiked, and the opportunities we identified did not meet our criteria for risk, reward and/or growth potential. We built our cash position while drilling our existing inventory of prospects and waiting for the right transactions to supplement it.
 
  •  In June we completed the $1.05 billion acquisition of Devon Energy Corporation’s oil and gas assets on the Gulf of Mexico (GOM) shelf, 75 percent of which are in fields now operated by Apache. The acquired assets include 477,000 net acres across 150 blocks. The Company believes that these well-maintained, high-quality assets fit well with Apache’s existing infrastructure and play to the strengths that come with our experience operating on the shelf, exploiting the current production base and capturing upside potential.
 
  •  In August we completed the $2.5 billion acquisition of oil and gas operations, acreage and infrastructure in the Permian Basin from BP plc (BP), solidifying our position as one of the most active operators in the area, where Apache has been competing for 20 years. The acquisition more than doubled our footprint in the Permian Basin to over three million gross acres.
 
  •  In October we completed the $3.25 billion acquisition of substantially all of BP’s upstream natural gas business in western Alberta and British Columbia, including 1.3 million net mineral and leasehold acres with significant positions in several emerging unconventional plays, such as the Noel tight-gas project, which ramped up to 100 MMcf/d by the end of the fourth quarter. We own a 100-percent working interest in the Noel project.
 
  •  In November we closed on the purchase of BP assets in Egypt’s Western Desert for $650 million, acquiring four development leases and one exploration concession as well as strategically-positioned infrastructure that will enable Apache to increase production from existing fields in the Western Desert.
 
  •  Also in November, shareholders of Mariner Energy, Inc. (Mariner) approved the purchase of their company by Apache for stock and cash consideration totaling $2.7 billion. We also assumed approximately $1.7 billion of Mariner’s debt with the merger. Apache established a strategic presence in the deepwater Gulf of Mexico and expanded our positions in the GOM shelf, Gulf Coast and Permian Basin with the acquisition. The acquisition also provides deepwater geoscience expertise, including a core competency in subsea tieback developments, which can significantly reduce the cycle time between exploration success and initial production.
 
  •  During the first quarter of 2010 Apache Canada Ltd. (Apache Canada), through its subsidiaries, closed the acquisition of a 51-percent interest in a planned LNG export terminal (Kitimat LNG facility) and a 25.5-percent interest in a partnership that owns a related proposed pipeline. EOG Resources Canada, Inc. (EOG


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  Canada) owns the remaining 49 percent of the Kitimat LNG facility and a 24.5-percent interest in the pipeline partnership. In February 2011 Apache Canada and EOG Canada entered into an agreement to purchase the remaining 50-percent interest in the partnership. Upon close of the transaction, Apache Canada and EOG Canada will own 51 percent and 49 percent, respectively, of the pipeline partnership and proposed pipeline.
 
  •  In Australia, during 2010 we expanded our exploration opportunities in the Carnarvon and Exmouth basins via farm-ins to seven permits. The transactions resulted in a 58-percent increase in our net undeveloped acreage in the Carnarvon basin and added 1.9 million acres for exploration in the Exmouth basin. We will operate all of them with a 20- to 70-percent working interest.
 
  •  In the North Sea, we expanded our acreage position during the year through successful bids on four exploration licenses and farming into two additional licenses with a 50-percent working interest.
 
Egypt 2X Gross Production Achievement
 
Apache’s Egypt operations had another year of growth in 2010, with gross daily production rising 16 percent to 322.5 Mboe/d and net daily production rising six percent to an average of 161.7 Mboe/d for the year. During the year the Company surpassed its late-2005 goal of doubling its Western Desert production within five years. Achievement of the goal was driven in part by production from several discoveries in the Faghur and Matruh basins, infrastructure improvements including two new Salam gas trains, expansion of the capacity of the Kalabsha oil processing and transportation facilities to 40,000 b/d and completion of a major strategic compression project on Egypt’s northern gas pipeline. The Faghur and Matruh basins, where the thickness of the sands and the stacked pay zones present multiple opportunities for further exploration across our acreage, will continue to be focus areas for Apache in 2011.
 
Van Gogh and Pyrenees Oil Fields Development
 
Australia’s 2010 production averaged a record 79.2 Mboe/d, driven by the Apache-operated Van Gogh oil field and BHP Billiton-operated Pyrenees oil field, both of which commenced production early in 2010. The Van Gogh and Pyrenees developments utilize Floating Production Storage and Offloading (FPSO) vessels and together added 42.2 Mb/d to Apache’s 2010 net oil production. Both projects have already reached payout.
 
Organic Growth Drivers 2011 to 2013
 
Australia Reindeer Field Development and Devil Creek Gas Plant
 
Our Reindeer field discovery is projected to commence production in 2011 upon completion of the Devil Creek Gas Plant. The Devil Creek Gas Plant is scheduled to be commissioned in the fourth quarter of 2011. This will be Western Australia’s first new domestic natural gas processing hub in more than 15 years. The two-train plant is designed to process 200 MMcf/d from the Apache-operated Reindeer Field. In 2009 we entered into a gas sales contract covering a portion of the field’s future production. Under the contract, Apache and our joint venture partner agreed to supply 154 Bcf of gas over seven years (approximately 60 MMcf/d) beginning in the fourth quarter of 2011 at prices substantially higher than we have historically received in Western Australia. Apache owns a 55-percent interest in the field.
 
Australia Halyard Field Development
 
Initial production from our Halyard-1 discovery well in Australia is projected for 2011 upon completion of the tie-in to the existing gas facilities on Varanus Island. The extension of this subsea infrastructure will also connect the 2010 Spar-2 discovery and allow for tie-in of future wells.
 
North Sea Satellite Platform
 
In November Apache entered into a contract to build a new satellite oil production platform for our UK Forties field. The new platform will be bridge-linked to our existing Forties Alpha installation in the Apache-operated field, located on the U.K. continental shelf. This project will provide Apache with 18 new slots for drilling additional development wells to increase the ultimate recovery from the Forties field. The satellite platform will also expand


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critical utility services to the field, including power generation, produced fluid processing, high-pressure gas compression for artificial lift and dehydration. Construction is projected to be complete by mid-year 2012.
 
Australia Macedon Field Development
 
The Macedon gas field’s four development wells, which were completed in 2010, will be delivered via a 60-mile pipeline to a 200 MMcf/d gas plant to be built at Ashburton North in Western Australia. We have a 28-percent non-operated working interest in the field. The project, approved in 2010, is currently underway, with first production projected in 2013.
 
Australia Coniston Oil Field Discovery
 
The Coniston field is an oil accumulation near our Van Gogh field in Australia. Apache drilled 10 appraisal wells during 2009, and current plans call for subsea completions tied back to the Van Gogh field FPSO Ningaloo Vision. The project has been sanctioned for development, with first production into the domestic market projected in 2013.
 
North America Unconventional Gas Plays
 
The identification and development of significant resources in shale formations and other unconventional gas plays have introduced substantial gas supplies into North American natural gas markets for the foreseeable future. Although Apache’s current production in North America is primarily conventional, near-term gas production growth will likely be driven by our activity in three large unconventional plays: shale gas in British Columbia’s Horn River basin, tight sands in British Columbia’s Noel area and the Granite Wash tight sands in the Anadarko basin of Oklahoma and the Texas Panhandle.
 
Horizontal Drilling and Completion Techniques
 
Apache continues to evaluate horizontal drilling potential across our acreage positions around the world, in both conventional and unconventional reservoirs. In the Permian Basin, Apache is utilizing horizontal drilling to access bypassed, unswept zones in established waterfloods. We are currently drilling our first horizontal shale well in Argentina, targeted for completion in April. In addition, we plan to drill our first horizontal well in the Western Desert of Egypt in 2011. The Company will continue to evaluate our opportunities utilizing horizontal drilling technology.
 
Organic Growth Drivers 2014 and Beyond
 
Australia Balnaves Oil Field Discovery Development
 
In October 2010 we announced three successful wells appraising our Balnaves-1 discovery, an oil accumulation in a separate reservoir beneath the large gas reservoirs of our Brunello gas fields (discussed below). The project is currently in the FEED stage, with plans to develop the field through a new FPSO. First production, if the decision is made to go forward with the project, is projected for 2014.
 
Julimar and Brunello Field Discoveries Development/Wheatstone LNG Project
 
In 2016, we are projecting to begin production from our operated Julimar and Brunello field gas discoveries through the Chevron operated Wheatstone LNG hub, in which we own a foundation equity partner interest of 13 percent. Apache’s projected net gas sales from the fields are 160 MMcf/d and 3,250 b/d with a projected 15-year production plateau when the multi-year project is fully operational. The Wheatstone project, which is currently in FEED, will convert the gas into LNG for sale on the world market. World LNG prices are typically oil-linked prices and are currently higher than the historical gas prices in Western Australia. The project Final Investment Decision (FID) is scheduled for 2011, with first LNG projected in 2016. Nonbinding Heads of Agreements have been signed with LNG buyers and final binding sales and purchase agreements will be completed by FID.


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Kitimat/Horn River Basin Development
 
Apache’s time horizon and magnitude of our Horn River basin shale gas development is impacted by North American gas prices and the completion of the Kitimat LNG facility and a related proposed pipeline. The project has the potential to open new markets linked to oil prices in the Asia-Pacific region for gas from Apache’s Canadian operations, including the Horn River basin area in northeast British Columbia. Apache Canada and EOG Canada plan to build the Kitimat LNG facility on Bish Cove near the Port of Kitimat, 400 miles north of Vancouver, British Columbia. The facility is planned for an initial minimum capacity of 700 MMcf/d, or five million metric tons of LNG per year, of which Apache Canada has reserved 51 percent. The proposed 287-mile pipeline will originate in Summit Lake, British Columbia, and is designed to link the Kitimat LNG facility to the pipeline system currently servicing western Canada’s natural gas producing regions. Apache Canada will have rights to 51-percent of the capacity in the proposed pipeline. Completion of the FEED study and a final investment decision are targeted for late 2011. Construction is expected to commence in 2012, with commercial operations projected to begin in 2015.
 
GOM Deepwater
 
Apache has built deepwater experience and a record of success in Egypt, Australia and the Gulf of Mexico, on both the exploration and development sides. The GOM deepwater portfolio gained in the Mariner merger adds over 100 blocks and offers a strategic position into a significant potential growth area in the United States that can add meaningful oil reserves and production over the long term. Exploration potential is generated from Mariner’s extensive track record of 36 deepwater development projects completed to date and the technological developments in seismic and facilities making exploration more predictable, lower risk and lower cost. Our pipeline of development projects include the non-operated Heidelberg (12.5-percent net working interest) and Lucius (16.67-percent net working interest) discoveries, which are still under further appraisal and study for ultimate development.
 
Significant Events
 
Impact of Deepwater Drilling Moratorium on Gulf of Mexico Operations
 
In 2010 the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) announced a series of moratoria, which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the Outer Continental Shelf (OCS), and put oil and gas lessees and operators on notice that, with certain exceptions, the BOEMRE would not consider drilling permits for deepwater wells and related activities. While the moratoria have been formally lifted, no new permits for deepwater drilling have been issued as of the date of this filing.
 
In addition, the BOEMRE issued new regulations in 2010 requiring additional information, documentation and analysis for all new wells on the OCS. The effect of these new regulations was to significantly slow down issuance of permits for shallow wells. Apache continues to operate under these new regulations and, through February 2011, has received 25 drilling permits for shallow wells. Current permitting activity has been slowed compared to prior-year levels, and the Company has budgeted its exploration and development activity accordingly.
 
Impact of Recent Political Changes on Egyptian Operations
 
In 2010 our operations in Egypt contributed 28 percent of our production revenue, 25 percent of total production and 10 percent of total estimated proved reserves. In 2010 we sold all of our Egyptian gas production and 34 percent of our Egyptian oil production to Egyptian General Petroleum Company (EGPC), the Egyptian state-owned oil company. The remainder of our oil was sold in the export market.
 
As a result of political unrest, protests, riots, street demonstrations and acts of civil disobedience that began on January 25, 2011, in the Egyptian capital of Cairo, Egyptian president Hosni Mubarak stepped down, effective February 11, 2011. The Egyptian Supreme Council of the Armed Forces assumed power. On February 13, 2011, the Council announced that the constitution would be suspended, both houses of parliament would be dissolved, and the military would rule for six months until elections can be held. Following the advice of the U.S. State Department, Apache evacuated all non-essential personnel from Egypt. As conditions stabilized, approximately one-third of the


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evacuated employees returned. Apache’s production, located in remote locations in the Western Desert, has continued uninterrupted; however, further changes in the political, economic and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition and results of operations.
 
Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and highly rated international insurers covering its investments in Egypt. In the aggregate, these policies, subject to the policy terms and conditions, provide approximately $1 billion of coverage to Apache covering losses arising from confiscation, nationalization, and expropriation risks and currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the Government of Egypt prevent Apache from exporting our share of production.
 
Operations Downtime
 
Production from our Van Gogh oil field was impacted by essential maintenance activities on the FPSO. Net fourth quarter production of 6,100 b/d was down 17,600 b/d from the previous quarter. Production resumed in the first half of February 2011.
 
In January 2011 a subsea pipeline connecting our Forties Bravo platform to our Charlie platform was shut-in because of corrosion. A project is underway to re-route the production through a smaller line until a new flexible pipeline is installed. This intermediate solution should be completed by the first of March 2011 and will allow us to produce approximately half of the 11,600 b/d that flowed through the main pipeline. The new main subsea pipeline will be completed by September 2011.


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Results of Operations
 
Oil and Gas Revenues
 
                                                 
    For the Year Ended December 31,  
    2010     2009     2008  
          %
          %
          %
 
    $ Value     Contribution     $ Value     Contribution     $ Value     Contribution  
    (In millions)           (In millions)           (In millions)        
 
Oil Revenues:
                                               
United States
  $ 2,683       30 %   $ 1,922       32 %   $ 2,751       34 %
Canada
    388       4 %     311       5 %     587       7 %
                                                 
North America
    3,071       34 %     2,233       37 %     3,338       41 %
                                                 
Egypt
    2,875       32 %     2,063       34 %     2,232       27 %
Australia
    1,296       14 %     230       4 %     277       3 %
North Sea
    1,590       18 %     1,356       22 %     2,085       26 %
Argentina
    209       2 %     207       3 %     225       3 %
                                                 
International
    5,970       66 %     3,856       63 %     4,819       59 %
                                                 
Total(2)
  $ 9,041       100 %   $ 6,089       100 %   $ 8,157       100 %
                                                 
Natural Gas Revenues:
                                               
United States
  $ 1,409       49 %   $ 1,054       44 %   $ 2,204       56 %
Canada
    647       23 %     546       23 %     1,026       26 %
                                                 
North America
    2,056       72 %     1,600       67 %     3,230       82 %
                                                 
Egypt
    495       17 %     490       21 %     507       13 %
Australia
    163       6 %     133       6 %     95       2 %
North Sea
    16       0 %     13       0 %     18       0 %
Argentina
    132       5 %     133       6 %     115       3 %
                                                 
International
    806       28 %     769       33 %     735       18 %
                                                 
Total(3)
  $ 2,862       100 %   $ 2,369       100 %   $ 3,965       100 %
                                                 
Natural Gas Liquids (NGL) Revenues:
                                               
United States
  $ 208       74 %   $ 74       64 %   $ 128       62 %
Canada
    39       14 %     20       17 %     38       19 %
                                                 
North America
    247       88 %     94       81 %     166       81 %
                                                 
Egypt
    2       1 %           0 %           0 %
Argentina
    31       11 %     22       19 %     40       19 %
                                                 
International
    33       12 %     22       19 %     40       19 %
                                                 
Total
  $ 280       100 %   $ 116       100 %   $ 206       100 %
                                                 
Total Oil and Gas Revenues:
                                               
United States
  $ 4,300       35 %   $ 3,050       36 %   $ 5,083       41 %
Canada
    1,074       9 %     877       10 %     1,651       14 %
                                                 
North America
    5,374       44 %     3,927       46 %     6,734       55 %
                                                 
Egypt
    3,372       28 %     2,553       30 %     2,739       22 %
Australia
    1,459       12 %     363       4 %     372       3 %
North Sea
    1,606       13 %     1,369       16 %     2,103       17 %
Argentina
    372       3 %     362       4 %     380       3 %
                                                 
International
    6,809       56 %     4,647       54 %     5,594       45 %
                                                 
Total(1)
  $ 12,183       100 %   $ 8,574       100 %   $ 12,328       100 %
                                                 
 
 
(1) Financial derivative hedging activities increased oil and gas production revenues for 2010 and 2009 by $165.3 million and $180.8 million, respectively, and decreased oil and gas production revenues for 2008 by $458.7 million.


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(2) Financial derivative hedging activities decreased 2010 oil revenues by $57.0 million, increased 2009 oil revenues by $45.2 million and decreased 2008 oil revenues by $450.8 million.
 
(3) Financial derivative hedging activities increased natural gas revenues for 2010 and 2009 by $222.3 million and $135.6 million, respectively, and decreased natural gas revenues for 2008 by $7.9 million.
 
Production
 
                                         
    For the Year Ended December 31,  
          Increase
          Increase
       
    2010     (Decrease)     2009     (Decrease)     2008  
 
Oil Volume — b/d:
                                       
United States
    96,576       +8 %     89,133       −1 %     89,797  
Canada
    14,581       −4 %     15,186       −11 %     17,154  
                                         
North America
    111,157       +7 %     104,319       −2 %     106,951  
                                         
Egypt
    99,122       +8 %     92,139       +38 %     66,753  
Australia
    45,908       +369 %     9,779       +19 %     8,249  
North Sea
    56,791       −7 %     60,984       +3 %     59,494  
Argentina
    9,956       −13 %     11,505       −7 %     12,409  
                                         
International
    211,777       +21 %     174,407       +19 %     146,905  
                                         
Total(1)
    322,934       +16 %     278,726       +10 %     253,856  
                                         
Natural Gas Volume — Mcf/d:
                                       
United States
    730,847       +10 %     666,084       −2 %     679,876  
Canada
    396,005       +10 %     359,235       +2 %     352,731  
                                         
North America
    1,126,852       +10 %     1,025,319       −1 %     1,032,607  
                                         
Egypt
    374,858       +3 %     362,618       +38 %     263,711  
Australia
    199,729       +9 %     183,617       +49 %     123,003  
North Sea
    2,391       −12 %     2,703       +3 %     2,637  
Argentina
    184,830       0 %     184,557       −6 %     195,651  
                                         
International
    761,808       +4 %     733,495       +25 %     585,002  
                                         
Total(2)
    1,888,660       +7 %     1,758,814       +9 %     1,617,609  
                                         
NGL Volume — b/d:
                                       
United States
    13,777       +125 %     6,136       +3 %     5,986  
Canada
    2,884       +38 %     2,089       +1 %     2,076  
                                         
North America
    16,661       +103 %     8,225       +2 %     8,062  
                                         
Egypt
    82       N/A             N/A        
Argentina
    3,180       −2 %     3,241       +12 %     2,887  
                                         
International
    3,262       +1 %     3,241       +12 %     2,887  
                                         
Total
    19,923       +74 %     11,466       +5 %     10,949  
                                         
BOE per day(3)
                                       
United States
    232,161       +13 %     206,284       −1 %     209,097  
Canada
    83,466       +8 %     77,147       −1 %     78,018  
                                         
North America
    315,627       +11 %     283,431       −1 %     287,115  
                                         
Egypt
    161,680       +6 %     152,575       +38 %     110,704  
Australia
    79,196       +96 %     40,382       +40 %     28,750  
North Sea
    57,190       −7 %     61,435       +3 %     59,934  
Argentina
    43,941       −3 %     45,505       −5 %     47,904  
                                         
International
    342,007       +14 %     299,897       +21 %     247,292  
                                         
Total
    657,634       +13 %     583,328       +9 %     534,407  
                                         
 
 
(1) Approximately 12 percent of 2010 oil production was subject to financial derivative hedges, compared to 10 percent in 2009 and 19 percent in 2008.


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(2) Approximately 23 percent of 2010 gas production was subject to financial derivative hedges, compared to nine percent in 2009 and 20 percent in 2008.
 
(3) The table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.
 
Pricing
 
                                         
    For the Year Ended December 31,  
          Increase
          Increase
       
    2010     (Decrease)     2009     (Decrease)     2008  
 
Average Oil price — Per barrel:
                                       
United States
  $ 76.13       +29 %   $ 59.06       −29 %   $ 83.70  
Canada
    72.83       +30 %     56.16       −40 %     93.53  
North America
    75.69       +29 %     58.64       −31 %     85.28  
Egypt
    79.45       +30 %     61.34       −33 %     91.37  
Australia
    77.32       +20 %     64.42       −30 %     91.78  
North Sea
    76.66       +26 %     60.91       −36 %     95.76  
Argentina
    57.47       +16 %     49.42       0 %     49.46  
International
    77.21       +27 %     60.58       −32 %     89.63  
Total(1)
    76.69       +28 %     59.85       −32 %     87.80  
Average Natural Gas price — Per Mcf:
                                       
United States
  $ 5.28       +22 %   $ 4.34       −51 %   $ 8.86  
Canada
    4.48       +7 %     4.17       −47 %     7.94  
North America
    5.00       +17 %     4.28       −50 %     8.55  
Egypt
    3.62       −2 %     3.70       −30 %     5.25  
Australia
    2.24       +13 %     1.99       −5 %     2.10  
North Sea
    18.64       +42 %     13.15       −30 %     18.78  
Argentina
    1.96       0 %     1.96       +22 %     1.61  
International
    2.90       +1 %     2.87       −16 %     3.43  
Total(2)
    4.15       +12 %     3.69       −45 %     6.70  
Average NGL Price — Per barrel:
                                       
United States
  $ 41.45       +26 %   $ 33.02       −44 %   $ 58.62  
Canada
    36.61       +43 %     25.54       −48 %     49.33  
North America
    40.62       +31 %     31.12       −45 %     56.23  
Egypt
    69.75       N/A             N/A        
Argentina
    27.08       +44 %     18.76       −50 %     37.83  
International
    28.15       +50 %     18.76       −50 %     37.83  
Total
    38.58       +40 %     27.63       −46 %     51.38  
 
 
(1) Reflects per-barrel decrease of $.48 in 2010, an increase of $.44 in 2009 and a reduction of $4.85 in 2008 from financial derivative hedging activities.
 
(2) Reflects per-Mcf increase of $.32 in 2010 and $.21 in 2009 and a reduction of $.01 in 2008 from financial derivative hedging activities.
 
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 the Company’s control. Prices we received for crude oil in 2010 were 28 percent above 2009 with economies stabilizing or growing across the globe. Apache uses financial instruments to manage a


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portion of its exposure to fluctuations in crude oil prices, particularly in North America. In 2010, 12 percent of our oil production was subject to financial derivative hedges, reducing revenues by $57 million. In 2009, 10 percent of our oil production was hedged, increasing oil revenue by $45 million. For the year-end status of our derivatives, please see Note 3 — Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
While the market price received for crude oil varies among geographic areas, crude oil tends to trade at a global price. With the exception of Argentina, price movements for all types and grades of crude oil generally move in the same direction. In Australia, Apache continues to directly market all of our crude oil production into Australian domestic and international markets at prices indexed to Dated Brent benchmark crude oil prices plus a premium, which are typically above NYMEX oil prices. In Argentina, we currently sell our oil in the domestic market. The Argentine government imposes a sliding-scale tax on oil exports, which significantly influences prices domestic buyers are willing to pay. Domestic oil prices are currently indexed to a $42 per barrel base price, subject to quality adjustments and local premiums, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar pricing formulas exist, but producers retain a value-added tax collected from buyers, effectively increasing price realizations by 21 percent.
 
Natural Gas Prices
 
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices. Apache uses a variety of fixed-price contracts and derivatives to manage our exposure to fluctuations in natural gas prices, primarily in North America. In 2010, 23 percent of our gas production was subject to financial derivative hedges, increasing revenues by $222 million. In 2009, nine percent of our gas production was hedged, increasing gas revenue by $136 million. For the year-end status of our derivatives, please see Note 3 — Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
Apache primarily sells natural gas into the North American market, where spot prices increased 17 percent compared to 2009, and various international markets, where our average contracted prices rose just one percent from 2009. Our primary markets include North America, Egypt, Australia and Argentina.
 
  •  North America has a common market; most of our gas is sold on a monthly or daily basis at either monthly or daily market prices.
 
  •  In Egypt our gas is sold to EGPC, with a majority 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 of gross production, there is no price cap for our gas under a legacy contract, which expires at the end of 2012. Overall, the region averaged $3.62 per Mcf in 2010.
 
  •  Australia has a local market with a limited number of buyers and sellers resulting in mostly long-term, fixed-price contracts that are periodically adjusted for changes in the local consumer price index. Recent increases in demand and higher development costs have increased the prices required from the local market in order to support the development of new supplies. As a result, market prices received on recent contracts, including our Reindeer field, are substantially higher than historical levels.
 
  •  In Argentina we receive 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 2010 we realized an average price of $1.20 per Mcf on government-regulated sales. The majority of the remaining volumes were sold at market-driven prices, which averaged $2.65 per Mcf in 2010. Our overall average realized price for 2010 was $1.96 per Mcf, the same as our 2009 average realized price and 22 percent higher than 2008 average realized price ($1.61 per Mcf).
 
During 2010 Apache signed three Gas Plus contracts totaling 63 MMcf/d of gross production from fields in the Neuquén and Rio Negro Provinces. Gas Plus is a program instituted by the Argentine government to encourage new gas supplies through the development of tight sands and unconventional reserves. The first contract, for 10 MMcf/d at $4.10 per MMBtu, has been extended through 2011 for 11 MMcf/d at $4.10 per


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MMbtu. Our other two Gas Plus contracts, for a total of 53 MMcf/d at $5.00 per MMBtu, are projected to commence in the first quarter of 2011. The gas supplying the Gas Plus program contracts is required to come from wells drilled in the projects’ approved fields and formations. We believe the Gas Plus program, coupled with changing market conditions, point to improving price realizations going forward.
 
For more specific information on marketing arrangements by country, please refer to Part I, Items 1 and 2 — Business and Properties of this Form 10-K.
 
Crude Oil Revenues
 
2010 vs. 2009 During 2010 crude oil revenues totaled $9.0 billion, $2.9 billion higher than the 2009 total of $6.1 billion, driven by a 16-percent increase in worldwide production and a 28-percent increase in average realized prices. Average daily production in 2010 was 322.9 Mb/d, with prices averaging $76.69 per barrel. Crude oil represented 74 percent of our 2010 oil and gas production revenues and 49 percent of our equivalent production, compared to 71 and 48 percent, respectively, in the prior year. Higher realized prices contributed $1.7 billion to the increase in full-year revenues, while higher production volumes added another $1.2 billion.
 
Worldwide oil production increased 44.2 Mb/d, driven by a 36.1 Mb/d increase in Australia on new production from the Van Gogh and Pyrenees discoveries, which were brought online in the first quarter of 2010. U.S. production increased eight percent, or 7.4 Mb/d, with the Permian region up 4.4 Mb/d on properties added from the BP acquisitions, the Mariner merger and drilling and recompletion activity. The Gulf Coast region added 1.8 Mb/d from properties acquired in the Devon acquisition, the Mariner merger and drilling and recompletion activity. Central region production increased 1.2 Mb/d on drilling and recompletion activity. Gross production in Egypt increased 17 percent, while net production was up only eight percent, a function of the mechanics of our production-sharing contracts. Net production increased 7.0 Mb/d on production gains in the Shushan, Matruh and numerous other concessions. Additional capacity at the Kalabsha oil processing facility, as well as processing of condensate-rich gas through the Salam Gas Plant allowed by the new Jade manifold, allowed for much of the production gains. North Sea production decreased 4.2 Mb/d on natural decline and downtime. Production in Argentina and Canada declined 1.5 Mb/d and .6 Mb/d, respectively, on natural decline.
 
2009 vs. 2008  Crude oil accounted for 48 percent of our equivalent production and 71 percent of oil and gas production revenues during 2009, compared to 48 and 66 percent, respectively, for 2008. Impacted by dramatically lower oil prices realized during the global financial crisis that began in late 2008, crude oil revenues for 2009 totaled $6.1 billion, $2.1 billion lower than the prior year. A 32-percent decline in average realized prices reduced revenues $2.6 billion, of which $528 million was offset by the impact of 10 percent production growth.
 
Worldwide production increased 24.9 Mb/d despite curtailed capital spending, which was 40 percent lower than 2008. Egypt’s oil production increased 38 percent or 25.4 Mb/d on exploration successes in numerous concessions, most notably East Bahariya Extension, South Umbarka, Matruh, Northeast Abu Gharadig Extension and Khalda, waterflood projects and increased condensate from additional Qasr gas flowing through the new processing trains at the Salam Gas Plant. Australia’s production was up 1.5 Mb/d, as production was restored following completion of repairs at Varanus Island. North Sea production increased 1.5 Mb/d on strong drilling results, which offset the impact of unplanned downtime at the Bravo Platform, which lowered 2009 average daily oil production by 2.6 Mb/d. The Bravo Platform was down for most of the fourth quarter for pipeline repairs. Production declined 2.0 Mb/d in Canada, .9 Mb/d in Argentina and .7 Mb/d in the U.S., as natural decline offset results from our curtailed 2009 drilling programs.
 
Natural Gas Revenues
 
2010 vs. 2009  Natural gas revenues for 2010 of $2.9 billion were $493 million higher than 2009 on a 12-percent increase in realized prices and a seven-percent increase in production volumes. Realized prices in 2010 averaged $4.15 per Mcf and the $.46 per Mcf increase added $297 million to revenues. Worldwide production rose 130 MMcf/d, adding another $197 million to revenues.
 
Worldwide gas production rose in all of our core gas-producing regions. U.S. production was up 64.8 MMcf/d, or 10 percent. Driven by new drilling, recompletion activity and properties acquired from Devon and the Mariner


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merger, Gulf Coast region production was up 38.2 MMcf/d. Permian region production was up 20.1 MMcf/d, primarily on volumes from properties acquired from BP. Central region production was up 6.5 MMcf/d as additional production from new drilling and recompletions outpaced natural decline. An active drilling and completion program at Horn River and additional volumes from properties acquired from BP led Canada region production 36.8 MMcf/d higher. Production in Australia was up 16.1 MMcf/d on higher customer takes from our John Brookes field. In Egypt, gross production was up 14 percent, while net production rose only three percent, a function of our production-sharing contracts. The 12.2 MMcf/d increase in net production relative to 2009 was attributable to several factors, including a successful drilling and recompletion program on our Matruh concession, additional volumes processed through the Obaiyed Gas Plant and a full year of additional capacity provided by the completion of two new gas trains at the Salam Gas Plant. Argentina’s production was up marginally as production from new drilling and recompletions was mostly offset by natural decline.
 
2009 vs. 2008  Natural gas accounted for 50 percent of our equivalent production and 28 percent of our oil and gas production revenues during 2009, compared to 50 and 32 percent, respectively, for 2008. Impacted by dramatically lower gas prices realized during the global financial crisis that began in late 2008, gas revenues for 2009 totaled $2.4 billion, down $1.6 billion from 2008. A 45-percent decline in average realized prices reduced revenues $1.8 billion, partially offset by the $184 million impact of a nine percent increase in production.
 
Worldwide production grew 141 MMcf/d, driven by a 99 MMcf/d increase in Egypt’s net production and a 61 MMcf/d increase in Australia. Egypt’s gas production was up 38 percent on exploration successes at our Khalda and Matruh concessions and additional plant and pipeline capacity. Additional capacity provided by the combination of two new processing trains at the Salam Gas Plant and completion of a project to increase compression on the Northern Gas Pipeline allowed previously discovered wells in our Khalda Concession Qasr field to come online. Australia’s 49 percent production increase was driven by production restorations following completion of repairs to the Varanus Island facility. Canada’s gas production increased 6 MMcf/d from drilling and recompletion activities and a lower effective royalty rate, partially offset by natural decline. Argentine production decreased 11 MMcf/d on natural decline and lower capital spending levels. U.S. daily production declined 14 MMcf/d. Production in the Gulf Coast decreased 8 MMcf/d as production shut-in for facility, rig and third-party downtime repairs reduced the 2009 production by 30 MMcf/d, which more than offset net production gains from drilling results. Our Central region’s production declined 6 MMcf/d primarily a result of the region’s curtailed drilling program, which was deferred until service costs fell in line with lower commodity prices. Most of the regions drilling activity occurred in the second half of the year.


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Operating Expenses
 
The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on relevance.
 
                                                 
    Year Ended December 31,     Year Ended December 31,  
    2010     2009     2008     2010     2009     2008  
          (In millions)                 (Per boe)        
 
Depreciation, depletion and amortization:
                                               
Oil and gas property and equipment
                                               
Recurring
  $ 2,861     $ 2,202     $ 2,358     $ 11.92     $ 10.34     $ 12.06  
Additional
          2,818       5,334             13.24       27.27  
Other assets
    222       193       158       .92       .91       .81  
Asset retirement obligation accretion
    111       105       101       .46       .49       .52  
Lease operating expenses
    2,032       1,662       1,910       8.47       7.81       9.76  
Gathering and transportation
    178       143       157       .73       .67       .80  
Taxes other than income
    690       580       985       2.88       2.72       5.03  
General and administrative expenses
    380       344       289       1.58       1.62       1.48  
Merger, acquisitions & transition
    183                   .77              
Financing costs, net
    229       242       166       .95       1.13       .85  
                                                 
Total
  $ 6,886     $ 8,289     $ 11,458     $ 28.68     $ 38.93     $ 58.58  
                                                 
 
Depreciation, Depletion and Amortization
 
The following table details the changes in recurring depreciation, depletion and amortization (DD&A) of oil and gas properties between 2010 and 2008:
 
         
    Recurring DD&A  
    (In millions)  
 
2008
  $ 2,358  
Volume change
    150  
Rate change
    (306 )
         
2009
  $ 2,202  
Volume change
    317  
Rate change
    342  
         
2010
  $ 2,861  
         
 
2010 vs. 2009  Recurring full-cost depletion expense increased $659 million on an absolute dollar basis: $342 million on higher rate and $317 million from additional production. Our full-cost depletion rate increased $1.58 to $11.92 per boe as costs to acquire, find and develop reserves exceeded our historical cost basis.
 
2009 vs. 2008  Recurring full-cost depletion expense decreased $156 million on an absolute dollar basis: $306 million on lower rate, partially offset by an increase of $150 million from higher production. Our full-cost depletion rate decreased $1.72 to $10.34 per boe. The decrease in rate was driven by a $5.33 billion non-cash write-down of the carrying value of our December 31, 2008, proved property balances in the U.S., U.K. North Sea, Canada and Argentina and a $2.82 billion non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas property balances in the U.S. and Canada. The impact of the write-downs was partially offset by 2009 drilling and finding costs, which exceeded our historical cost basis.


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Lease Operating Expenses
 
Lease operating expenses (LOE) include several components: direct operating costs, repair and maintenance, and workover costs.
 
Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity-price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as labor, boats, helicopters, materials and supplies. Oil, which contributed nearly half of our production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties and in areas with remote plants and facilities. All production in Australia and the North Sea and nearly 90 percent from the U.S. Gulf Coast region comes from offshore properties. Workovers accelerate production; hence, activity generally increases with higher commodity prices. Foreign exchange rate fluctuations generally impact the Company’s LOE, with a weakening U.S. dollar adding to per-unit costs and a strengthening U.S. dollar lowering per-unit costs in our international regions.
 
2010 vs. 2009 Our 2010 LOE increased $370 million from 2009, or 22 percent on an absolute dollar basis. On a per-unit basis, LOE increased eight percent with a 22 percent increase on higher costs, offset by a 14 percent decline related to increased production. The rate was impacted by the items below:
 
         
    Per boe  
 
2009 LOE
  $ 7.81  
Acquisitions, net of associated production
    .27  
Foreign exchange rate impact
    .22  
Equipment rental
    .22  
Workover costs
    .16  
Stock-based compensation
    .14  
Labor and pumper costs
    .08  
Material
    .07  
Power and fuel
    .07  
Incentive compensation
    .05  
Other
    .15  
Other increased production
    (.77 )
         
2010 LOE
  $ 8.47  
         
 
2009 vs. 2008 Our 2009 LOE decreased $248 million from 2008. LOE per boe was down 20 percent: 13 percent on lower cost and seven percent on higher production. The rate was impacted by the items below:
 
         
    Per boe  
 
2008 LOE
  $ 9.76  
Higher production
    (.68 )
Workover costs
    (.36 )
Foreign exchange rate impact
    (.33 )
Power and fuel
    (.32 )
Labor and pumper costs
    (.10 )
Hurricane repairs
    (.10 )
Other
    (.06 )
         
2009 LOE
  $ 7.81  
         


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Gathering and Transportation
 
We generally sell oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a lower relative price to reflect transportation costs to be incurred by the purchaser. In this case, we record sales at the netback price received from the purchaser. Alternatively, we sell oil or natural gas at a specific delivery point, pay our own transportation to a third-party carrier and receive a price with no transportation deduction. In this case we record the separate transportation cost as gathering and transportation costs.
 
In the U.S., Canada and Argentina, we sell oil and natural gas under both types of arrangements. In the North Sea, we pay transportation charges to a third-party carrier. In Australia, oil and natural gas are sold under netback arrangements. In Egypt, our oil and natural gas production is primarily sold to EGPC under netback arrangements; however, we also export crude oil under both types of arrangements.
 
The following table presents gathering and transportation costs we paid directly to third-party carriers for each of the periods presented:
 
                         
    For the Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
U.S. 
  $ 42     $ 36     $ 40  
Canada
    75       53       63  
North Sea
    25       26       28  
Egypt
    31       23       21  
Argentina
    5       5       5  
                         
Total Gathering and Transportation
  $ 178     $ 143     $ 157  
                         
 
2010 vs. 2009  Gathering and transportation costs increased $35 million from 2009. The increase in the U.S. resulted from an increase in both the volumes transported under arrangements where we pay costs directly to third parties and in rates. The increase in Canada resulted from an increase in volumes, rate and foreign exchange rates. North Sea costs were down on lower production and foreign exchange rates. Egypt costs increased as a result of higher shipping, handling and pipeline fees as compared to the prior year.
 
2009 vs. 2008  Gathering and transportation costs decreased $14 million from 2008. The decreases in the U.S. and Canada resulted from a decrease in both the volumes transported under arrangements where we pay costs directly to third parties and in rates. North Sea costs were down on foreign exchange rates. Egypt costs increased as a result of retroactive terminal fees claimed by EGPC, partially offset by a decrease in export cargoes as more crude oil was purchased by EGPC for domestic use in the latter part of 2009.
 
Taxes Other Than Income
 
Taxes other than income primarily comprises U.K. Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters off the coast of the U.S. and Australia and ad valorem taxes on properties in the U.S. and Canada. Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties field in the U.K. North Sea. We are subject to a variety of other taxes including U.S. franchise taxes, Australian Petroleum Resources Rent tax and various Canadian taxes including: Freehold


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Mineral tax, Saskatchewan Capital tax and Saskatchewan Resources surtax. We also pay taxes on invoices and bank transactions in Argentina. The table below presents a comparison of these expenses:
 
                         
    For the Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
U.K. PRT
  $ 422     $ 383     $ 695  
Severance taxes
    142       88       168  
Ad valorem taxes
    80       55       71  
Other taxes
    46       54       51  
                         
Total Taxes other than income
  $ 690     $ 580     $ 985  
                         
 
2010 vs. 2009  Taxes other than income were $110 million higher than 2009. U.K. PRT was $39 million more than 2009 on a 10 percent increase in net profits driven by higher oil revenues. Severance taxes increased $54 million from higher taxable revenues in the U.S., predominantly resulting from acquisitions, and consistent with higher realized oil and natural gas prices relative to the prior year. The $25 million increase in ad valorem taxes resulted from higher taxable valuations in the U.S. associated with increases in oil and natural gas prices relative to the prior year and the BP and Devon acquisitions and Mariner merger.
 
2009 vs. 2008  Taxes other than income were $405 million lower than 2008. U.K. PRT was $312 million less than 2008 on a 43 percent decrease in net profits, driven by lower oil revenues and lower operating and capital costs. The decrease in severance taxes resulted from lower taxable revenues in the U.S., consistent with the lower realized oil and natural gas prices relative to the prior year. The $16 million decrease in ad valorem taxes resulted from lower taxable valuations associated with decreases in oil and natural gas prices.
 
General and Administrative Expenses
 
2010 vs. 2009  General and administrative (G&A) expenses were $36 million higher in 2010 than in 2009. On a per boe basis, G&A expenses decreased two percent as the effect of higher volumes more than offset the increase in costs. G&A expense was impacted by the following:
 
         
2009 G&A
  $ 1.62  
Workforce reduction costs
    (.19 )
Stock-based compensation
    .15  
Other incentive compensation
    .06  
Kitimat LNG administrative costs
    .03  
Other corporate costs
    .11  
Increased production
    (.20 )
         
2010 G&A
  $ 1.58  
         
 
2009 vs. 2008  G&A expenses were $55 million higher in 2009 than in 2008. On a per boe basis, G&A expenses increased nine percent: 19 percent on higher costs, offset by a 10 percent reduction on higher volumes. G&A expense was impacted by the following:
 
         
2008 G&A
  $ 1.48  
Workforce reduction costs
    .20  
Stock-based compensation
    .17  
Other incentive compensation
    (.06 )
Other corporate costs
    (.03 )
Increased production
    (.14 )
         
2009 G&A
  $ 1.62  
         


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Merger, Acquisitions & Transition
 
In 2010, the Company recognized $183 million in merger, acquisitions & transition costs related to our BP and Devon acquisitions and the Mariner merger. A summary of these costs follows:
 
         
Separation and retention costs
  $ 114  
Investment banking fees
    42  
Other costs
    27  
         
2010 Merger, Acquisitions & Transition
  $ 183  
         
 
Merger, acquisitions & transition costs during 2008 and 2009 were not material.
 
Financing Costs, Net
 
Financing costs incurred during the periods noted are composed of the following:
 
                         
    For the Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Interest expense
  $ 345     $ 309     $ 280  
Amortization of deferred loan costs
    17       6       4  
Capitalized interest
    (120 )     (61 )     (94 )
Interest income
    (13 )     (12 )     (24 )
                         
Total Financing costs, net
  $ 229     $ 242     $ 166  
                         
 
2010 vs. 2009  Financing costs, net decreased $13 million from 2009. The decrease is primarily related to a $59 million increase in capitalized interest, the result of additional unproved balances from the BP acquisitions and Mariner merger. This decrease is partially offset by a $36 million increase in interest expense from three debt issuances in 2010 and $11 million higher amortization of deferred loan costs related to the new debt and repayment of the Australian project financing facility.
 
2009 vs. 2008  Financing costs, net increased $76 million from 2008. The increase in cost is primarily the result of a $29 million increase in interest expense related to higher average outstanding debt balances, a $33 million reduction in capitalized interest related to lower unproved property balances and completion of several long-term construction projects, and a $12 million decrease in interest income on a lower average cash balance and lower interest rates.
 
Provision for Income Taxes
 
2010 vs. 2009  The provision for income taxes totaled $2.2 billion in 2010 compared to $611 million in 2009. The effective rates for 2010 and 2009 were skewed by the effect of currency exchange rates on our foreign deferred tax liabilities and other net tax settlements. Total taxes and the effective rate for 2009 were also impacted by the magnitude of the taxes related to the full-cost write-down in that year. Excluding these items, the 2010 and 2009 effective tax rates were comparable at 40.75 percent and 39.75 percent, respectively.
 
2009 vs. 2008  The provision for income taxes totaled $611 million in 2009 compared to $220 million in 2008. Total taxes and the effective rates for each period were skewed by the magnitude of the taxes related to the 2009 and 2008 full-cost write-downs, the effect of currency exchange rates on our foreign deferred tax liabilities and other net tax settlements. Excluding these items, the 2009 and 2008 effective tax rates were comparable at 39.75 percent and 39.58 percent, respectively.
 
Non-GAAP Measures
 
The Company makes reference to some measures in discussion of its financial and operating highlights that are not required by or presented in accordance with GAAP. Management uses these measures in assessing operating


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results and believes the presentation of these measures provides information useful in assessing the Company’s financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to GAAP measures and may be calculated differently from, and therefore may not be comparable to, similarly-titled measures used at other companies.
 
Adjusted Earnings
 
To assess the Company’s operating trends and performance, management uses Adjusted Earnings, which is net income excluding certain items that management believes affect the comparability of operating results. Management believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings for items that may obscure underlying fundamentals and trends. The reconciling items below are the types of items management excludes and believes are frequently excluded by analysts when evaluating the operating trends and comparability of the Company’s results.
 
                 
    For the Year
 
    Ended December 31,  
    2010     2009  
    (In millions, except share data)  
 
Income (Loss) Attributable to Common Stock (GAAP)
  $ 3,000     $ (292 )
Adjustments:
               
Foreign currency fluctuation impact on deferred tax expense
    52       198  
Merger, acquisitions & transition, net of tax(1)
    120        
Additional depletion, net of tax(2)
          1,981  
                 
Adjusted Earnings (Non-GAAP)
  $ 3,172     $ 1,887  
                 
Adjusted Earnings Per Share (Non-GAAP)
               
Basic
  $ 9.02     $ 5.62  
                 
Diluted
  $ 8.94     $ 5.59  
                 
Average Number of Common Shares
               
Basic
    352       336  
                 
Diluted
    359       338  
                 
 
 
(1) Merger, acquisitions & transition costs recorded in 2010 totaled $183 million pre-tax, for which a tax benefit of $63 million was recognized. The tax effect was calculated utilizing the statutory rates in effect in each country where costs were incurred.
 
(2) Additional depletion (non-cash write-down of the carrying value of proved property) recorded in 2009 was $2.82 billion pre-tax, for which a deferred tax benefit of $837 million was recognized. The tax effect of the write-down of the carrying value of proved property (additional depletion) in 2009 was calculated utilizing the statutory rates in effect in each country where a write-down occurred.
 
Acquisitions and Divestitures
 
2010 Activity
 
In the fourth quarter of 2010 Apache acquired Mariner, an independent exploration and production company, in a stock and cash transaction totaling $2.7 billion. We also assumed approximately $1.7 billion of Mariner’s debt in connection with the merger. The transaction was accounted for as a business combination, with Mariner’s assets and liabilities reflected in Apache’s financial statements at fair value. Mariner’s oil and gas properties are primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin and onshore in the Gulf Coast. The Permian Basin and Gulf of Mexico shelf assets are complementary to Apache’s existing holdings and provide an inventory of future potential drilling locations, particularly in the Spraberry and Wolfcamp formation oil plays of the Permian Basin. Additionally, Mariner has accumulated acreage in emerging unconventional shale oil resources in the U.S.


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In the third and fourth quarters of 2010 Apache completed the acquisition of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of west Texas and New Mexico, substantially all of BP’s Western Canadian upstream natural gas assets and BP’s interests in four development licenses and one exploration concession (East Badr El Din) in the Western Desert of Egypt. The aggregate purchase price of the BP acquisitions, subsequent to exercise of preferential purchase rights, was $6.4 billion, subject to normal post-closing adjustments. The effective date of these acquisitions was July 1, 2010.
 
In the second quarter of 2010 Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon for $1.05 billion, subject to normal post-closing adjustments. The acquisition from Devon was effective January 1, 2010, and included 477,000 acres across 150 blocks.
 
During the first quarter of 2010 Apache Canada, through its subsidiaries, closed the acquisition of a 51-percent interest in the Kitimat LNG facility and a 25.5-percent interest in a partnership that owns a related proposed pipeline. EOG Resources Canada owns the remaining 49 percent of the Kitimat LNG facility and a 24.5-percent interest in the pipeline partnership. In February 2011 Apache Canada and EOG Canada entered into an agreement to purchase the remaining 50-percent interest in the partnership. Upon close of the transaction, Apache Canada and EOG Canada will own 51 percent and 49 percent, respectively, of the pipeline partnership and proposed pipeline.
 
For further information regarding these acquisitions, please see Note 2 — Acquisitions in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
2009 Activity
 
During the second quarter of 2009 Apache announced the acquisition of nine Permian Basin oil and gas fields with then-current net production of 3,500 boe/d from Marathon Oil Corporation for $187.4 million, subject to normal post-closing adjustments. Estimated reserves acquired in connection with the acquisition totaled 19.5 MMboe. These long-lived fields fit well with Apache’s existing properties in the Permian Basin, particularly in Lea County, New Mexico, and will provide the Company many years of drilling opportunities. The effective date of the transaction was January 1, 2009.
 
2008 Activity
 
There was no major acquisition activity during 2008; however, the Company completed several divestiture transactions. On January 29, 2008, the Company completed the sale of its interest in Ship Shoal blocks 349 and 359 on the outer continental shelf of the Gulf of Mexico to W&T Offshore, Inc. for $116 million. On January 31, 2008, the Company completed the sale of non-strategic oil and gas properties in the Permian Basin of West Texas to Vanguard Permian, LLC for $78 million. On April 2, 2008, the Company completed the sale of non-strategic Canadian properties to Central Global Resources for C$112 million.
 
Capital Resources and Liquidity
 
Operating cash flows is a primary source of liquidity. Apache’s cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts revenues, earnings and cash flows, capital spending and potentially our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactive as commodity prices in the short-term.
 
Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Our business, as with other extractive industries, is a depleting one in which each barrel produced must be replaced or the Company and its reserves, a critical source of future liquidity, will shrink. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities or our ability to acquire additional reserves at reasonable costs. For a discussion of risk factors related to our business and operations, please see Part I, Item 1A — Risk Factors.


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We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs. Apache’s ability to access the debt and equity capital markets is supported by its investment-grade credit ratings.
 
We believe the liquidity and capital resource alternatives available to Apache, combined with internally-generated cash flows, will be adequate to fund short-term and long-term operations, including our capital spending program, repayment of debt maturities and any amount that may ultimately be paid in connection with contingencies.
 
Apache’s primary uses of cash are exploration, development and acquisition of oil and gas properties, costs necessary to maintain ongoing operations, repayment of principal and interest on outstanding debt and payment of dividends. We fund our exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected cash flows.
 
See additional information, please see Part I, Items 1 and 2 — Business and Properties and Part I, Item 1A — Risk Factors of this Form 10-K.


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Sources and Uses of Cash
 
The following table presents the sources and uses of our cash and cash equivalents for the years presented:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Sources of Cash and Cash Equivalents:
                       
Net cash provided by operating activities
  $ 6,726     $ 4,224     $ 7,065  
Net commercial paper and bank loan borrowings
    318              
Sale of short-term investments
          792        
Sales of property and equipment
          2       308  
Project financing draw-downs
          250       100  
Fixed-rate debt borrowings
    2,470             796  
Proceeds from issuance of common stock
    2,258              
Proceeds from issuance of depositary shares
    1,227              
Common stock activity
    70       29       32  
Treasury stock activity
    9       6       4  
Other
    27       29       39  
                         
      13,105       5,332       8,344  
                         
Uses of Cash and Cash Equivalents:
                       
Capital expenditures(1)
    4,922       3,631       5,823  
Purchase of short-term investments
                792  
Acquisitions:
                       
Devon properties
    1,018              
BP properties
    6,429              
Mariner
    787              
Other
    126       310       150  
Net commercial paper and bank loan repayments
          2       200  
Project financing repayment
    350              
Payments on fixed-rate notes
    1,023       100        
Redemption of preferred stock
          98        
Dividends
    226       209       239  
Cost of debt and equity transactions
    17              
Other
    121       115       85  
                         
      15,019       4,465       7,289  
                         
Increase (decrease) in cash and cash equivalents
  $ (1,914 )   $ 867     $ 1,055  
                         
 
 
(1) The table presents capital expenditures on a cash basis; therefore, the amounts differ from those discussed elsewhere in this document, which include accruals.
 
Net Cash Provided by Operating Activities
 
Operating cash flows is our primary source of capital and liquidity and is impacted, both in the short-term and the long-term, by highly volatile oil and natural gas prices.
 
Apache’s average natural gas price realizations fluctuated throughout 2010, dipping from a high of $4.84 per Mcf in February to a low of $3.89 in September before increasing to $4.19 in December. Average realized natural gas prices for the year rose 12 percent over 2009 to $4.15 per Mcf. Our average crude oil realizations saw an


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increase throughout the year from a low of $70.68 per barrel in May 2010, peaking in December at $86.01 per barrel. Crude oil prices averaged $76.69 per barrel for 2010, up 28 percent from 2009.
 
In order to manage the variability in cash flows, we utilize commodity hedges. At the end of 2010, we had hedged an average of just over 375,000 MMBtu per day of our 2011 North American natural gas production. The volumes were primarily hedged using fixed-price swaps at an average price of approximately $6.25 per MMBtu. For perspective, the natural gas hedges represent 24 percent of fourth-quarter 2010 North America daily gas production and 16 percent worldwide.
 
For liquids, we had an average of just under 98,000 b/d of oil production hedged for 2011. Crude oil production was primarily hedged using collars that had average floor and ceiling prices of approximately $69 and $97 per barrel, respectively. In addition, 20,000 b/d of our North Sea Forties field production will be sold under a physical delivery contract subject to a minimum price of $70 a barrel and a ceiling price of $99 a barrel. For perspective, the combined 2011 financial derivatives represent approximately 35 percent of fourth-quarter 2010 worldwide daily oil production.
 
For additional information regarding our derivative contracts, please see Note 3 — Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. For quantitative and qualitative information regarding our use of derivatives to manage commodity price risk, please see Commodity Risk in Part II, Item 7A of this Form 10-K.
 
The factors affecting operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation (ARO) accretion and deferred income tax expense, which affect earnings but do not affect cash flows.
 
For 2010, operating cash flows totaled $6.7 billion, up $2.5 billion from 2009. The primary driver of the increase was a $3.6 billion increase in oil and gas revenues on both higher production and prices, especially oil. This was partially offset by higher cash-based expenses, including merger and transition expenses associated with our acquisitions in 2010, and higher income tax payments in 2010.
 
For a detailed discussion of commodity prices, production, costs and expenses, please see “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses which do not impact net cash provided by operating activities, please see the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
Commercial Paper and Bank Loans
 
The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. As of December 31, 2010, the Company had $913 million in commercial paper outstanding. For further discussion of our commercial paper program, please see “Liquidity” below and Note 5 — Debt in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
Upon consummation of our merger with Mariner, we assumed credit lines with outstanding borrowings of approximately $632 million. Commercial paper was issued to repay this amount, and credit lines assumed from Mariner were terminated prior to year-end 2010.
 
Short-term Investments
 
We occasionally invest in highly-liquid, short-term investments until funds are needed to further supplement our operating cash flows. At December 31, 2008, we had $792 million invested in U.S. Treasury securities with original maturities greater than three months but less than one year. These securities matured on April 2, 2009. None were held at December 31, 2010 or 2009.
 
Project Financing
 
One of the Company’s Australian subsidiaries had a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The outstanding balance under the facility was


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$350 million at December 31, 2009. We paid off $50 million of the facility in June 2010 and the remaining balance in December 2010. For a more detailed discussion of this facility and information regarding our available committed borrowing capacity, please see “Liquidity” below.
 
Fixed-Rate Debt
 
On August 20, 2010, the Company issued $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds were used to repay borrowings under a bridge facility and the Company’s commercial paper program that were used to finance the BP acquisitions.
 
On December 3, 2010, the Company issued $500 million principal amount of senior unsecured 3.625-percent notes maturing February 1, 2021, and $500 million principal amount of senior unsecured 5.25-percent notes maturing February 1, 2042. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds were used to redeem the outstanding public debt of $1.0 billion assumed upon completion of Apache’s acquisition of Mariner on November 10, 2010.
 
Proceeds from Issuance of Common Stock
 
On July 28, 2010, in conjunction with Apache’s $6.4 billion acquisition of properties from BP, the Company issued 26.45 million shares of common stock at a public offering price of $88 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering totaled approximately $2.3 billion.
 
Proceeds from Issuance of Mandatory Convertible Preferred Stock
 
On July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). The Company received proceeds of approximately $1.2 billion, after underwriting discounts and before expenses, from the sale.
 
Capital Expenditures
 
We fund exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected operating cash flows. Our operating cash flows, both in the short and long term, are impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, operating cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to these adjusted operating cash flow forecasts and market trends in drilling and acquisitions costs.
 
Historically, we have used a combination of operating cash flows, borrowings under lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund significant acquisitions.


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The following table details capital expenditures for each country in which we do business.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Exploration and Development:
                       
United States
  $ 1,623     $ 929     $ 2,183  
Canada
    860       412       705  
                         
North America
    2,483       1,341       2,888  
Egypt
    757       676       853  
Australia
    624       602       880  
North Sea
    617       375       459  
Argentina
    240       140       318  
Chile
    20       11       27  
                         
International
    2,258       1,804       2,537  
                         
Worldwide Exploration and Development Costs
    4,741       3,145       5,425  
Gathering, Transmission and Processing Facilities (GTP):
                       
Canada
    159       83       29  
Egypt
    182       151       571  
Australia
    162       69       54  
Argentina
    3       2       5  
                         
Total GTP Costs
    506       305       659  
Asset Retirement Costs
    459       288       514  
Capitalized Interest
    120       61       94  
                         
Capital Expenditures, excluding Acquisitions
    5,826       3,799       6,692  
Acquisitions, including GTP
    11,557       310       150  
Asset Retirement Costs — Acquired
    847       5        
                         
Total Capital Expenditures
  $ 18,230     $ 4,114     $ 6,842  
                         
 
Exploration and Development  As a result of Apache’s determination to not outspend our operating cash flows, we curtailed 2009 capital expenditures in response to the decline in commodity prices and financial uncertainty in the global economy at the outset of 2009. Our 2010 drilling and development budgets were increased in response to recovering commodity prices and projected increases in operating cash flows. As a result, worldwide E&D expenditures for 2010 were 51 percent higher than 2009.
 
E&D spending in North America, which was up 85 percent from the prior year, totaled 52 percent of worldwide E&D spending, up from 43 percent in 2009. U.S. E&D expenditures were $694 million or 75 percent higher than year-ago levels on expanded drilling activities in the Permian region and horizontal drilling in the Granite Wash play in the Central region. Activity related to newly acquired properties in the Permian and Gulf Coast regions also contributed to increased E&D expenditures late in the year. E&D spending in Canada more than doubled, increasing to $860 million as the Company actively developed and increased its acreage positions in several plays including the Horn River basin.
 
E&D expenditures outside of North America increased 25 percent over 2009 to nearly $2.3 billion. E&D spending in the North Sea was up $242 million over 2009 levels on construction of the Bacchus subsea tie-back project and on the Forties Alpha satellite platform and ongoing upgrades to existing platforms. Argentina expenditures were up on additional drilling and development activity. Egypt was $81 million higher than the prior year on continued drilling activity in the Matruh and Faghur basins, where we have announced numerous recent discoveries. E&D expenditures in Australia and Chile were up marginally, increasing over prior-year levels by $22 million and $9 million, respectively.


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Acquisitions  We completed over $11 billion of acquisitions in 2010 compared to $310 million in 2009. We also assumed $847 million in asset retirement costs. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year. For information regarding our acquisitions, please see Significant Acquisitions and Divestitures above and Note 2 — Acquisitions in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
Asset Retirement Costs  In 2010 we recorded $459 million of additional future asset retirement costs associated with our worldwide drilling programs and upward revisions to prior-year estimates for timing and costs.
 
Gathering, Transmission and Processing Facilities (GTP)  We invested $506 million in GTP in 2010 compared to $305 million in 2009. GTP expenditures in Australia consisted of construction activity at the Devil Creek Gas Plant and the FEED study for the Wheatstone LNG project. Activity in Canada was centered in the Horn River basin, with expenditures for compressor stations, a water treatment facility, gathering systems and a gas processing plant. Expenditures in Egypt included the initial phases of the Kalabsha oil processing facility. In addition, approximately $517 million of the value of our 2010 acquisitions is associated with GTP.
 
Dividends
 
The Company has paid cash dividends on its common stock for 46 consecutive years through 2010. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common stock dividends paid during 2010 totaled $206 million, compared with $201 million in 2009 and $234 million in 2008. The 2008 period included a special non-recurring cash dividend of 10 cents per common share paid on March 18, 2008. The Company also made dividend payments of $20 million on the Company’s Series D Preferred Stock in 2010.
 
Liquidity
 
                 
    At December 31,  
(In millions, except percentages)   2010     2009  
 
Cash and cash equivalents
  $ 134     $ 2,048  
Total debt
    8,141       5,067  
Shareholders’ equity
    24,377       15,779  
Available committed borrowing capacity
    2,387       2,300  
Floating-rate debt/total debt
    12 %     7 %
Percent of total debt to capitalization
    25 %     24 %
 
Our liquidity and financial position have not been materially affected by recent uncertainty in the credit markets. We believe that losses from non-performance are unlikely to occur; however, we are not able to predict sudden changes in the creditworthiness of the financial institutions with which we do business. Twenty-seven of 28 banks with lending commitments to the Company have credit ratings of at least single-A, which in some cases is based on government support. There is no assurance that the financial condition of these banks will not deteriorate or that the government guarantee will be maintained. We closely monitor the ratings of the 28 banks in our bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.
 
Cash and Cash Equivalents
 
We had $134 million in cash and cash equivalents at December 31, 2010. At December 31, 2010, $120 million of cash was held by foreign subsidiaries and approximately $14 million was held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities, with maturities of three months or less at the time of purchase. We intend to use cash from our international subsidiaries to fund international projects.


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Debt
 
At December 31, 2010, outstanding debt, which consisted of notes, debentures, commercial paper and uncommitted bank lines, totaled $8.1 billion. Current debt consists of $46 million borrowed under uncommitted money market/overdraft lines of credit in the U.S. and Argentina. We have $46 million of debt maturing in 2011, $400 million maturing in 2012, $1.8 billion maturing in 2013, $350 million maturing in 2015, and the remaining $5.6 billion maturing intermittently in years 2016 through 2096.
 
Debt-to-Capitalization Ratio
 
The Company’s debt-to-capitalization ratio as of December 31, 2010 was 25 percent.
 
Available Credit Facilities
 
As of December 31, 2010, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2011 and $2.3 billion matures in May 2013. The facilities consist of a $1.0 billion 364-day facility, a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. The $1.5 billion and the $450 million credit facilities also allow the company to borrow under competitive auctions. The U.S. credit facilities are used to support Apache’s commercial paper program.
 
The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, or approximately $2.2 billion as of December 31, 2010. There are no restrictions on incurring liens in countries other than U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group.
 
There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2010.
 
At the Company’s option, the interest rate for the facilities, excluding the 364-day facility, is based on a base rate, as defined, or LIBOR plus a margin determined by the Company’s senior long-term debt rating. In the case of the 364-day facility, the margin over LIBOR varies based upon prices reported in the credit default swap market with respect to Apache’s one-year indebtedness and the rating for Apache’s senior, unsecured long-term debt.
 
In 2010, one of the Company’s Australian subsidiaries repaid $350 million under its amortizing secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. Upon repayment of the facility, all commitments under the facility were terminated and assets secured by the facility were released.
 
At December 31, 2010, the margin over LIBOR for committed loans was .19 percent on the $1.5 billion facility and .23 percent on the $450 million facility in the U.S., the $200 million facility in Australia and the $150 million facility in Canada. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional .05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .06 percent on the total amount of the $1.5 billion facility and


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.07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.
 
Commercial Paper Program
 
In August 2010 the Company increased its commercial paper program by $1 billion from $1.95 billion to $2.95 billion. The commercial paper program generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Our 2010 weighted-average interest rate for commercial paper was .37 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100-percent backstop. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2011 and 2013. As of December 31, 2010, the Company had $913 million in commercial paper outstanding.
 
Contractual Obligations
 
We are subject to various financial obligations and commitments in the normal course of operations. These contractual obligations represent known future cash payments that we are required to make and relate primarily to long-term debt, operating leases, pipeline transportation commitments and international commitments. The Company expects to fund these contractual obligations with cash generated from operating activities.
 
The following table summarizes the Company’s contractual obligations as of December 31, 2010. For additional information regarding these obligations, please see Note 5 — Debt and Note 8 — Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
                                             
    Note
                          2017 &
 
Contractual Obligations   Reference   Total     2011     2012-2014     2015-2016     Beyond  
    (In millions)  
 
Debt, at face value
  Note 5   $ 8,190     $ 46     $ 2,213     $ 766     $ 5,165  
Interest payments
  Note 5     7,774       417       1,107       659       5,591  
Drilling rig commitments
  Note 8     392       303       89              
Purchase obligations
  Note 8     833       574       259              
E&D commitments
  Note 8     575       235       308       32        
Firm transportation agreements
  Note 8     809       137       423       170       79  
Office and related equipment
  Note 8     166       34       70       25       37  
Oil and gas operations equipment
  Note 8     476       85       146       55       190  
Other
  Note 8     5       5                    
                                             
Total Contractual Obligations(a)(b)(c)(d)
      $ 19,220     $ 1,836     $ 4,615     $ 1,707     $ 11,062  
                                             
 
 
(a) This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $2.9 billion. For additional information regarding asset retirement obligation, please see Note 4 — Asset Retirement Obligation in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
(b) This table does not include the Company’s $12 million net liability for outstanding derivative instruments valued as of December 31, 2010. For additional information regarding derivative instruments, please see Note 3 — Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
(c) This table does not include the Company’s pension or postretirement benefit obligations. For additional information regarding pension and postretirement benefit obligations, please see Note 8 — Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
(d) This table does not include the Company’s tax reserves. For additional information regarding tax reserves, please see Note 6 — Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.


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Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations, including approximately $135 million for environmental remediation and approximately $14 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 8 — Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
The Company also had approximately $106 million accrued as of December 31, 2010, for an insurance contingency as a member of Oil Insurance Limited (OIL). This insurance co-op insures specific property, pollution liability and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay a withdrawal premium if we elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential withdrawal premium is calculated annually based on past losses and the nature of our asset base. The liability reflecting this potential charge has been fully accrued.
 
Off-Balance Sheet Arrangements
 
Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions.
 
Insurance Program
 
We maintain insurance coverage that includes coverage for physical damage to our oil and gas properties, third party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
 
In general, our current insurance policies covering physical damage to our oil and gas assets provide $250 million per occurrence with an additional $250 million per year. Coverage for damage to our U.S. Gulf of Mexico assets specifically resulting from a named windstorm, however, is subject to a maximum of $250 million per named windstorm, includes a self-insured retention of 40 percent of the losses above a $100 million deductible, and is limited to no more than two storms per year. In addition, our policies covering physical damage to our North Sea oil and gas assets provide $250 million per occurrence with an additional $750 million per year.
 
Our various insurance policies also provide coverage for, among other things, liability related to negative environmental impacts of a sudden pollution event in the amount of $750 million per occurrence, charterer’s legal liability, in the amount of $1 billion per occurrence, aircraft liability in the amount of $750 million per occurrence, and general liability, employer’s liability and auto liability in the amount of $500 million per occurrence. Our service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.
 
Our insurance policies generally renew in January and June of each year. In light of the recent catastrophic accident in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.
 
Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and highly rated international insurers covering its investments in Egypt. In the aggregate, these policies, subject to the policy terms and conditions, provide approximately $1 billion of coverage to Apache covering losses arising from confiscation, nationalization, and expropriation risks and currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of


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exportable petroleum when actions taken by the Government of Egypt prevent Apache from exporting our share of production.
 
Critical Accounting Policies and Estimates
 
Apache prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Apache identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Apache’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of Apache’s most critical accounting policies:
 
Reserves Estimates
 
Effective December 31, 2009, Apache adopted revised oil and gas disclosure requirements set forth by the U.S. Securities and Exchange Commission (SEC) in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries — Oil and Gas.” The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures.
 
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGL’s that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
 
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
 
Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.
 
Reserves as of December 31, 2010 and 2009 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of the production, except where prices are defined by contractual arrangements. Reserves as of December 31, 2008 were estimated using prices in effect at the end of that year, in accordance with SEC guidance in effect prior to the issuance of the Modernization Rules.
 
Apache has elected not to disclose probable and possible reserves or reserve estimates in this filing.
 
Asset Retirement Obligation (ARO)
 
The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal


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technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
 
ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
 
Income Taxes
 
Our oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).
 
The Company regularly assesses and, if required, establishes accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. Tax reserves have been established and include any related interest, despite the belief by the Company that certain tax positions meet certain legislative, judicial and regulatory requirements. These reserves are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law and any new legislation. The Company believes that the reserves established are adequate in relation to the potential for any additional tax assessments.
 
Purchase Price Allocation
 
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill.
 
The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
 
In estimating the fair values of assets acquired and liabilities assumed we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves as described above in “Reserve Estimates.” Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.


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ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
 
Commodity Risk
 
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile due to unpredictable events such as economic growth or retraction, weather and climate. Our average monthly crude oil realizations saw a gradual increase from a low of $70.68 per barrel in May 2010, peaking in December at $86.10. In 2010 crude oil prices averaged $76.69 per barrel up 28 percent from 2009. Our average monthly natural gas price realizations fluctuated throughout 2010, dipping from a high of $4.84 per Mcf in February to a low of $3.89 in September before increasing to $4.19 in December. Average realized prices in 2010 for natural gas increased 12 percent to $4.15 per Mcf.
 
For 2010 approximately 23 percent of our natural gas production was subject to financial derivative hedges. As of year-end 2010 we had just over 375,000 MMBtu per day of our projected 2011 North American natural gas production hedged. For perspective, these hedges cover 24 percent of fourth-quarter 2010 North American daily production, or 16 percent of worldwide production.
 
Approximately 12 percent of our 2010 crude oil production was subject to financial derivative hedges. We entered 2011 having hedged approximately 98,000 b/d of oil production. In addi