10-K 1 apc12311310k.htm 10-K APC 12.31.13 10K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
76-0146568
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(Address of principal executive offices)
Registrant’s telephone number, including area code (832) 636-1000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
  
Name of each exchange on which registered
Common Stock, par value $0.10 per share
  
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
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  ý    No  ¨
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  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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.
Large accelerated filer  ý    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  ý
The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 28, 2013, was $43.1 billion based on the closing price as reported on the New York Stock Exchange.
The number of shares outstanding of the Company’s common stock at January 31, 2014, is shown below:
Title of Class
  
Number of Shares Outstanding
Common Stock, par value $0.10 per share
  
503,767,298
Documents Incorporated By Reference
Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 13, 2014 (to be filed with the Securities and Exchange Commission prior to April 3, 2014), are incorporated by reference into Part III of this Form 10-K.



TABLE OF CONTENTS
 
 
Page
PART I
 
 
Items 1 and 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 3.
Item 4.
PART II
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
 
 
Item 15.



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 Risk Factors under Item 1A of this Form 10-K.

GENERAL

Anadarko Petroleum Corporation is among the world’s largest independent exploration and production companies, with approximately 2.8 billion barrels of oil equivalent (BOE) of proved reserves at December 31, 2013. Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko’s asset portfolio is aimed at delivering long-term value to stakeholders by combining a large inventory of development opportunities in the U.S. onshore with high-potential worldwide offshore exploration and development activities.
Anadarko’s asset portfolio includes U.S. onshore resource plays in the Rocky Mountains area, the southern United States, the Appalachian basin, and Alaska. The Company is also among the largest independent producers in the deepwater Gulf of Mexico, and has production and exploration activities worldwide, including activities in Algeria, Mozambique, Ghana, China, Brazil, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, New Zealand, Colombia, South Africa, and other countries.
Anadarko is committed to producing energy in a manner that protects the environment and public health. Anadarko’s focus is to deliver resources to the world while upholding the Company’s core values of integrity and trust, servant leadership, people and passion, commercial focus, and open communication in all business activities.
Anadarko’s business segments are managed separately due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are as follows:

Oil and gas exploration and production—This segment explores for and produces natural gas, crude oil, condensate, and natural gas liquids (NGLs), and plans for the development and operation of the Company’s liquefied natural gas (LNG) project.

Midstream—This segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The Company owns and operates gathering, processing, treating, and transportation systems in the United States for natural gas, crude oil, and NGLs.

Marketing—This segment sells much of Anadarko’s production, as well as third-party purchased volumes. The Company actively markets oil, natural gas, and NGLs in the United States; oil from Algeria, China, and Ghana; and anticipated LNG production from Mozambique.

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046, and its telephone number is (832) 636-1000.


2


Available Information  The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements, and other reports and filings with the Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its website located at www.anadarko.com/Investor/Pages/SECFilings.aspx. The Company will also make available to any stockholder, without charge, printed copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this report, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations, P.O. Box 1330, Houston, Texas 77251-1330 or call (855) 820-6605, send an email to investor@anadarko.com, or submit a request using the Request Corporate Materials option under the Investor Relations tab on the Company’s website at www.anadarko.com.
The public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Anadarko, that file electronically with the SEC.

OIL AND GAS PROPERTIES AND ACTIVITIES

The map below illustrates the locations of Anadarko’s oil and natural-gas exploration and production operations.

3


United States

Overview  Anadarko’s U.S. operations include oil and natural-gas exploration and production onshore in the Lower 48 states, the deepwater Gulf of Mexico, and onshore Alaska. The Company’s U.S. operations accounted for 89% of total sales volumes during 2013 and 90% of total proved reserves at year-end 2013.

Rocky Mountains Region  Anadarko’s Rocky Mountains Region (Rockies) properties include oil and natural-gas plays located in Colorado, Utah, and Wyoming. The Company focused its 2013 capital investments in areas that offer high liquids yields (liquids-rich areas), which resulted in significant growth in oil production. Anadarko operates approximately 13,200 wells and owns an interest in approximately 9,500 nonoperated wells in the Rockies. Anadarko operates fractured-carbonate/shale reservoirs, tight-gas assets, coalbed-methane (CBM) natural-gas assets, and enhanced oil recovery (EOR) projects within the region. The Company also has fee ownership of mineral rights under approximately eight million acres that pass through Colorado, Wyoming, and into Utah (known as the Land Grant). Management considers the Land Grant a significant competitive advantage for Anadarko as it enhances the Company’s economic returns from production on Land Grant acreage, offers drilling opportunities for the Company without expiration, and allows the Company to capture incremental royalty revenue from third-party activity on Land Grant acreage.
The Company believes its liquids-rich reservoirs, strong well performance, low development and operating costs, large expandable midstream infrastructure, and the competitive advantages provided by mineral ownership in the Land Grant each provide tangible benefits to the Company. Activities in the Rockies primarily focus on expanding existing fields to increase production and adding proved reserves through horizontal drilling, infill drilling, and down-spacing operations.
In 2013, total-year Rockies sales volumes increased 3% over 2012, with a 15%, or 14 thousand barrels of oil equivalent per day (MBOE/d), increase in liquids volumes. The Company drilled 707 wells and completed 658 wells in the Rockies during 2013. The Company plans to increase the number of horizontal wells drilled from 350 in 2013 to approximately 400 in 2014, with continued focus on liquids-rich areas.

4


Wattenberg  The Wattenberg field is a liquids-rich area where Anadarko operates over 5,240 wells. The field contains the Niobrara and Codell naturally fractured formations that hold liquids and natural gas. During 2013, the Company’s drilling program focused entirely on horizontal development, drilling 335 horizontal wells. Sales volumes in the Wattenberg field increased 21% compared to 2012, with a year-over-year 36% increase in oil volumes and 32% increase in total liquids volumes. Horizontal drilling results in the Wattenberg field have shown strong initial production rates with average liquids yields of approximately 67%. The Company has identified approximately 4,000 potential drilling locations in the Niobrara and Codell formations that are expected to provide substantial opportunity for Anadarko’s continued activity. In 2014, the Company plans to employ 13 horizontal rigs in the Wattenberg field and expects wells drilled to increase as a result of the increased number of rigs operating in the area and from improved drilling efficiencies and cycle times.
In October 2013, Anadarko exchanged certain oil and gas properties in the Wattenberg field with a third party. Under the terms of the transaction, each party exchanged approximately 50,000 net acres. This exchange consolidated Anadarko’s working interest and operated acreage positions in this core development area, while retaining the royalty benefit of the Company’s Land Grant mineral ownership on approximately 21,000 acres of the lands conveyed to the third party. The trade increased Anadarko’s production by 8,000 barrels of oil equivalent per day (BOE/d) since October 2013. Consolidating Anadarko’s operating position is expected to provide significant value through more efficient development planning and infrastructure utilization. The Company also expects to improve operating efficiencies, reduce costs, and reduce impacts to local communities as a result of this exchange.
In September 2013, the Company shut in approximately 675 operated vertical wells in the Greater Wattenberg area in preparation for and during the flooding in Colorado. Due to damaged roads, bridges, railways, and other issues impacting the ability to move heavy equipment such as rigs and compression units, the Company experienced disruptions to its drilling, completion, and construction activities in the area. These disruptions have been resolved and the Company does not expect production volumes to be significantly affected in 2014.

Greater Natural Buttes  The Greater Natural Buttes area in eastern Utah is one of the Company’s major tight-gas assets. The Company utilizes both refrigeration and cryogenic processing facilities in this area to extract NGLs from the natural-gas stream.
The Company operates approximately 2,800 wells in the Greater Natural Buttes area, drilled 223 wells in 2013, and increased year-over-year sales volumes from the area by 2%. Anadarko identified more than 1,800 potential locations in the Wasatch/Mesaverde formations. Many of these locations are infill drilling opportunities focused on down-spacing from 40-acre well density to 10-acre well density.

Powder River Deep  The Company drilled 14 horizontal wells in the Powder River basin during 2013 as part of a multi-objective horizontal exploration program targeting liquids-rich plays. Anadarko controls over 350,000 acres of deep rights within the Powder River basin.

Coalbed Methane Properties  Anadarko operates approximately 2,200 CBM wells and owns an interest in approximately 4,200 nonoperated CBM wells in the Rockies, primarily located in the Powder River basin in Wyoming and the Helper and Clawson fields in Utah. Anadarko controls over 640,000 acres of shallow rights within the Powder River basin. CBM is natural gas that is generated and stored within coal seams. To produce CBM, water is extracted from the coal seam, resulting in reduced pressure and the release of natural gas, which flows to the wellhead. The Company expects to remain at a reduced CBM activity level in 2014 as a result of low natural-gas prices.


5


Salt Creek and Monell  During 2013, the Company continued the development of its Rockies EOR assets at the Salt Creek and Monell fields in Wyoming. The Company’s EOR operations use carbon dioxide (CO2) to stimulate oil production from mature reservoirs after primary and water-flood recovery methods have been completed. Significant gains in production were achieved in this area due to the Company’s ongoing development programs, with oil production rising 13% in 2013. In 2014, the Company plans to continue the development of these fields with additional facility expansion projects and a continued limited drilling program to enhance CO2 flooding operations.
In 2012, the Company entered into a carried-interest arrangement where a third party agreed to fund $400 million of development costs in exchange for a 23% interest in the Company’s EOR development at the Salt Creek field in Wyoming. At December 31, 2013, $375 million of the $400 million obligation had been funded.

Greater Green River Basin  Anadarko operates over 1,400 wells in the Wamsutter and Moxa fields and carries a nonoperated position in 3,400 wells between the two fields. Much of this producing area is in the Land Grant, which improves the economics of projects in the area.
In 2013, Anadarko acquired additional wells, increased interest in existing wells, and increased acreage in the Company’s core areas of this basin through the completion of a $310 million acquisition in the Moxa field. This acquisition resulted in a production increase of approximately 6,500 BOE/d, with significant additional value expected to be provided through decreased operating costs, maintenance performed to increase base production, and further infill drilling potential.
In January 2014, Anadarko sold its interest in the Pinedale/Jonah assets in Wyoming for $581 million.


6


Southern and Appalachia Region  Anadarko’s Southern and Appalachia Region properties are primarily located in Texas, Pennsylvania, Louisiana, and Kansas. Anadarko holds an interest in approximately 4.2 million gross acres throughout the Southern and Appalachia Region. The region includes the Eagleford shale in South Texas, the Marcellus shale in north-central Pennsylvania, the Delaware basin in West Texas, and the Haynesville shale in East Texas and Louisiana. Operations in these areas are focused on finding and developing both natural gas and liquids from shales, tight sands, and fractured-reservoir plays.
During 2013, the Company continued to focus on liquids-rich opportunities across the region by expanding drilling activity in the emerging Wolfcamp and other shale plays, while continuing its existing liquids-rich projects in the Eagleford, Delaware basin, and East Texas/North Louisiana plays. The Company has reduced costs and benefited from improved cycle-time efficiencies in both drilling and completion operations across all operating areas in the region.
In 2013, total-year sales volumes in the Southern and Appalachia Region increased 30% over 2012, with a 29% increase in liquids volumes. The Company drilled 593 operated horizontal wells and brought 533 wells online in 2013. The Company expects to drill approximately 665 horizontal wells in the Southern and Appalachia Region in 2014.
Eagleford  The Eagleford shale performance continued to benefit from a carried-interest arrangement entered into in 2011 that conveyed 33.3% of the Company’s Eagleford shale assets and the underlying Pearsall shale rights to a third party in exchange for the funding of $1.6 billion of Anadarko’s development costs. The third party funded $444 million of the Company’s development costs in 2013, which completed its funding commitment.
Anadarko currently holds 388,000 gross acres in this area. During 2013, the Company operated an average of nine rigs and spud 359 horizontal wells. The Company increased sales volumes by 46% year over year. During 2013, Anadarko also expanded its infield gathering-system capacity from 350 million cubic feet per day (MMcf/d) to approximately 600 MMcf/d with the completion of a new gas compression facility. In addition, three oil stabilization trains were added with an oil capacity of 75 thousand barrels per day (MBbls/d). Gas processing capacity was also expanded in 2013 by completion of the Company’s new high-efficiency cryogenic gas plant that came online in June. This 200-MMcf/d Brasada natural-gas processing plant is capable of recovering approximately 30 MBbls/d of NGLs.

Delaware Basin  Anadarko holds an interest in over 602,000 gross acres in the Delaware basin. Anadarko’s 2013 drilling activity primarily targeted the liquids-rich Bone Spring formation, the Avalon shale, and the developing Wolfcamp shale play. In 2013, Anadarko spud 74 operated wells and participated in 36 nonoperated wells. Significant infrastructure was added, which increased NGLs sales volumes by 47% over 2012. The Company had two operated rigs drilling in the Bone Spring formation, three operated rigs drilling in the Avalon shale, and six operated rigs drilling in the Wolfcamp shale at year-end 2013.

7


East Texas/North Louisiana  Anadarko increased its capital program in the East Texas Carthage area in 2013, targeting a liquids-rich area in the Haynesville shale. In 2013, Anadarko operated seven rigs and drilled 76 wells in the Haynesville and Cotton Valley formations. The Company increased sales volumes from the area by 40% year over year.

Marcellus  In the Marcellus shale of the Appalachian basin, where the Company holds 773,000 gross acres, 61 operated horizontal wells were spud using a fleet average of three rigs during the year. Anadarko also participated in drilling an additional 51 nonoperated horizontal wells in 2013. The Company’s production volumes in Marcellus continued to improve with sales volumes increasing 58% over 2012.

Gulf of Mexico  In the Gulf of Mexico, Anadarko owns an average 63% working interest in 444 blocks. The Company operates six active floating platforms, holds interests in 29 producing fields, and is in the process of delineating and developing two additional fields. During 2013, the Company continued an active deepwater exploration and appraisal program in the Gulf of Mexico as it continues to take advantage of its existing infrastructure to accelerate development activities at reduced costs.
 
The following includes the significant development, exploration, and appraisal activity during 2013.

Development  Anadarko continues to advance the Lucius project toward first oil in the second half of 2014. Fabrication was completed in 2013 on the production spar that will support the development. The spar was successfully towed, installed, and secured over Keathley Canyon Block 875. The subsea infrastructure is currently being installed with the 80-MBbls/d topside facilities on schedule for delivery in the first quarter of 2014. The Company has successfully finished the Phase 1 development drilling campaign and is now focusing its efforts on completion operations. In 2012, Anadarko entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of capital costs in exchange for a 7.2% working interest in the Lucius development. The carry obligation is expected to cover the substantial majority of the Company’s expected future capital costs through first production. At December 31, 2013, $416 million of the $556 million obligation had been funded and the remaining portion is expected to be funded during 2014. Following the transaction, the Company held a 27.8% working interest in the Lucius development.

8


Anadarko is also advancing the Heidelberg development with construction of the 80-MBbls/d spar progressing on schedule. The project was sanctioned during the second quarter of 2013. During the year, the Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of capital costs in exchange for a 12.75% working interest in the development. The carry obligation is expected to cover the substantial majority of the Company’s expected future capital costs through first production. At December 31, 2013, $119 million of the $860 million obligation had been funded. Following the transaction, Anadarko held a 31.5% working interest in Heidelberg. Development drilling is on schedule to begin in the first quarter of 2014 with first production anticipated in 2016.
At Marco Polo (100% working interest) in the K2 Complex, two wells were successfully sidetracked and completed during 2013. The A3 well came online at a sustainable net rate of 2,400 BOE/d and the A5 well came online at a sustainable net rate of 3,500 BOE/d. At Constitution (100% working interest), the Company executed a successful platform drilling program in 2013, where the A6 well was sidetracked, completed, and brought online. The next drilling programs for both of these oil-producing fields are expected to commence in the first quarter of 2014. At Ticonderoga (50% working interest), Anadarko drilled, completed, and brought online the GC 768-4 well, which is a tieback to the Constitution spar.
The Company successfully drilled and completed a fourth development well at Caesar/Tonga, which began producing in the first quarter of 2014. The Company purchased an additional 11.25% interest in Power Play during the year, bringing its total working interest to 56.25%. Anadarko also completed the transfer of its ownership in the Neptune spar to a third party at the end of 2013.

Exploration  Three new discoveries were drilled in the Gulf of Mexico in 2013, including two in Walker Ridge and one in the Sigsbee Escarpment area.
In the Shenandoah basin in Walker Ridge, discoveries were successfully drilled at Coronado (35% working interest) and at Yucatan (15% working interest). The Coronado-1 discovery well encountered more than 400 net feet of oil pay in high-quality Lower Tertiary reservoirs. The Company increased its ownership position in the Coronado discovery from 15% to 35% and will assume operatorship following the drilling of a second appraisal well, which was spud in the fourth quarter of 2013. The Yucatan-1 discovery well, drilled approximately three miles south and syncline-separated from the Shenandoah-2 appraisal well, encountered more than 120 net feet of high-quality oil pay in Lower Tertiary-aged reservoirs.
The Phobos exploration well (30% working interest) was the first well drilled in the Sigsbee Escarpment area, approximately 11 miles south of the Company-operated Lucius field. The well spud in December 2012 and was determined to be successful in the second quarter of 2013. The well encountered approximately 250 net feet of high-quality oil pay in Lower Tertiary-aged reservoirs, trapped in a large, multi-block, four-way closure.

Appraisal  Anadarko participated in drilling successful appraisal wells associated with three Gulf of Mexico discoveries: Shenandoah, Coronado, and Vito. The Company-operated Shenandoah-2 well (30% working interest) reached total depth in January 2013, encountering more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary reservoirs. Similar to the initial Shenandoah discovery, well log and pressure data from the Shenandoah-2 well indicated excellent-quality reservoir and fluid properties. The targeted pay sands were full of oil with no oil-water contact.
During the second quarter of 2013, the Company participated in the appraisal sidetrack at Coronado, which defined the down-dip extent of the accumulation discovered earlier in the year. At year end, the second appraisal well was drilling in Walker Ridge Block 143.
Another successful appraisal well was drilled at the Vito discovery (18.67% working interest) in Mississippi Canyon Block 984 and further defined the extent of the field.

Alaska  Anadarko’s oil production and development activity in Alaska is concentrated primarily on the North Slope. Infrastructure construction began during 2013 in preparation of the upcoming Alpine West development, a 15-to-20-well extension of the Alpine field, which is estimated to commence production in late 2015 or early 2016.

9


International

Overview  Anadarko’s international oil and natural-gas production and development operations are located in Mozambique, Algeria, Ghana, and China. The Company also has exploration acreage in Ghana, Mozambique, Brazil, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, China, New Zealand, Colombia, South Africa, and other countries. International locations accounted for 11% of Anadarko’s total sales volumes and 26% of sales revenues during 2013, and 10% of total proved reserves at year-end 2013. In 2014, the Company expects to drill 14 to 18 development wells and 15 to 18 exploration/appraisal wells in various international locations.

Mozambique  Anadarko operates two blocks (one onshore and one offshore) totaling approximately 5.7 million gross acres.

Development  During 2013, the Company made progress advancing the Rovuma Offshore Area 1 gas development project towards sanction. The Environmental Impact Assessment was completed including all necessary public consultations and the final report has been prepared for submittal. Site preparation and early infrastructure improvements at the Afungi Peninsula location have been initiated. The Company has completed front-end engineering and design (FEED) for the offshore gathering infrastructure and bid invitations have been issued. The FEED for the onshore liquefaction facilities is nearing completion and remains on schedule. The first LNG train is targeted to achieve first delivery in 2018.
In February 2014, the Company sold a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion. Anadarko remains the operator of Rovuma Offshore Area 1 with a working interest of 26.5%.
Anadarko and its partners continue to make progress marketing LNG to be produced from Rovuma Offshore Area 1 in Mozambique. The partners have reached non-binding Heads of Agreements for long-term LNG sales to buyers in Asian markets covering approximately two-thirds of the first 5-million-tonne-per-annum train.

10


Exploration  In 2013, the Company made additional discoveries in Mozambique at Espadarte and Orca. The Espadarte exploration well targeted an exploration play in the Miocene and the up-dip extent of the Oligocene-aged reservoirs found at the Golfinho-Atum field. The well encountered approximately 50 net feet of natural-gas pay in the Miocene reservoirs and 230 net feet of natural-gas pay in the Oligocene reservoirs. Pressure data indicate the Oligocene sands are in communication with the Golfinho-Atum reservoirs discovered in 2012, confirming the well as a northwest extension of the field. The Orca exploration well reached total depth during the first quarter of 2013 and encountered approximately 190 net feet of natural-gas pay in a single Paleocene reservoir. The Manta-1 exploration well, which had an exploration target in the Miocene and an appraisal target in the Oligocene-aged reservoirs from the Golfinho field, also tested the northernmost extent of the Orca discovery. The Manta-1 well encountered approximately 360 net feet of natural-gas pay in the Oligocene, and 115 net feet of pay in the Paleocene. A two-well appraisal program for the Orca discovery is planned for 2014. The Atum-3 appraisal well encountered approximately 230 net feet of natural-gas pay and established the gas-water contact for the Golfinho-Atum field. In addition, two successful Golfinho appraisal wells were drilled in 2013.

Algeria  Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404 and 208, which are governed by a Production Sharing Agreement between Anadarko, two other parties, and Sonatrach, the national oil and gas company of Algeria. The Company is responsible for 24.5% of the development and production costs for these blocks. The Company produces oil through the Hassi Berkine South and Ourhoud central processing facilities in Block 404 and oil, condensate, and NGLs through the El Merk central processing facility in Block 208. Gross oil production through these facilities averaged more than 300 MBbls/d throughout 2013. Initial production from El Merk in Block 208 was achieved in the first quarter of 2013, and production from the facility increased throughout the year as two 65-MBbls/d oil trains and a natural-gas processing and NGLs extraction train were completed and brought online. Final commissioning of the NGLs extraction train is ongoing and will be completed in the first quarter of 2014. The Company drilled 10 development wells in 2013 and expects to drill 10 to 12 additional development wells in 2014.

Ghana  Anadarko’s production and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.
During 2013, the Company and its partners completed four additional wells in the Jubilee field (24% nonoperated unit interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block. The Company and its partners are expanding the natural-gas handling capacity on the floating production, storage, and offloading vessel (FPSO) to allow for increased oil production, and exited the year with a gross oil production rate of 100 MBbls/d in the Jubilee field. The Company and its partners also commenced a study to evaluate options to further expand the oil throughput capacity of the FPSO.
The Akasa 2A appraisal well was drilled in the West Cape Three Points Block (31% nonoperated working interest) and development options are being evaluated to maximize the value from the Mahogany, Teak, and Akasa discoveries.
In May 2013, the Government of Ghana approved the Plan of Development for the Tweneboa/Enyenra/Ntomme (TEN) complex (19% nonoperated working interest) and the project was sanctioned by the Company and its partners. Major facility construction contracts have been awarded for the development, which will utilize an 80-MBbls/d FPSO for production from subsea wells. The Company expects first production in 2016. The Company participated in three exploration and appraisal wells in the Deepwater Tano block in 2013.


11


China  Anadarko’s production and development activities in China are located offshore in Bohai Bay. During 2013, the Company and its partners drilled and brought online 12 new wells. A development plan for the next major field expansion is being created and final governmental approval and project sanction is expected to be completed in 2014. Consistent with the terms of the petroleum contract, the Company transferred operatorship of the Bohai Bay development to CNOOC China Limited effective January 1, 2013. The Company maintains an average working interest of approximately 35%.
The Liwan 21-1-1 exploration well (50% working interest) in the South China Sea spud in August 2012 and was suspended after setting surface casing due to rig commitments and weather considerations. Drilling resumed on the well during the fourth quarter of 2013. The well encountered high-quality sands, but was determined to be non-commercial. The Company’s capital spending on the well was fully carried by a third party.
In February 2014, the Company entered into an agreement to sell its oil and gas properties in China for $1.075 billion. The transaction is expected to close later in 2014 and is subject to preferential rights, regulatory approvals, and other customary closing conditions.

Brazil  Anadarko holds exploration interests in approximately 350,000 gross acres in three offshore blocks located in the Campos basin. In early 2013, a drillstem test was completed at the Itaipu-1 (33% working interest) discovery well in BM-C-32. The well flowed at rates up to 5,600 Bbls/d. A successful appraisal of the Itaipu discovery was also drilled during the year. The Company-operated Wahoo-5 (30% working interest) appraisal well in BM-C-30 was drilled in the eastern flank of the Wahoo structure and encountered more than 200 net feet of high-quality pay in a pre-salt reservoir, with a total hydrocarbon column now established at 460 feet. Unitization discussions continue at Itaipu.

Liberia  The Company operates Block 10 (80% working interest) and Block 15 (48% working interest) in the offshore Liberian basin totaling approximately 1.3 million exploration acres. Multiple Cretaceous stratigraphic prospects, similar to the Jubilee Mahogany fan, have been identified on these blocks. Block 10 exploration drilling is planned for 2014.

Sierra Leone  Anadarko owns and operates a 55% working interest in offshore Block SL-07B-11, which encompasses approximately 1.3 million gross acres. Multiple Upper Cretaceous fan-type prospects have been identified in the lightly explored Liberian basin. Data from the previously drilled exploration wells is being evaluated to determine future drilling plans.

Kenya  Anadarko owns and operates a 45% working interest in five offshore deepwater blocks, encompassing approximately 5.6 million gross acres. The Company drilled two exploration wells in 2013. The Kubwa well in Block L-7 encountered non-commercial oil shows in reservoir-quality sands. The Kiboko well in Block L-11 encountered well-developed reservoir sands with low permeability and also encountered indications of a working petroleum system. The results are being integrated into the geologic model with plans for additional exploration drilling in 2014.

Côte d’Ivoire  Anadarko owns working interests in five offshore blocks totaling approximately 1.4 million acres, including Blocks CI-515 and CI-516 with a 45% operated working interest and Block CI-103 with a 55% nonoperated working interest. Two additional blocks, CI-528 and CI-529 (90% working interest, operated), were acquired during 2013. The Calao exploration well was drilled on Block CI-103 in early 2013 and encountered non-commercial volumes of hydrocarbons. A combination exploration and down-dip appraisal of the 2012 Paon discovery in Block CI-103 was drilled in the fourth quarter of 2013. No hydrocarbons were encountered in the exploration targets, but pressure data obtained in the Paon appraisal well indicates a potential oil-water contact in the reservoir found by the Paon discovery well. The potential for a commercial accumulation at Paon will be further tested in 2014 by the Paon 3A appraisal well.


12


New Zealand  Anadarko operates approximately 10 million gross exploration acres in four offshore blocks, with a 48% working interest in the Taranaki basin block, a 45% working interest in the Canterbury basin block, and a 100% working interest in two Pegasus basin blocks. In 2011, a 3D seismic survey of approximately 700 square miles was completed on the Taranaki block and a 2D seismic survey of approximately 2,400 miles was acquired over the Canterbury block. The Romney-1 exploration well on the Taranaki block reached its total depth objective during the first quarter of 2014, and the reservoir was water-bearing. An exploration well is expected to be drilled in the Canterbury basin in 2014.

Colombia  Anadarko owns and operates exploration acreage in six offshore blocks, totaling approximately 7.8 million acres. The Company owns a 100% working interest in the COL 2 Block and a 50% working interest in the remaining blocks. Existing 2D and 3D seismic data has been reprocessed and combined with a newly acquired 2,100-square mile 3D survey, which was completed in 2013. The seismic data is being interpreted to develop a multi-well drilling program planned to begin in late 2014 or early 2015.

South Africa  The Company operates offshore Block 5/6/7 (80% working interest), which covers over 23 million acres. In 2013, a 3,800-mile 2D seismic program and a high resolution sea floor survey were completed. This data is being interpreted and mapped to better understand the basin geology and plan a 3D seismic program.

Other  Anadarko also has exploration projects in other overseas, new-venture areas including Guyana, Morocco, and Tunisia.

13


Proved Reserves

Estimates of proved reserves volumes owned at year end, net of third-party royalty interests, are presented in billion cubic feet (Bcf), at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (MMBbls) for oil, condensate, and NGLs. Total volumes are presented in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural-gas reserves volumes.
Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria, Ghana, and China, which by country and in total represents less than 15% of the Company’s total proved reserves.

Summary of Proved Reserves
 
Natural Gas
(Bcf)
 
Oil and
Condensate
(MMBbls)
 
NGLs
(MMBbls)
 
Total
(MMBOE)
December 31, 2013
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
7,120

 
347

 
268

 
1,801

International

 
202

 

 
202

Undeveloped
 
 
 
 
 
 
 
United States
2,085

 
245

 
127

 
720

International

 
57

 
12

 
69

Total proved
9,205

 
851

 
407

 
2,792

 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
6,445

 
318

 
283

 
1,675

International

 
208

 

 
208

Undeveloped
 
 
 
 
 
 
 
United States
1,884

 
193

 
110

 
617

International

 
48

 
12

 
60

Total proved
8,329

 
767

 
405

 
2,560

 
 
 
 
 
 
 
 
December 31, 2011
 
 
 
 
 
 
 
Proved
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
United States
6,113

 
352

 
267

 
1,638

International

 
173

 

 
173

Undeveloped
 
 
 
 
 
 
 
United States
2,252

 
184

 
94

 
653

International

 
62

 
13

 
75

Total proved
8,365

 
771

 
374

 
2,539



14


The Company’s year-end 2013 proved reserves product mix was comparable to the last two years with 55% natural gas, 30% oil and condensate, and 15% NGLs.
The Company’s estimates of proved developed reserves, proved undeveloped reserves (PUDs), and total proved reserves at December 31, 2013, 2012, and 2011, and changes in proved reserves during the last three years are presented in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K.
The Company has not yet filed information with a federal authority or agency with respect to its estimated total proved reserves at December 31, 2013. Annually, Anadarko reports gross proved reserves for U.S.-operated properties to the U.S. Department of Energy. These reported reserves are derived from the same database used to estimate and report proved reserves in this Form 10-K.
Also presented in the Supplemental Information are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. See Operating Results and Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.

Changes in PUDs  Changes to PUDs occurring during 2013 are summarized in the table below. Revisions of prior estimates include updates to prior PUDs, the addition of new PUDs associated with current development plans, the transfer of PUDs to unproved categories due to development plan changes, and the impact of changes in economic conditions, including changes in commodity prices. PUD revisions reflect Anadarko’s ongoing evaluation of its asset portfolio and current-year changes to development plans. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years unless specific circumstances warrant a longer development time horizon.
MMBOE
 
PUDs at January 1, 2013
677

Revisions of prior estimates
197

Extensions, discoveries, and other additions
109

Conversion to developed
(183
)
Sales
(11
)
PUDs at December 31, 2013
789


Revisions In 2013, PUD reserves revisions of 197 MMBOE were primarily related to successful infill drilling in large onshore areas such as Wattenberg and Greater Natural Buttes in the Rockies and the Eagleford shale in the Southern and Appalachia Region, partially offset by decreases due to development plan updates and lower ethane prices in the Rockies. 

Additions During 2013, Anadarko added 109 MMBOE of PUD reserves through extensions, discoveries, and other additions, primarily as a result of successful drilling at Heidelberg and Caesar/Tonga in the Gulf of Mexico and in the Marcellus shale in the Southern and Appalachia Region.

Conversions  In 2013, the Company converted 183 MMBOE, or 27% of total year-end 2012 PUDs, to developed status. Approximately 85% of PUD conversions occurred in U.S. onshore assets, 11% in international assets, and the remaining 4% in Gulf of Mexico assets.
The majority of the U.S. onshore PUD conversions occurred as a result of development activities, which included 107 MMBOE in the Rockies and 48 MMBOE in the Southern and Appalachia Region. International PUD conversions of 20 MMBOE were primarily associated with ongoing development activities in the Company’s African assets. The remaining PUD conversions were associated with development projects in various Gulf of Mexico fields and Alaska.

15


Anadarko spent $1.0 billion to develop PUDs in 2013, of which approximately 70% related to domestic development programs in the Rockies and the Southern and Appalachia Regions, 25% related to development of international projects, and the remaining 5% related to Alaska and Gulf of Mexico development projects.
In 2012, the Company converted 171 MMBOE, or 23% of the total year-end 2011 PUDs, to developed status. Approximately 79% of PUD conversions occurred in U.S. onshore assets, 15% in international assets, and the remaining 6% in Gulf of Mexico assets. Anadarko spent $1.0 billion on PUD development in 2012, of which approximately 69% related to domestic development programs in the Rockies and the Southern and Appalachia Regions, 28% related to development of international projects, and the remaining 3% related to Alaska and Gulf of Mexico development projects.

Development Plans  The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Typically, U.S. onshore PUDs are converted to developed reserves within five years of the initial proved reserves booking, but projects such as EOR, arctic development, deepwater development, and international programs may take longer. All of the Company’s U.S. onshore PUDs at December 31, 2013, were scheduled to be developed within five years, with the exception of the Salt Creek EOR project, the annual development of which is limited by CO2 supply.
At December 31, 2013, the Company had 89 MMBOE of pre-2009 PUDs that remained undeveloped. Approximately 31% of these PUDs are associated with the El Merk development project and are being developed according to an Algerian government-approved plan. Construction of the El Merk central processing facility has been completed and 97 of the 119 wells in the approved Reservoir Development Plan have been drilled. Anadarko and its partners achieved initial oil production in 2013 as two oil trains and a natural-gas processing and NGLs extraction train were completed and brought online during the year. Final commissioning of the NGLs extraction train is ongoing and will be completed in the first quarter of 2014.
Another 24% of the Company’s pre-2009 PUDs are associated with the Salt Creek EOR single-development project located in the Rockies. Since 2003, Anadarko has invested an average of $79 million per year to develop various phases of the Salt Creek EOR project and will continue significant spending levels in the future to complete the development.
All remaining pre-2009 PUDs are associated with various Gulf of Mexico opportunities where longer development times are a result of various delays associated with operating in a deepwater environment, including the impacts of the deepwater drilling moratorium.

Technologies Used in Proved Reserves Estimation  The Company’s 2013 proved reserves additions were based on estimates generated through the integration of relevant geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

Internal Controls over Reserves Estimation  Anadarko’s estimates of proved reserves and associated future net cash flows were made solely by the Company’s engineers and are the responsibility of management. The Company requires that reserves estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers’ standards. The QREs are assigned to specific assets within the Company’s regions. The QREs interact with engineering, land, and geoscience personnel to obtain the necessary data for projecting future production, net cash flows, and ultimate recoverable reserves. Management within each region approves the QREs’ reserves estimates. All QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group (CRG).

16


The CRG ensures confidence in the Company’s reserves estimates by maintaining internal policies for estimating and recording reserves in compliance with applicable SEC definitions and guidance. Compliance with the SEC reserves guidelines is the primary responsibility of Anadarko’s CRG.
The CRG is managed through the Company’s finance department, which is separate from its operating regions, and is responsible for overseeing internal reserves reviews and approving the Company’s reserves estimates. The Director-Reserves Administration and the Corporate Reserves Manager manage the CRG and report to the VP-Corporate Planning. The VP-Corporate Planning reports to the Company’s Executive Vice President, Finance and Chief Financial Officer, who in turn reports to the Chairman, President, and Chief Executive Officer. The Governance and Risk Committee of the Company’s Board of Directors meets with management, members of the CRG, and the Company’s independent petroleum consultants, Miller and Lents, Ltd. (M&L), to discuss the results of procedures and methods reviews as discussed below, as well as other matters and policies related to reserves.
The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserves estimates, has over 27 years of experience in the oil and gas industry, including over 13 years as either a reserves estimator or manager. His further professional qualifications include a degree in petroleum engineering, extensive internal and external reserves training, and asset evaluation and management. The principal engineer is a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers, where he has been a member for over 27 years. In addition, he is an active participant in industry reserves seminars and professional industry groups.

Third-Party Procedures and Methods Reviews  M&L reviewed the procedures and methods used by Anadarko’s staff in preparing its internal estimates of proved reserves and future net cash flows at December 31, 2013. The purpose of the review was to determine if the procedures and methods used by Anadarko to estimate its proved reserves are effective and in accordance with the definitions contained in SEC regulations. The procedures and methods reviews by M&L was a limited review of Anadarko’s procedures and methods and does not constitute a complete review, audit, independent estimate, or confirmation of the reasonableness of Anadarko’s estimates of proved reserves and future net cash flows.
The reviews covered 18 fields that included major assets in the United States and Africa, and encompassed approximately 88% of the Company’s estimates of proved reserves and associated future net cash flows at December 31, 2013. In each review, Anadarko’s technical staff presented M&L with an overview of the data, methods, and assumptions used in estimating its reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures, and relevant economic criteria.
Management’s intent in retaining M&L to review its procedures and methods is to provide objective third-party input on the Company’s procedures and methods and to gather industry information applicable to reserves estimation and reporting processes.

17


Sales Volumes, Prices, and Production Costs

The Company’s sales volumes were 285 MMBOE for 2013, 268 MMBOE for 2012, and 248 MMBOE for 2011. Production costs are costs to operate and maintain the Company’s wells and related equipment and include the cost of labor, well service and repair, location maintenance, power and fuel, transportation, other taxes, and production-related general and administrative costs. Additional information on volumes, prices, and production costs is contained in Financial Results under Item 7 of this Form 10-K. Additional detail regarding production costs is contained in the Supplemental Information under Item 8 of this Form 10-K. Information on major customers is contained in Note 21—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The following provides the Company’s annual sales volumes, average sales prices, and average production costs per BOE for each of the last three years:
 
Sales Volumes
 
Average Sales Prices (1)
 
Average
Production
Costs (2)
(Per BOE)
 
Natural
Gas
(Bcf)
 
Oil and
Condensate
(MMBbls)
 
NGLs
(MMBbls)
 
Barrels of
Oil
Equivalent
(MMBOE)
 
Natural
Gas
(Per Mcf)
 
Oil and
Condensate
(Per Bbl)
 
NGLs
(Per Bbl)
 
2013

 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
168

 
1

 
4

 
33

 
$
3.12

 
$
87.46

 
$
41.79

 
$
9.59

Wattenberg
102

 
16

 
6

 
40

 
3.75

 
94.27

 
41.75

 
8.55

Other United States
698

 
41

 
23

 
179

 
3.56

 
98.38

 
36.14

 
8.72

Total United States
968

 
58

 
33

 
252

 
3.50

 
97.02

 
37.97

 
8.81

International

 
33

 

 
33

 

 
109.15

 

 
9.96

Total
968

 
91

 
33

 
285

 
3.50

 
101.41

 
37.97

 
8.94

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
163

 
1

 
5

 
33

 
$
2.26

 
$
81.34

 
$
40.43

 
$
8.75

Wattenberg
95

 
12

 
5

 
33

 
3.00

 
92.16

 
40.72

 
8.05

Other United States
655

 
42

 
20

 
171

 
2.73

 
99.36

 
40.37

 
8.76

Total United States
913

 
55

 
30

 
237

 
2.68

 
97.46

 
40.44

 
8.66

International

 
31

 

 
31

 

 
111.11

 

 
10.89

Total
913

 
86

 
30

 
268

 
2.68

 
102.35

 
40.44

 
8.92

2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Natural Buttes
135

 
1

 
4

 
27

 
$
3.58

 
$
84.13

 
$
51.50

 
$
9.48

Wattenberg
79

 
9

 
5

 
27

 
4.17

 
91.91

 
53.85

 
7.58

Other United States
638

 
38

 
18

 
163

 
3.90

 
99.28

 
54.55

 
9.80

Total United States
852

 
48

 
27

 
217

 
3.87

 
97.70

 
53.95

 
9.50

International

 
31

 

 
31

 

 
109.20

 

 
9.98

Total
852

 
79

 
27

 
248

 
3.87

 
102.24

 
53.95

 
9.55

 _______________________________________________________________________________
Bcf—billion cubic feet
Mcf—thousand cubic feet
Bbl—barrel
(1) 
Excludes the impact of commodity derivatives.
(2) 
Excludes ad valorem and severance taxes.

18


Delivery Commitments

The Company sells crude oil and natural gas under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities. At December 31, 2013, Anadarko was contractually committed to deliver approximately 950 Bcf of natural gas to various customers in the United States through 2031. These contracts have various expiration dates with approximately 42% of the Company’s current commitment to be delivered in 2014, and 68% by 2018. At December 31, 2013, Anadarko also was contractually committed to deliver approximately 9 MMBbls of crude oil to ports in Algeria and Ghana through 2014. The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.

Properties and Leases

The following shows the developed lease, undeveloped lease, and fee mineral acres in which Anadarko held interests at December 31, 2013:
 
Developed
Lease
 
Undeveloped
Lease
 
Fee Mineral
 
Total
thousands of acres
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore
4,804

 
3,151

 
5,269

 
2,498

 
10,318

 
8,452

 
20,391

 
14,101

Offshore
288

 
143

 
2,292

 
1,533

 

 

 
2,580

 
1,676

Total United States
5,092

 
3,294

 
7,561

 
4,031

 
10,318

 
8,452

 
22,971

 
15,777

International
546

 
130

 
66,104

 
43,856

 

 

 
66,650

 
43,986

Total
5,638

 
3,424

 
73,665

 
47,887

 
10,318

 
8,452

 
89,621

 
59,763


At December 31, 2013, the Company had approximately 7 million net undeveloped lease acres scheduled to expire by December 31, 2014, if the Company does not establish production or take any other action to extend the terms. The Company plans to continue the terms of many of these licenses and concession areas through operational or administrative actions and does not expect a significant portion of the Company’s net acreage position to expire before such actions occur.

Drilling Program

The Company’s 2013 drilling program focused on proven and emerging oil and natural-gas basins in the United States (onshore and deepwater Gulf of Mexico) and various international locations. Exploration activity in 2013 consisted of 175 gross completed wells, which included 162 U.S. onshore wells, 5 Gulf of Mexico wells, and 8 international wells. Development activity in 2013 consisted of 1,366 gross completed wells, which included 1,347 U.S. onshore wells, 1 Gulf of Mexico well, and 18 international wells.

19


Drilling Statistics
The following shows the number of oil and gas wells that completed drilling in each of the last three years:
 
Net Exploratory
 
Net Development
 
Total

Productive
 
Dry Holes
 
Total
 
Productive
 
Dry Holes
 
Total
 
2013
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
62.9

 
1.4

 
64.3

 
879.3

 
3.3

 
882.6

 
946.9

International
0.2

 
3.5

 
3.7

 
5.4

 

 
5.4

 
9.1

Total
63.1

 
4.9

 
68.0

 
884.7

 
3.3

 
888.0

 
956.0

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
79.5

 
1.0

 
80.5

 
923.7

 
11.3

 
935.0

 
1,015.5

International
0.5

 
3.0

 
3.5

 
2.1

 

 
2.1

 
5.6

Total
80.0

 
4.0

 
84.0

 
925.8

 
11.3

 
937.1

 
1,021.1

2011
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
79.0

 
2.2

 
81.2

 
1,169.6

 
6.3

 
1,175.9

 
1,257.1

International
0.5

 
1.2

 
1.7

 
6.8

 
0.2

 
7.0

 
8.7

Total
79.5

 
3.4

 
82.9

 
1,176.4

 
6.5

 
1,182.9

 
1,265.8


The following shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion at December 31, 2013:
 
Wells in the process
of drilling or
in active completion
 
Wells suspended or
waiting on completion (1)
 
Exploration
 
Development
 
Exploration
 
Development
United States
 
 
 
 
 
 
 
Gross
12

 
221

 
86

 
746

Net
5.7

 
165.0

 
39.1

 
426.9

International
 
 
 
 
 
 
 
Gross
2

 

 
47

 
6

Net
0.9

 

 
17.9

 
1.7

Total
 
 
 
 
 
 
 
Gross
14

 
221

 
133

 
752

Net
6.6

 
165.0

 
57.0

 
428.6

 _______________________________________________________________________________
(1) 
Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

20


Productive Wells

At December 31, 2013, the Company’s ownership interest in productive wells was as follows:
 
Oil Wells (1)
 
Gas Wells (1)
United States
 
 
 
Gross
3,796

 
29,415

Net
2,608.2

 
19,082.0

International
 
 
 
Gross
355

 
8

Net
90.6

 
2.0

Total
 
 
 
Gross
4,151

 
29,423

Net
2,698.8

 
19,084.0

________________________________________________________________
(1) 
Includes wells containing multiple completions as follows:
Gross
229

 
2,865

Net
196.7

 
2,406.0


MIDSTREAM PROPERTIES AND ACTIVITIES

Anadarko invests in midstream (gathering, processing, treating, and transportation) assets to complement its operations in regions where the Company has oil and natural-gas production. Through ownership and operation of these facilities, the Company improves its ability to manage costs, controls the timing of bringing on new production, and enhances the value received for gathering, processing, treating, and transporting the Company’s production. Anadarko’s midstream business also provides services to third-party customers, including major and independent producers. Anadarko generates revenues from its midstream activities through a variety of contract structures, including fixed-fee, percent-of-proceeds, and keep-whole agreements. Anadarko’s midstream activities include Western Gas Partners, LP (WES), which is a publicly traded limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES’s general partner is owned by Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of Anadarko’s partnership interests in WES. At December 31, 2013, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire non-economic general partner interest. At December 31, 2013, WGP’s ownership interest in WES consisted of a 41.2% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. At December 31, 2013, Anadarko also owned a 0.4% limited partner interest in WES through another subsidiary.
At the end of 2013, Anadarko had 34 gathering systems and 31 processing and treating plants located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Pennsylvania, and Texas. In 2013, the Company’s midstream activity was concentrated in liquids-rich growth areas such as Wattenberg, Greater Natural Buttes, the Delaware basin, the Eagleford shale, and East Texas/North Louisiana plays, as well as in the Marcellus shale dry-gas play. In 2014, the Company plans to continue midstream investments in these core areas.

Wattenberg  The Company is constructing the 300-MMcf/d Lancaster cryogenic processing plant, with expected completion in early 2014. The plant will support the increasing production from horizontal drilling in the Niobrara development, helping to relieve processing constraints in the basin. The Company installed 180 MMcf/d of interim refrigeration processing capacity during 2013 to allow the Company’s production to continue to grow in advance of the Lancaster Train I completion. In 2013, the Company sanctioned a second 300-MMcf/d cryogenic processing plant that will sit adjacent to Lancaster Train I. Engineering is underway and long-lead items have been ordered for Lancaster Train II, which is expected to be completed in the second quarter of 2015. Three separate compressor stations in other areas are scheduled to be in service in the first half of 2014, which will add an additional 184 MMcf/d of compression capacity.

21


Anadarko and joint-venture partners are currently constructing a 435-mile NGLs pipeline (Front Range Pipeline) with initial capacity of 150 MBbls/d and the ability to expand to 230 MBbls/d. The pipeline will transport NGLs from Weld County, Colorado to Skellytown, Texas, where it will connect with other pipelines, including the Texas Express Pipeline (TEP). The Front Range Pipeline is expected to be in service in the first quarter of 2014. During the third quarter of 2013, Anadarko and its partners placed the TEP in service. The TEP originates in Skellytown, Texas and extends approximately 580 miles to NGLs fractionation and storage facilities in Mont Belvieu, Texas. The capacity of the TEP is 280 MBbls/d and can be expanded to approximately 400 MBbls/d. The Front Range Pipeline and the TEP are expected to enhance the value of the Company’s production by providing additional NGLs takeaway capacity and access to the Gulf Coast NGLs market. The Company acquired a 25% interest in an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. The two fractionation trains were placed in service late 2013.

Greater Natural Buttes  A new inter-connect between a third-party pipeline and the Chipeta processing complex was completed during 2013, adding an additional 100 MMcf/d of natural-gas supply to the plant. Repairs and warranty work were performed on the two cryogenic trains at Chipeta during the year and the combined 550-MMcf/d cryogenic trains are now processing above capacity at a combined 600 MMcf/d. Construction also commenced to install an additional 100 MMcf/d of compression capacity at the Natural Buttes compressor station, which is expected to be completed in the first half of 2014.

Wyoming  During the third quarter of 2013, the Company completed the purchase of a 242-mile pipeline between the Company’s Granger and Patrick Draw plants in Wyoming. Also, an expansion project to build a 26-mile, 16-inch pipeline from the Horsetrap production area to the Patrick Draw plant was completed, adding 35 MMcf/d of natural-gas compression capacity.

Delaware Basin  In the Delaware basin of West Texas, the Company expanded its midstream infrastructure for Bone Spring, Wolfcamp, and Avalon production. Projects were completed to increase oil and water capacity from 42 MBbls/d to a total of 47 MBbls/d through expansions at three central production facilities. In January 2013, the second phase of the Bone Spring processing plant, which is owned and operated by a third party, was commissioned and brought online with the start-up of a 100-MMcf/d cryogenic plant. Additionally, two new 20-MMcf/d central gathering facilities (CGF) were brought online in the Avalon area, bringing total CGF capacity in the area to 80 MMcf/d.

Eagleford  In the Eagleford shale, the Anadarko-operated gathering systems were expanded to approximately 600 MMcf/d for natural gas and 75 MBbls/d for oil. Major projects completed in 2013 include the Maverick central delivery point/oil handling facility expansion, which includes 75 MBbls/d of oil stabilization capacity, the Cat Ranch Mega CGF (compressor station), the Stumberg Mega CGF (compressor station), and the expansion of the Cochina gathering system. The Brasada natural-gas processing plant was placed into service in the second quarter of 2013, adding 200 MMcf/d of natural-gas processing capacity and 15 MBbls/d of condensate stabilization capacity. The Company has agreements with a third party which provide for the transportation and sale of up to 35 MBbls/d of raw mix delivered from Cotulla, Texas. The Company has the right to expand this reserved capacity up to 70 MBbls/d.

East Texas/North Louisiana  In East Texas, the Company continued to expand its midstream infrastructure for Cotton Valley Taylor and Haynesville production. The high-pressure Haynesville gathering system and related water and condensate infrastructure was expanded in the Carthage area to handle the continued growth associated with the liquids-rich Haynesville natural-gas production. Additionally, Anadarko has secured access to 490 MMcf/d of firm processing capacity for the Company’s current and future development in East Texas.


22


Marcellus  In the Marcellus shale in Pennsylvania, Anadarko’s natural-gas gathering capacity increased from 1,500 MMcf/d in 2012 to over 1,650 MMcf/d in 2013. In 2013, the Company connected 71 Anadarko-operated wells, constructed 41 miles of new pipeline, and introduced third-party natural gas to the gathering system. The Bull Run Compressor Facility (2,700 horsepower) was commissioned in January 2013, with an additional 2,700-horsepower expansion completed in December 2013. The additional compression start-ups will enhance the long-term deliverability in the Bull Run development area. During 2013, the Company acquired a third party’s 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems.

The following provides information regarding the Company’s midstream assets by geographic regions:
Area
 
Asset Type
 
Miles of
Gathering
Pipelines
 
Total
Horsepower
 
2013
Average
Throughput
(MMcf/d)
Rocky Mountains
 
Gathering, processing, and treating
 
11,300

 
1,166,400

 
3,800

Mid-Continent and other
 
Gathering
 
3,800

 
221,500

 
1,000

Texas
 
Gathering and treating
 
2,900

 
337,800

 
1,000

Total
 
 
 
18,000

 
1,725,700

 
5,800


MARKETING ACTIVITIES

The Company’s marketing segment actively manages Anadarko’s natural-gas, crude-oil, condensate, and NGLs sales, as well as the Company’s anticipated LNG sales. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. The Company’s sales of natural gas, crude oil, condensate, and NGLs are generally made at market prices for those products at the time of sale. The Company also purchases natural gas, crude oil, condensate, and NGLs from third parties, primarily near Anadarko’s production areas, to aggregate volumes so that the Company is positioned to utilize transportation and storage capacity fully, attract creditworthy customers, facilitate efforts to maximize prices received, and minimize balancing issues with customers and pipelines during operational disruptions.
The Company sells its products under a variety of contract structures including indexed, fixed-price, and cost-escalation-based agreements. The Company also engages in limited trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate, and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, crude-oil, NGLs, and LNG commodity contracts. The Company’s marketing-risk position is typically a net short position (reflecting agreements to sell natural gas, crude oil, and NGLs in the future for specific prices) that is offset by the Company’s natural long position as a producer (reflecting ownership of underlying natural-gas and crude-oil reserves). See Commodity Price Risk under Item 7A of this Form 10-K.

Natural Gas  Anadarko markets its natural-gas production to maximize value and to reduce the inherent risks of physical commodity markets. Anadarko’s marketing segment offers supply-assurance and limited risk-management services at competitive prices, as well as other services that are tailored to its customers’ needs. The Company may also receive a service fee related to the level of reliability and service required by the customer. The Company controls natural-gas firm-transportation capacity that ensures access to downstream markets, which enables the Company to maximize its natural-gas production. This transportation capacity also provides the opportunity to capture incremental value when price differentials between physical locations exist. The Company stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical-delivery or financial derivative instruments) to sell stored natural gas at a fixed price.


23


Crude Oil, Condensate, and NGLs  Anadarko’s crude-oil, condensate, and NGLs revenues are derived from production in the United States, Algeria, China, and Ghana. Most of the Company’s U.S. crude-oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality, and transportation. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD) Blend to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the market for the heavy fuel oil blend stock. Oil from Ghana is sold by tanker as Jubilee Crude Oil to customers around the world. Jubilee Crude Oil is high-quality crude that provides refiners large quantities of premium products such as gasoline, diesel, and jet fuel. The Company also purchases and sells third-party-produced crude oil, condensate, and NGLs, and utilizes contracted NGLs storage facilities to capture market opportunities and reduce fractionation and downstream infrastructure disruptions.

COMPETITION

The oil and gas business is highly competitive in the exploration for and acquisition of reserves and in the gathering and marketing of oil and gas production. The Company’s competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers.

SEGMENT INFORMATION

For additional information on operations by segment, see Note 21—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and for additional information on risk associated with international operations, see Risk Factors under Item 1A of this Form 10-K.

EMPLOYEES

The Company had approximately 5,700 employees at December 31, 2013.

24


REGULATORY AND ENVIRONMENTAL MATTERS

Environmental and Occupational Health and Safety Regulations

Anadarko’s business operations are subject to numerous international, provincial, federal, regional, state, tribal, and local environmental and occupational health and safety laws and regulations. These laws and regulations pertain to the discharge of materials into the environment; the generating, handling, and disposal of materials (including solid and hazardous wastes); the workplace health and safety of employees; or otherwise relating to the prevention, mitigation, or remediation of pollution, or the protection of natural resources, wildlife, or the environment. The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:
 
the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements
the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), which regulates discharges of pollutants from facilities to state and federal waters
the U.S. Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to strict liability for removal costs and damages arising from an oil spill in waters of the United States
U.S. Department of the Interior (DOI) regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, a remedial statute that imposes strict liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur
the U.S. Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes
the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources
the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and response departments
the U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures
the National Environmental Policy Act, which requires federal agencies, including the DOI, to evaluate major agency actions having the potential to impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

25


the Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and which may require the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas
the Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

These and other laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Compliance with these laws and regulations also, in most cases, requires new or amended permits that may contain new or more stringent technological standards or limits on emissions, discharges, disposals, or other releases in association with new or modified operations. Application for permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with public notice and comment periods required prior to the issuance or amendment of a permit as well as the agency’s processing of an application. Many of the delays associated with the permitting process are beyond the control of the Company.
Many states and foreign countries where the Company operates also have, or are developing, similar environmental laws, regulations, or analogous controls governing many of these same types of activities. While the legal requirements may be similar in form, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the development of a project or substantially increase the cost of doing business.
Anadarko is also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations.
Federal and state occupational safety and health laws require the Company to organize information about materials, some of which may be hazardous or toxic, that are used, released, stored, or produced in Anadarko’s operations. Certain portions of this information must be provided to employees, state and local governmental authorities and responders, and local citizens. The Company is also subject to the safety hazard communication requirements and reporting obligations set forth in federal workplace standards.

26


There have been several regulatory and governmental initiatives related to the hydraulic-fracturing process, which could have an adverse impact on our completion or production activities. The U.S. Environmental Protection Agency (EPA) has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic-fracturing practices involving diesel notwithstanding the existence of current oil and gas regulations adopted at the state level. Moreover, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report expected to be available for public comment and peer review by 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities for shale gas. In May 2013, the federal Bureau of Land Management (BLM) published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands, replacing a prior proposed rulemaking issued in May 2012, that would require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. Certain other governmental reviews have been recently conducted or are underway that focus on environmental aspects of hydraulic-fracturing practices, including an evaluation by the U.S. Department of Energy, and coordination of an administration-wide review of these practices by the White House Council on Environmental Quality. Congress has from time to time considered bills that would regulate hydraulic fracturing and/or require public disclosure of chemicals used in the hydraulic-fracturing process. A number of states, including states in which the Company operates, have adopted or are considering legal requirements that could impose more stringent permitting, public disclosure, and well-construction requirements on hydraulic-fracturing activities. In addition, local government may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular; for example, local ballot initiatives in the Colorado cities of Boulder, Broomfield, Fort Collins, and Lafayette to restrict oil and gas development, including the use of hydraulic fracturing, either temporarily or permanently, within their respective city’s limits were approved by voters in November 2013.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as new standards, such as air emission standards and water quality standards, continue to evolve. For example, in August 2012, the EPA published final rules under the federal Clean Air Act that subject oil and natural-gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from fractured gas wells for which well-completion operations are conducted. In 2013, the EPA reconsidered significant storage vessel requirements and will complete further reconsideration and rulemaking in 2014. In addition, environmental laws and regulations, including those that may arise to address concerns about global climate change and the threat of adverse impacts to groundwater arising from hydraulic-fracturing activities, are expected to continue to have an increasing impact on the Company’s operations in the United States and in other countries in which Anadarko operates. Notable areas of potential impacts include air emission monitoring, compliance, mitigation, and remediation obligations in the United States.
The Company has reviewed its potential responsibilities under both OPA and CWA as they relate to the Deepwater Horizon events. OPA imposes joint and several liability on the responsible parties for all cleanup and response costs, natural resource damages, and other damages such as lost revenues, damages to real or personal property, damages to subsistence users of natural resources, and lost profits and earning capacity. While OPA requires that a responsible party pay for all cleanup and response costs, it currently limits liability for damages to $75 million, exclusive of response and remediation expenses (for which there is no cap), except in cases of gross negligence, willful misconduct, or the violation of an applicable federal safety, construction, or operating regulation. The federal government may take legislative or other action to increase or eliminate, perhaps even retroactively, the liability cap. As for damages to natural resources, the government may recover damages for injury to, loss of, destruction of, or loss of use of natural resources which may include the costs to repair, replace, or restore those or like resources. The CWA governs discharges into waters of the United States and provides for penalties in the event of unauthorized discharges into those waters. Under the CWA, these include, among other penalties, civil penalties that may be assessed in an amount up to $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties that may be sought by the United States are increased to not more than $4,300 per barrel of oil discharged.

27


As of the date of filing this Form 10-K with the SEC, no penalties or fines have been assessed by the federal government against the Company under OPA, CWA, and other similar local, state and federal environmental legislation related to the Deepwater Horizon events. However, in December 2010, the U.S. Department of Justice, on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana, against several parties, including the Company, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. In October 2011, the Company and BP Exploration & Production Inc. (BP) entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement), pursuant to which BP has agreed to fully indemnify Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events and related damage claims arising under OPA. Under the Settlement Agreement, BP does not indemnify the Company against penalties or fines that may be assessed against the Company as a result of the Deepwater Horizon events, including for example, penalties or fines under the CWA. For additional information, see Note 17—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
The Company has made and will continue to make operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. These are necessary business costs in the Company’s operations and in the oil and natural-gas industry. Although the Company is not fully insured against all environmental and occupational health and safety risks, and the Company’s insurance does not cover any penalties or fines that may be issued by a governmental authority, it maintains insurance coverage that it believes is sufficient based on the Company’s assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental and occupational health and safety laws and regulations, as well as claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities, including administrative, civil, and criminal penalties, to Anadarko. The Company believes that it is in material compliance with existing environmental and occupational health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial position, results of operations, or cash flows, but new or more stringently applied existing laws and regulations could increase the cost of doing business, and such increases could be material.

Oil Spill-Response Plan

Domestically, the Company is subject to compliance with the Bureau of Safety and Environmental Enforcement (BSEE) regulations, which, among other standards, require every owner or operator of a U.S. offshore lease to prepare and submit for approval an oil spill-response plan prior to conducting any offshore operations. The submitted plan is required to provide a detailed description of actions to be taken in the event of a spill, identify contracted spill-response equipment, materials and trained personnel, and stipulate the time necessary to deploy identified resources in the event of a spill. The Company has filed the information that describes the Company’s ability to deploy surface and subsea containment resources to adequately and promptly respond to a blowout or other loss of well control. The BSEE regulations may be amended, resulting in changes to the amount and type of spill-response resources to which an owner or operator must maintain ready access. Accordingly, resources available to the Company may change to satisfy any new regulatory requirements, or to adapt to changes in the Company’s operations.
Anadarko has in place and maintains both Regional (Central and Western Gulf of Mexico) and Sub-Regional (Eastern Gulf of Mexico) Oil Spill-Response Plans (Plans) for the Company’s Gulf of Mexico operations. The Plans detail procedures for a rapid and effective response to spill events that may occur as a result of Anadarko’s operations. The Plans are reviewed at least annually and updated as necessary. Drills are conducted at least annually to test the effectiveness of the Plans and include the participation of spill-response contractors, representatives of Clean Gulf Associates (CGA, a not-for-profit association of production and pipeline companies operating in the Gulf of Mexico contractually engaged by the Company for such matters), and representatives of relevant governmental agencies. The Plans must be approved by the BSEE.

28


As part of the Company’s oil spill-response preparedness, and as set forth in the Plans, Anadarko maintains membership in CGA, and has an employee representative on the executive committee of CGA. CGA was created to provide a means of effectively staging response equipment and to provide effective spill-response capability for its member companies operating in the Gulf of Mexico.
CGA equipment includes the following: High Volume Open Sea Skimmer System (HOSS) barge, 95-foot skimming vessels, 46-foot skimming vessels, 56-foot skimming vessels, Marco skimmers, and Egmopol skimmers. Additional available equipment includes the following: fast response units, rope mop, barges, skimming arms, skim packages, and tanks. In addition, auto boom, beach boom, and fire boom are currently available through CGA. CGA also has a stockpile of Corexit 9500 dispersant spray system through Airborne Support Inc. (ASI), a wildlife rehabilitation trailer, and bird scare guns. CGA currently has one X-band radar installed on the HOSS barge.
CGA has executed a support contract with T&T Marine to coordinate bareboat charters and provides for expanded response support. T&T Marine is responsible for inspecting, maintaining, storing, and calling out CGA equipment. T&T Marine has positioned CGA’s equipment and materials in a ready state at various staging areas around the Gulf of Mexico.
T&T Marine also handles the maintenance and mobilization of CGA non-marine equipment. T&T Marine has service contracts in place with domestic environmental contractors as well as with other companies that provide support services during the execution of spill-response activities. In the event of a spill, T&T Marine will activate these contracts as necessary to provide additional resources or support services requested by CGA. In addition, CGA maintains a service contract with ASI, which provides aircraft and dispersant capabilities for CGA member companies.
Anadarko is also a member of the Marine Preservation Association, which provides full access to the Marine Spill Response Corporation (MSRC) cooperative including the Deep Blue enhanced Gulf of Mexico Response capability. In the event of a spill, MSRC stands ready to mobilize all of its equipment and materials. MSRC has a fleet of dedicated Responder Class Oil Spill-Response Vessels (OSRVs), designed and built specifically to recover spilled oil. Each OSRV is approximately 210 feet long, has temporary storage for recovered oil, and has the ability to separate oil and water aboard the vessels using two oil-water separation systems. To enable the OSRV to sustain cleanup operations, recovered oil can be transferred into other vessels or barges.
MSRC has equipment housed for the Atlantic Region, the Gulf of Mexico Region, the California Region, and the Pacific Northwest Region. The Gulf of Mexico Region has a total of approximately 60 skimmers with an Effective Daily Recovery Capacity (EDRC) of approximately 562,000 barrels. The California Region has approximately 278,000 barrels EDRC and the Pacific Northwest Region has approximately 335,000 barrels EDRC. Additional available equipment includes the following: OSRVs, fast response vessels, barges, storage bladders, work boats, ocean boom, and dispersant.
The Company has also entered into a contractual commitment to access subsea intervention, containment, capture, and shut-in capacity for deepwater exploration wells. Marine Well Containment Company (MWCC) is open to all oil and gas operators in the Gulf of Mexico and provides members access to oil spill-response equipment and services on a per-well fee basis. Anadarko has an employee representative on the executive committee of MWCC and this employee currently serves as its Chair. MWCC members have access to an interim containment system that includes a 15-kpsi capping stack and dispersant capability. The interim containment system is engineered to operate in deepwater depths of up to 10,000 feet, and has the capacity to contain 60 MBbls/d of liquids and flare 120 MMcf/d of natural gas. The DOI has reviewed the functional specifications of the MWCC interim containment system, and DOI input was included in the final specifications.
MWCC members also expect to have access to an expanded containment system that is planned for use in deepwater depths of up to 10,000 feet with containment capacity of 100 MBbls/d of liquids and flare capability for 200 MMcf/d of natural gas. The expanded system is planned to include a 15-kpsi subsea containment assembly with three rams stack, dedicated capture vessels, and a dispersant injection system. The expanded containment system may be further expanded with additional capture vessels, modified tankers, drill ships, and extended well-test vessels, all of which may process, store, and offload oil to shuttle tankers, which may then take the oil to shore for further processing. This expanded containment system is currently scheduled for delivery by mid-2014.

29


Anadarko retains geospatial and satellite imagery services through the MDA Corporation (MDA) to provide coverage over the Company’s Gulf of Mexico operations. MDA owns and maintains two radar satellites, RADARSAT-1 and RADARSAT-2, which provide all-weather surveillance and imagery available to assist in identifying areas of concern on the surface waters of the Gulf of Mexico. The Company has agreements with Waste Management, Inc. and Clean Harbors to assist in the proper disposal of contaminated and hazardous waste soil and debris. In addition, Anadarko has agreements with HDR Engineering, Inc. (HDR) for assistance with Subsea Dispersant applications. Staff members of HDR are recognized as worldwide experts in the proper use of dispersants in a subsea application, developing scientific methods for determining the proper injection, and monitoring of the dispersant while maintaining the environmental and ecosystem integrity and health. The Company also has agreements with TDI-Brooks International for its scientific research vessels to properly monitor the effectiveness of the dispersant application and the health of the ecosystem. The Company also has agreements with Scientific and Environmental Associates, Inc. (SEA) for assistance with surface-dispersant applications. SEA is a scientific support consulting firm providing subject matter experts, and is renowned for its expertise in surface-dispersion applications and efficacy monitoring.
Anadarko has emergency and oil spill-response plans in place for each of its exploration and operational activities around the globe. Each plan satisfies the requirements of relevant local or national authority, describes the actions the Company will take in the event of an incident, is subject to drills at least annually, and includes reference to external resources that may become necessary in the event of an incident. Included in these external resources is the Company’s contract with Oil Spill Response Limited (OSRL), a global emergency and oil spill-response organization headquartered in London. OSRL maintains specialized equipment in a ready state for deployment in the event such equipment is needed by one of its members. OSRL is mainly available for response internationally, but its equipment is registered with the U.S. Coast Guard for domestic use if needed.
OSRL has one 727 aircraft, located in the United Kingdom and one Hercules aircraft, located in Singapore, available for dispersant application or equipment transport. The aircraft have a three-hour callback time. The Hercules can transport two to three pre-packaged equipment loads, or one Aerial Dispersant Delivery System (ADDS) Pack. OSRL has three ADDS Packs: one in the United Kingdom, one in Bahrain, and one in Singapore. If additional aircraft are needed, OSRL retains an aircraft broker so that an aircraft can be chartered. For international operations, the majority of equipment will be air freighted.
OSRL has a number of active recovery boom systems, and a range of booms that can be used for offshore, nearshore, or shoreline responses. Offshore boom is stored in the United Kingdom, Bahrain, and Singapore. Fireboom systems have been delivered and a team is trained to operate the system. A variety of nearshore boom exists for spill containment.
OSRL also provides a range of communications equipment, safety equipment, transfer pumps, dispersant application systems, temporary storage equipment, power packs and generators, small inflatable vessels, rigid inflatable boats, work boats, and Fast Response Vessels. Oleophilic, weir, and mechanical skimmers provide the ability to recover a range of oil types. OSRL also has a wide range of oiled wildlife equipment in conjunction with the Sea Alarm Foundation.
During 2013, Clean Caribbean and Americas, a cooperative located in Fort Lauderdale, Florida, was integrated into OSRL and assets now available to OSRL members include an ADDS Pack, dispersant stockpile, and a depot of mechanical containment and recovery systems.
In addition, during 2013, a small group of exploration and production companies reached an agreement as a subset of OSRL to develop the Global Dispersant Stockpile of 5,000 cubic meters of dispersant designed to support response efforts for up to 30 days or until the dispersant production facilities could take up production.
In addition to Anadarko’s membership in or access to CGA, MSRC, OSRL, and MWCC, the Company participates in industry-wide task forces, which are currently studying improvements in both gaining access to and controlling blowouts in subsea environments. Two such task forces are the Subsea Well Control and Containment Task Force, and the Oil Spill Task Force.

30


TITLE TO PROPERTIES

As is customary in the oil and gas industry, a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by third-party attorneys and curative work is performed with respect to significant defects, if any, before proceeding with operations. Anadarko believes the title to its leasehold properties is good, defensible, and customary with practices in the oil and gas industry, subject to such exceptions that, in the opinion of legal counsel for the Company, do not materially detract from the use of such properties.
Leasehold properties owned by the Company are subject to royalty, overriding royalty, and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements, current taxes, development obligations under oil and gas leases and other encumbrances, easements, and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.

EXECUTIVE OFFICERS OF THE REGISTRANT
Name
 
Age at
January 31,
2014
 
Position
R. A. Walker
 
56
 
Chairman, President and Chief Executive Officer
Robert P. Daniels
 
55
 
Executive Vice President, International and Deepwater Exploration
Robert G. Gwin
 
50
 
Executive Vice President, Finance and Chief Financial Officer
James J. Kleckner
 
56
 
Executive Vice President, International and Deepwater Operations
Charles A. Meloy
 
53
 
Executive Vice President, U.S. Onshore Exploration and Production
Robert K. Reeves
 
56
 
Executive Vice President, General Counsel and Chief Administrative Officer
M. Cathy Douglas
 
57
 
Senior Vice President, Chief Accounting Officer and Controller

Mr. Walker was named Chairman of the Board of the Company in May 2013, in addition to the role of Chief Executive Officer and director, both of which he assumed in May 2012, and the role of President, which he assumed in February 2010. He previously served as Chief Operating Officer from March 2009 until his appointment as Chief Executive Officer. He served as Senior Vice President, Finance and Chief Financial Officer from September 2005 until March 2009. From August 2007 until March 2013, he served as director of Western Gas Holdings, LLC (WGH), the general partner of WES, and served as its Chairman of the Board from August 2007 to September 2009. Mr. Walker served as a director of Western Gas Equity Holdings, LLC (WGEH), the general partner of WGP, from September 2012 until March 2013. Mr. Walker served as a director of Temple-Inland Inc. from November 2008 to February 2012 and has served as a director of CenterPoint Energy, Inc. since April 2010 and as a director of BOK Financial Corporation since April 2013.
Mr. Daniels was named Executive Vice President, International and Deepwater Exploration in May 2013 and previously served as Senior Vice President, International and Deepwater Exploration since July 2012. Prior to these positions, he served as Senior Vice President, Worldwide Exploration since December 2006 and served as Senior Vice President, Exploration and Production since May 2004. Prior to that position, he served as Vice President, Canada since July 2001. Mr. Daniels also served in various managerial roles in the Exploration Department for Anadarko Algeria Company, LLC. He has worked for the Company since 1985.
Mr. Gwin was named Executive Vice President, Finance and Chief Financial Officer in May 2013 and previously served as Senior Vice President, Finance and Chief Financial Officer since March 2009 and Senior Vice President since March 2008. He also has served as Chairman of the Board of WGH since October 2009 and as a director since August 2007. Additionally, Mr. Gwin has served as Chairman of the Board of WGEH since September 2012, and served as President of WGH from August 2007 to September 2009 and as Chief Executive Officer of WGH from August 2007 to January 2010. He joined Anadarko in January 2006 as Vice President, Finance and Treasurer and served in that capacity until March 2008. He has served as Chairman of the Board of LyondellBasell Industries N.V. since August 2013 and as a director since May 2011.

31


Mr. Kleckner was named Executive Vice President, International and Deepwater Operations in May 2013. Prior to this position, he served as Vice President, Operations for the Rockies region since May 2007. Mr. Kleckner joined Anadarko upon the acquisition of Kerr-McGee Corporation in August 2006. He has held positions of increasing responsibility with Anadarko and Kerr-McGee Corporation, including management roles in the North Sea, South America, China, the Gulf of Mexico and U.S. onshore. Prior to joining Kerr-McGee Corporation, Mr. Kleckner was in the oil and natural-gas industry with Oryx Energy Company and its predecessor, Sun Oil Company.
Mr. Meloy was named Executive Vice President, U.S. Onshore Exploration and Production in May 2013 and previously served as Senior Vice President, U.S. Onshore Exploration and Production since July 2012. Prior to this position, he served as Senior Vice President, Worldwide Operations since December 2006 and served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee Corporation in August 2006. Prior to joining Anadarko, he served Kerr-McGee Corporation as Vice President of Exploration and Production from 2005 to 2006, Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005, Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004 and Vice President of Gulf of Mexico Deepwater from 2000 to 2002. Prior to joining Kerr-McGee Corporation, Mr. Meloy was in the oil and natural-gas industry with Oryx Energy Company and its predecessor, Sun Oil Company. Mr. Meloy has served as a director of WGH since February 2009 and as a director of WGEH since September 2012.
Mr. Reeves was named Executive Vice President, General Counsel and Chief Administrative Officer in May 2013 and previously served as Senior Vice President, General Counsel and Chief Administrative Officer since February 2007. He also served as Chief Compliance Officer from July 2012 to May 2013. He served as Corporate Secretary from February 2007 to August 2008. He previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He has served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, since October 2007, as a director of WGH since August 2007 and as a director of WGEH since September 2012.
Ms. Douglas was named Senior Vice President, Chief Accounting Officer and Controller in May 2013. Prior to this position, she served as Vice President and Chief Accounting Officer since November 2008 and served as Corporate Controller from September 2007 to March 2009 and from March 2013 to May 2013. She served as Assistant Controller from July 2006 to September 2007. She also served as Director, Accounting, Policy and Coordination from October 2006 to September 2007 and Financial Reporting and Policy Manager from January 2003 to October 2006. Ms. Douglas joined Anadarko in 1979.
Officers of Anadarko are elected each year at the first meeting of the Board of Directors following the annual meeting of stockholders, the next of which is expected to occur on May 13, 2014, and hold office until their successors are duly elected and qualified. There are no family relationships between any directors or executive officers of Anadarko.

32


Item 1A.  Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realized. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:
 
the Company’s assumptions about energy markets
production levels
reserves levels
operating results
competitive conditions
technology
availability of capital resources, levels of capital expenditures, and other contractual obligations
supply and demand for, the price of, and the commercializing and transporting of natural gas, crude oil, natural gas liquids (NGLs), and other products or services
volatility in the commodity-futures market
weather
inflation
availability of goods and services, including unexpected changes in costs
drilling risks
future processing volumes and pipeline throughput
general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business
the Company’s inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects
legislative or regulatory changes, including retroactive royalty or production tax regimes; hydraulic-fracturing regulation; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations

33


ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for Deepwater Horizon events, including, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations
impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against the Company, for which it is not indemnified by BP
current and potential legal proceedings, or environmental or other obligations related to or arising from Tronox Incorporated (Tronox)
civil or political unrest or acts of terrorism in a region or country
creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk
the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings
disruptions in international crude oil cargo shipping activities
physical, digital, internal, and external security breaches
supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations
other factors discussed below and elsewhere in this Form 10-K, and in the Company’s other public filings, press releases, and discussions with Company management

We are, and in the future may become, involved in legal proceedings related to Tronox and, as a result, may incur substantial liabilities in connection with those proceedings, which could have a material adverse effect on our business, prospects, results of operations, cash flows, financial condition, and liquidity.

In January 2009, Tronox, a former subsidiary of Kerr-McGee Corporation, which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its initial public offering and sought, among other things, to recover damages from Kerr-McGee and Anadarko, as well as interest, appreciation, and attorneys’ fees and costs. See Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for the nature and status of this litigation and the Company’s liability accrual.
As a result of the Bankruptcy Court’s finding of liability in its Memorandum of Opinion, After Trial (Opinion) issued in December 2013, the Company believes that a loss in the Adversary Proceeding is probable and has recorded a liability of $850 million at December 31, 2013. The Company’s liability is based on the application of relevant accounting guidance and law to the information known to the Company at this time. The Bankruptcy Court has not entered a judgment against Kerr-McGee because the Bankruptcy Court has not resolved questions it raised concerning the appropriate application of bankruptcy law to Kerr-McGee’s right to an offset claim that would reduce the amount of damages to be awarded to the plaintiffs. As the post-trial proceedings continue, the Bankruptcy Court issues a judgment and the parties consider appeal, it is possible that the Company may be required to increase the accrued liability related to the Adversary Proceeding.

34


While we currently expect to fully pursue all rights available through the appellate process, the Company cannot guarantee success on appeal. If the Company is ultimately required to pay a judgment, the Company may be required to access its $5.0 billion Facility, enter into new or amended financing arrangements, identify and divest assets and/or use cash flows from operations to secure sufficient funds. The Company’s liabilities relating to Tronox could exceed current estimates, and we could incur additional liabilities that we are unable to estimate or predict at this time. These events could have a material adverse effect on our business, prospects, consolidated financial position, results of operations, cash flows, financial condition, and liquidity.
During the appeals process, the Company may be required to post a bond or provide sufficient security within 14 days of a judgment to stay execution of the judgment by the plaintiffs pending the outcome of the appellate process. Depending on the amount of a judgment, there is no guarantee that the Company will be able to post a bond in a timely manner or provide security at levels acceptable to the Bankruptcy Court.
The Company’s ability to post a bond or provide sufficient security to stay a judgment depends on a variety of factors, including, but not limited to, the amount of the judgment, the willingness of the Bankruptcy Court to accept alternative forms of security, the willingness of bond providers to issue bonds in the required amount or at all, and the proposed terms of such bonds. The Company may be required to access existing or new financing arrangements and monetize or pledge assets in order to post a bond or provide any such required security. There is no assurance that the Company would be able to take such actions on acceptable terms or at all. In addition, any such financing arrangements could subject the Company to covenants imposing additional or more burdensome restrictions on the Company’s business, relative to the covenants currently contained in the $5.0 billion Facility and other existing debt agreements. Moreover, the Company could incur significant fees or costs to obtain and maintain a bond or additional financing arrangements.

A downgrade or other negative rating action with respect to our credit rating could negatively impact our cost of and ability to access capital.

In December 2013, following the Bankruptcy Court’s issuance of the Opinion relating to Tronox, Standard and Poor’s (S&P) affirmed its “BBB-” rating of the Company’s debt but revised its outlook from “positive” to “negative” and Moody’s Investors Service (Moody’s) affirmed its “Baa3” rating but revised its outlook from “positive” to “developing.” At that time, Fitch Ratings (Fitch) announced no change to its “BBB-” rating with a stable outlook. As of the date of this Form 10-K, no changes in the Company’s credit ratings have occurred and we are not aware of any current plans of S&P, Moody’s, or Fitch to lower their respective ratings on our debt. However, we cannot provide assurance that our credit ratings will not be downgraded or otherwise negatively affected, especially at the time the Bankruptcy Court issues a judgment, depending on the amount of the judgment. A downgrade of our credit ratings could negatively impact our cost of capital and our ability to access capital markets, increase our costs under our $5.0 billion Facility, and limit our ability to effectively execute aspects of our strategy.
In addition, a downgrade or other negative rating action could affect the Company’s requirements to post collateral as financial assurance of its performance under certain contractual arrangements, such as pipeline transportation contracts, oil and gas sales contracts, and work commitments. Following the December 2013 outlook revisions by S&P and Moody’s, $17 million of letters of credit were provided as assurance of the Company’s performance under these types of arrangements. A downgrade or other negative rating action could also prompt requests by some of Anadarko’s business partners for the Company to post additional collateral in the form of letters of credit or cash.
A downgrade could also trigger provisions in certain of the Company’s derivative instruments that can require full or partial collateralization or immediate settlement of the Company’s obligations. Most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion Facility, and if such facility terminates, the Company may be required to post collateral pursuant to existing credit support arrangements. A downgrade could also cause the Company’s credit thresholds with such derivative counterparties to be reduced or eliminated, increasing the amount of collateral required. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed at December 31, 2013, was $42 million (net of collateral). See Note 11—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


35


We may be subject to claims and liabilities relating to the Deepwater Horizon events that are not covered by BP’s indemnification obligations under our Settlement Agreement with BP, or that result in losses to the Company, notwithstanding BP’s indemnification against such losses, as a result of BP’s inability to satisfy its indemnification obligations under the Settlement Agreement and BPCNA’s and BP p.l.c.’s inability to satisfy their guarantees of BP’s indemnification obligations.

In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, NRD claims and assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BPCNA and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor.
Any failure or inability on the part of BP to satisfy its indemnification obligations under the Settlement Agreement, or on the part of BPCNA or BP p.l.c. to satisfy their respective guarantee obligations, could subject us to significant monetary liability beyond the terms of the Settlement Agreement, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. In November 2012, BP settled all criminal and securities claims brought by the United States against BP, with BP agreeing to pay $4.0 billion over five years to the U.S. Department of Justice with respect to the criminal claims and further agreeing to pay another $525 million over three years to the Securities and Exchange Commission (SEC) with respect to the securities claims. BP represents that it is prepared to vigorously defend itself against remaining civil claims. Furthermore, in certain instances we may be required to recognize a liability for amounts for which we are indemnified in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. Any such liability recognition without collection of the offsetting receivable could adversely impact our results of operations, our financial condition, and our ability to make borrowings.
Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The adverse resolution of any current or future proceeding related to the Deepwater Horizon events for which we are not indemnified by BP could subject us to significant monetary liability, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Oil, natural-gas, and NGLs prices are volatile. A substantial or extended decline in the price of these commodities could adversely affect our financial condition and results of operations.

Prices for oil, natural gas, and NGLs can fluctuate widely. Our revenues, operating results, and future growth rates are highly dependent on the prices we receive for our oil, natural gas, and NGLs. The markets for oil, natural gas, and NGLs have been volatile historically and may continue to be volatile in the future. Factors influencing the prices of oil, natural gas, and NGLs are beyond our control. These factors include, but are not limited to, the following:
 
domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs
volatile trading patterns in the commodity-futures markets
cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs
level of global crude-oil and natural-gas inventories
weather conditions
potential U.S. exports of liquefied natural gas or crude oil
ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels
worldwide military and political environment, civil and political unrest in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or further acts of terrorism in the United States, or elsewhere

36


effect of worldwide energy conservation and environmental protection efforts
price and availability of alternative and competing fuels
price and level of foreign imports of oil, natural gas, and NGLs
domestic and foreign governmental regulations and taxes
proximity to, and capacity of, natural-gas pipelines and other transportation facilities
general economic conditions worldwide

The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:
 
adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
reducing the amount of oil, natural gas, and NGLs that we can produce economically
causing us to delay or postpone some of our capital projects
reducing our revenues, operating income, or cash flows
reducing the amounts of our estimated proved oil and natural-gas reserves
reducing the carrying value of our oil and natural-gas properties
reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves
limiting our access to, or increasing the cost of, sources of capital, such as equity and long-term debt

Our domestic operations are subject to governmental risks that may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, provincial, regional, state, tribal, local, and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing, and environmental protection regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, provincial, regional, state, tribal, and local governmental authorities. Government disruptions, such as an extended federal government shutdown resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations. As a result, activity in the affected regions, such as the Gulf of Mexico and on federal and Indian lands in the United States, could be adversely affected or delayed. In addition, the adoption of government payment transparency regulations could harm our competitiveness or relations with other governments or third parties. We may also incur substantial costs to maintain compliance with these existing laws and regulations. Our costs of compliance may increase if existing laws, including environmental and tax laws and regulations, are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, from time to time, legislation has been proposed that could adversely affect our business, financial condition, results of operations, or cash flows related to the following:
 
Climate Change.  A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, the U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs. In addition, certain operations are subject to EPA rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore production sources in the United States on an annual basis.

37


Deficit Reduction or Tax Reform.  Congress may undertake significant deficit reduction or comprehensive tax reform in the coming year. Proposals include provisions that would, if enacted, (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) eliminate the manufacturing deduction for oil and gas qualified production activities, and (iii) eliminate accelerated depreciation for tangible property.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an essential and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and in its semi-annual regulatory agenda published in July 2013, the agency continues to project the issuance of an Advance Notice of Proposed Rulemaking, but it does not state a deadline for such issuance. In May 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands, replacing a prior proposed rulemaking issued in May 2012, that would require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. In addition, Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Certain states in which we operate, including Colorado, Pennsylvania, Louisiana, Texas, Ohio, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular; for example, local ballot initiatives in the Colorado cities of Boulder, Broomfield, Fort Collins, and Lafayette to restrict oil and gas development, including the use of hydraulic fracturing, either temporarily or permanently, within their respective cities’ limits were approved by voters in November 2013. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic-fracturing activities. Nonetheless, in the event state or local restrictions or prohibitions are adopted in areas where we currently conduct operations, or in the future plan to conduct operations, we may incur significant costs to comply with such requirements or we may experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Depending on the state or area in which they are adopted, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

38


There are also certain governmental reviews recently conducted or underway that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards for shale gas by 2014. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods and, in August 2011, issued a report on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale-gas development. Also, as discussed above, the BLM is pursuing regulations governing hydraulic fracturing on federal and Indian oil and gas leases. These studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

The additional deepwater drilling laws and regulations, both domestically and internationally, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related developments arising after the deepwater drilling moratorium in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement, each agencies of the U.S. Department of the Interior, issued directives in May and July 2010 requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf (OCS) regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, but excluding workovers, completions, plugging and abandonment, or production, through November 30, 2010. In addition, the agencies issued a series of rules and Notices to Lessees and Operators imposing new and more stringent regulatory safety and performance requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. If similar events were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development.
Compliance with these new and more stringent rules and regulations, uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, and oil spill-response plans, as a result of the new laws and regulations, and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts. Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased costs and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or all of our facilities. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover the risks associated with such operations.
Further, the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite the Company’s oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident.
The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.


39


Our debt and other financial commitments may limit our financial and operating flexibility.

Our total debt was $13.6 billion at December 31, 2013. We also have various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services and products. Our financial commitments could have important consequences to our business including, but not limited to, the following:
 
increasing our vulnerability to general adverse economic and industry conditions
limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt or to comply with any restrictive terms of our debt
limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate
placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments

Additionally, the credit agreement governing our senior secured revolving credit facility ($5.0 billion Facility) contains a number of covenants that impose operating and financial constraints on the Company, including restrictions on our ability to incur additional indebtedness, sell assets, and incur liens. Provisions of the $5.0 billion Facility also require us to maintain specified financial covenants as further described in Liquidity and Capital Resources under Item 7 of this Form 10-K. Our ability to meet such covenants may be affected by events beyond our control.

Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause the quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. The reserves information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, no reserves audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows depend on a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates. These factors and assumptions may include, but are not limited to, the following:
 
historical production from an area compared with production from similar producing areas
assumed effects of regulation by governmental agencies and court rulings
assumptions concerning future oil and natural-gas prices, future operating costs, and capital expenditures
estimates of future severance and excise taxes, workover costs, and remedial costs

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on average 12-month sales prices using the average beginning-of-month price. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.


40


Failure to replace reserves may negatively affect our business.

Our future success depends on our ability to find, develop, or acquire additional oil and natural-gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities, acquire properties containing proved reserves, or both. We may be unable to find, develop, or acquire additional reserves on an economic basis. Furthermore, if oil and natural-gas prices increase, our costs for finding or acquiring additional reserves could also increase.

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 portion of our leasehold acreage is currently undeveloped. Unless production in sufficient 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 on various factors: 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.

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

During the last few years, concerns over inflation, potential default on U.S. debt, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If economic recovery in the United States or abroad is prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs; affect our vendors’, suppliers’ and customers’ ability to continue operations; and ultimately adversely impact our results of operations, liquidity, and financial condition.

Our results of operations could be adversely affected by goodwill impairments.

As a result of mergers and acquisitions, we had approximately $5.5 billion of goodwill on our Consolidated Balance Sheet at December 31, 2013. Goodwill must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment. Goodwill is considered impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to an impairment of goodwill, such as the Company’s inability to replace the value of its depleting asset base, difficulty or potential delays in obtaining drilling permits, or other adverse events, such as lower sustained oil and natural-gas prices, which could reduce the fair value of the associated reporting unit. An impairment of goodwill could have a substantial negative effect on our profitability.


41


We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner, and feasibility of doing business.

Our operations and properties are subject to numerous federal, provincial, regional, state, tribal, local, and foreign laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:
 
issuance of permits in connection with exploration, drilling, production, and midstream activities
protection of endangered species
amounts and types of emissions and discharges
generation, management, and disposition of waste materials
offshore oil and gas operations and decommissioning of abandoned facilities
reclamation and abandonment of wells and facility sites
remediation of contaminated sites

In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Future environmental laws and regulations, such as the restriction against emission of pollutants from previously unregulated activities or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. The cost of satisfying these requirements may have an adverse effect on our financial condition, results of operations, or cash flows or could result in limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce our reserves. For a description of certain environmental proceedings in which we are involved, see Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

We are vulnerable to risks associated with our offshore operations that could negatively impact our operations and financial results.

We conduct offshore operations in the Gulf of Mexico, Mozambique, Ghana, China, Brazil, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, New Zealand, Colombia, South Africa, and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas because we are vulnerable to certain unique risks associated with operating offshore, including those relating to the following:
 
hurricanes and other adverse weather conditions
oilfield service costs and availability
compliance with environmental and other laws and regulations
terrorist attacks, such as piracy
remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials
failure of equipment or facilities

In addition, we conduct some of our exploration in deep waters (greater than 1,000 feet) where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require significant time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

42


Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production and, as a result, our reserves replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

We operate in foreign countries and are subject to political, economic, and other uncertainties.

Our operations outside the United States are based primarily in Algeria, Brazil, China, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, Sierra Leone, and South Africa. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include the following, among other things:
 
loss of revenue, property, and equipment or delays in operations as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks, including tension and confrontations among political parties
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act, and other anti-corruption compliance laws and issues
increases in taxes and governmental royalties
unilateral renegotiation of contracts by governmental entities
redefinition of international boundaries or boundary disputes
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations
changes in laws and policies governing operations of foreign-based companies
foreign-exchange restrictions
international monetary fluctuations and changes in the relative value of the U.S. dollar as compared to the currencies of other countries in which we conduct business

For example, Ghana and Côte d’Ivoire are currently engaged in a dispute regarding the international maritime and land boundaries between the two countries. As a result, Côte d’Ivoire claims to be entitled to the maritime area which covers a portion of the Deepwater Tano Block where we are currently developing the TEN complex. In the event Côte d’Ivoire is successful in its maritime border claims, this development could be materially impacted. More recently, Venezuela has engaged Guyana in a dispute with regard to their maritime and land borders. Anadarko was forced to stop a seabed study undertaken within Guyana’s Exclusive Economic Zone pursuant to contractual rights granted by Guyana when a Venezuelan naval vessel escorted the vessel to a Venezuelan port because it claims the area as being within its national maritime territory. The two countries have initiated a dialogue. At this time we are unable to ascertain the full impact of this maritime border dispute on future operations in Guyana.
Outbreaks of civil and political unrest and acts of terrorism have occurred in several countries in Africa and the Middle East, including countries where we conduct operations, such as Algeria and Tunisia. As exhibited by the events in Tunisia, Egypt, and Libya, outbreaks of civil and political unrest have resulted in established governing bodies being overthrown. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired.
Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.
Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations, or cash flows.

43


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

To the extent that we engage in commodity-price risk-management activities to protect our cash flows 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 commodity-price risk-management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which the following occur:
 
our production is less than the notional volumes
a widening of price basis differentials occurs between delivery points for our production and the delivery point assumed in the derivative arrangement
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements
a sudden unexpected event materially impacts oil and natural-gas prices

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished.
The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures contracts in designated physical commodities and for options and swaps that are their economic equivalents. The CFTC’s initial position-limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. It is not possible at this time to predict when the CFTC will finalize these regulations; therefore, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest-rate swaps and credit-default swaps for mandatory clearing and exchange trading. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although the Company believes that it qualifies for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to manage its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Company uses for hedging. In addition, the Dodd-Frank Act requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to enter into derivatives to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore, the impact of those provisions to us is uncertain at this time.
The Dodd-Frank Act and regulations may also result in counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices. The Company’s revenues could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.

44


The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less-creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent the Company transacts with counterparties in foreign jurisdictions, it may become subject to such regulations. At this time, the impact of such regulations is not clear.
Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

Deterioration in the credit or equity markets could adversely affect us.

We have exposure to different counterparties. For example, we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds, and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. 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. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time.

We are not insured against all of the operating risks to which our business is exposed.

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing, and transportation of oil and gas, including blowouts; cratering and fire; environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, and releases of chemicals or other hazardous substances, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations, production facilities, and other property; pollution or other environmental damage; and injury to persons. For protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, aviation liability, and worker’s compensation and employer’s liability. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, business interruption, war, terrorism, and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.


45


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

We are involved in several large development projects and the completion of those projects may be delayed beyond our anticipated completion dates. Key factors that may affect the timing and outcome of such projects include the following:
 
project approvals by joint-venture partners
timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals
weather conditions
availability of personnel
civil and political environment of the country or region in which the project is located
manufacturing and delivery schedules of critical equipment
commercial arrangements for pipelines and related equipment to transport and market hydrocarbons

Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to large development projects and could have a material adverse effect on our results of operations.

The oil and gas exploration and production industry is very competitive, and some of our exploration and production competitors have greater financial and other resources than we do.

The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Some of our competitors may have greater and more diverse resources on which to draw than we do. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, or qualified personnel. During these periods, the costs of rigs, equipment, supplies, and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel, and other oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition, or results of operations.


46


Our drilling activities may not be productive.

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural-gas reservoirs. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including the following:
 
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
difficulty identifying and retaining qualified personnel
title problems
other adverse weather conditions
shortages or delays in the delivery of equipment

Certain of our 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. Because of the percentage of our capital budget devoted to high-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.

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

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

Our ability to sell our oil and gas production could be materially harmed if we fail to obtain adequate services such as transportation.

The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities and tanker transportation. If any pipelines or tankers become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport the oil and natural gas, which could increase our costs and/or reduce the revenues we might obtain from the sale of the oil and gas.

Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.
In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.


47


We may reduce or cease to pay dividends on our common stock.

We can provide no assurance that we will continue to pay dividends at the current rate or at all. The amount of cash dividends, if any, to be paid in the future will depend on actions taken by our Board of Directors, as well as, our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, future business prospects, expected liquidity needs, and other related matters that our Board of Directors deems relevant.

The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success.

The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team could have an adverse effect on our business. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers, and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

GENERAL  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that, with the possible exception of the Tronox Litigation discussed in Note 17—Contingencies—Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
In July 2013, Kerr-McGee Gathering LLC, one of the Company’s consolidated subsidiaries, entered into a consent order with the Colorado Department of Public Health and Environment relating to the failure to comply with certain terms of permits at its Frederick compression station and agreed to pay a penalty of approximately $125,000.
In September 2013, Anadarko received a Notice of Proposed Penalty Assessment (Notice) from the Bureau of Safety and Environmental Enforcement (BSEE) as the result of an incident that occurred in February 2012 relating to a drilling rig in the Gulf of Mexico. In the Notice, the BSEE alleged several violations of certain offshore operational requirements and proposed a penalty in the amount of $395,000. Anadarko has disputed many of the allegations and is working with the BSEE to resolve this matter.
See Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

Item 4.  Mine Safety Disclosures

Not applicable.

48


PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MARKET INFORMATION, HOLDERS, AND DIVIDENDS

At January 31, 2014, there were approximately 12,200 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the market price of and dividends declared and paid on the Company’s common stock by quarter for 2013 and 2012:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2013
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
89.20

 
$
92.18

 
$
96.75

 
$
98.47

Low
$
74.73

 
$
78.30

 
$
86.08

 
$
73.60

Dividends
$
0.09

 
$
0.09

 
$
0.18

 
$
0.18

2012
 
 
 
 
 
 
 
Market Price
 
 
 
 
 
 
 
High
$
88.70

 
$
79.85

 
$
76.63

 
$
76.95

Low
$
75.90

 
$
56.42

 
$
64.19

 
$
65.82

Dividends
$
0.09

 
$
0.09

 
$
0.09

 
$
0.09


The amount of future common stock dividends will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with its financial covenants, and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Liquidity and Capital Resources—Uses of Cash—Common Stock Dividends and Distributions to Noncontrolling Interest Owners under Item 7 of this Form 10-K.


49


SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, 2013:
Plan Category
 
(a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
 
(b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
 
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
Equity compensation plans
   approved by security holders
 
7,715,832

 
$
63.30

 
25,581,734

Equity compensation plans not
   approved by security holders
 

 

 

Total
 
7,715,832

 
$
63.30

 
25,581,734


PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of 2013:
Period
 
Total
number of
shares
purchased (1)
 
Average
price paid
per share
 
Total number of
shares purchased
as part of publicly
announced plans
or programs
 
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
October
 
724

 
$
93.08

 

 
 
November
 
215,015

 
$
91.34

 

 
 
December
 
49,908

 
$
88.46

 

 
 
Fourth Quarter 2013
 
265,647

 
$
90.80

 

 
$

 _______________________________________________________________________________
(1) 
During the fourth quarter of 2013, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.

For additional information, see Note 15—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


50


PERFORMANCE GRAPH

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative five-year total return to stockholders of Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and two peer groups. The 11 companies included in the new peer group (New Peer Group) are Apache Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Murphy Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; and Pioneer Natural Resources Company. The 10 companies included in the old peer group (Old Peer Group) are Apache Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; and Pioneer Natural Resources Company. Plains Exploration and Production Company was excluded from the Old Peer Group since it was acquired in May 2013 and ceased trading. As a result, Murphy Oil Corporation was included in the New Peer Group for 2013.
Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index,
the New Peer Group, and the Old Peer Group
 
Copyright© 2014 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in each of the peer groups on December 31, 2008, and its relative performance is tracked through December 31, 2013. 
Fiscal Year Ended December 31
2008
 
2009
 
2010
 
2011
 
2012
 
2013
Anadarko Petroleum Corporation
$
100.00

 
$
163.18

 
$
200.35

 
$
201.75

 
$
197.40

 
$
211.99

S&P 500
100.00

 
126.46

 
145.51

 
148.59

 
172.37

 
228.19

New Peer Group
100.00

 
117.43

 
145.22

 
153.46

 
156.49

 
196.69

Old Peer Group
100.00

 
117.28

 
144.58

 
153.93

 
156.59

 
196.70


51


Item 6.  Selected Financial Data
 
Summary Financial Information (1)
millions except per-share amounts
2013
 
2012
 
2011
 
2010
 
2009
Sales Revenues
$
14,867

 
$
13,307

 
$
13,882

 
$
10,842

 
$
8,210

Gains (Losses) on Divestitures and Other, net
(286
)
 
104

 
85

 
142

 
133

Reversal of Accrual for DWRRA Dispute

 

 

 

 
657

Total Revenues and Other
14,581

 
13,411

 
13,967

 
10,984

 
9,000

Algeria Exceptional Profits Tax Settlement
33

 
(1,797
)
 

 

 

Deepwater Horizon Settlement and Related Costs
15

 
18

 
3,930

 
15

 

Operating Income (Loss)
3,333

 
3,727

 
(1,870
)
 
1,769

 
377

Tronox-related Contingent Loss
850

 
(250
)
 
250

 

 

Income (Loss)
941

 
2,445

 
(2,568
)
 
821

 
(103
)
Net Income (Loss) Attributable to Common Stockholders
801

 
2,391

 
(2,649
)
 
761

 
(135
)
Per Common Share (amounts attributable to common stockholders)
 
 
 
 
 
 
 
 
 
Net Income (Loss)—Basic
$
1.58

 
$
4.76

 
$
(5.32
)
 
$
1.53

 
$
(0.28
)
Net Income (Loss)—Diluted
$
1.58

 
$
4.74

 
$
(5.32
)
 
$
1.52

 
$
(0.28
)
Dividends
$
0.54

 
$
0.36

 
$
0.36

 
$
0.36

 
$
0.36

Average Number of Common Shares Outstanding—Basic
502

 
500

 
498

 
495

 
480

Average Number of Common Shares Outstanding—Diluted
505

 
502

 
498

 
497

 
480

Cash Provided by Operating Activities
8,888

 
8,339

 
2,505

 
5,247

 
3,926

Capital Expenditures
$
8,523

 
$
7,311

 
$
6,553

 
$
5,169

 
$
4,558

Current Portion of Long-term Debt
$
500

 
$

 
$
170

 
$
291

 
$

Long-term Debt
13,065

 
13,269

 
15,060

 
12,722

 
11,149

Midstream Subsidiary Note Payable to a Related Party

 

 

 

 
1,599

Total Debt
$
13,565

 
$
13,269

 
$
15,230

 
$
13,013

 
$
12,748

Total Stockholders’ Equity
21,857

 
20,629

 
18,105

 
20,684

 
19,928

Total Assets
$
55,781

 
$
52,589

 
$
51,779

 
$
51,559

 
$
50,123

Annual Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (Bcf)
968

 
913

 
852

 
829

 
809

Oil and Condensate (MMBbls)
91

 
86

 
79

 
74

 
68

Natural Gas Liquids (MMBbls)
33

 
30

 
27

 
23

 
17

Total (MMBOE)(2)
285

 
268

 
248

 
235

 
220

Average Daily Sales Volumes
 
 
 
 
 
 
 
 
 
Natural Gas (MMcf/d)
2,652

 
2,495

 
2,334

 
2,272

 
2,217

Oil and Condensate (MBbls/d)
248

 
233

 
217

 
201

 
187

Natural Gas Liquids (MBbls/d)
91

 
83

 
74

 
63

 
47

Total (MBOE/d)
781

 
732

 
680

 
643

 
604

Proved Reserves
 
 
 
 
 
 
 
 
 
Natural-Gas Reserves (Tcf)
9.2

 
8.3

 
8.4

 
8.1

 
7.8

Oil and Condensate Reserves (MMBbls)
851

 
767

 
771

 
749

 
733

Natural-Gas Liquids Reserves (MMBbls)
407

 
405

 
374

 
320

 
277

Total Proved Reserves (MMBOE)
2,792

 
2,560

 
2,539

 
2,422

 
2,304

Number of Employees
5,700

 
5,200

 
4,800

 
4,400

 
4,300

(1) 
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
(2) 
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
Table of Measures
 
 
Bcf—Billion cubic feet
 
MBbls/d—Thousand barrels per day
MMBbls—Million barrels
 
MBOE/d—Thousand barrels of oil equivalent per day
MMBOE—Million barrels of oil equivalent
 
Tcf—Trillion cubic feet
MMcf/d—Million cubic feet per day
 
 

52


Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko met or exceeded its key operational objectives in 2013. The Company increased sales volumes per day by approximately 7% over 2012 and added 528 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its deepwater exploration and appraisal drilling success with a 67% success rate in 2013. The Company ended 2013 with $3.7 billion of cash on hand, availability of its $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility), and access to credit and capital markets as needed. Management believes that the Company is positioned to continue to satisfy its operational objectives and capital commitments with cash on hand, available borrowing capacity, and cash flows from operations.

Mission and Strategy

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
 
explore in high-potential, proven basins